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

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

mike.israni@rspa.dot.gov,

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

(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

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 (§ 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

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.

•

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.

•

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.

•

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.

•

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 § 192.65 (Transportation of pipe), § 192.227 (Qualification of welders), § 192.241 (Inspection and test of welds), § 192.309 (Repair of steel pipe), § 192.315 (Wrinkle bend in steel pipe), § 192.319 (installation of pipe in a ditch, § 192.505 (Strength requirements for steel pipeline to operate at a hoop stress of 30% or more of SMYS), § 192.711 (General requirements for repair procedures), and § 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.

(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:

• 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.

• 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.

• Our analysis of the rupture in Carlsbad, New Mexico, highlighting the need for methods to assess internal corrosion in pipelines that are not piggable.

• Several Congressional mandates identify areas where the risk of a

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 important through past inspections and incident history. High impact inspections are carried out periodically for each operator and the results are documented using heavier reliance on narrative description rather than on acceptability check marks. We found that a system-wide approach rooted in evaluation of operator response to incidents and recognized performance issues is a more effective and, in most cases, more efficient means of evaluating pipeline integrity. As part of this approach, we evaluate how pipeline operators integrate information about their pipelines to identify sources of risk and to determine the best means of addressing risk. This experience is helping us develop detailed inspection guidelines to evaluate compliance with the requirements of this rule.

RSPA/OPS continues to meet with representatives of the gas pipeline industry, research institutions, State pipeline safety agencies and public interest groups, to gather the information needed to propose an integrity management program (IMP) rulemaking pertaining to gas operators. Since January 2000, RSPA/OPS has attended several meetings with representatives of the Interstate Natural Gas Association of America (INGAA), the American Gas Association (AGA), Battelle Memorial Institute, the Gas Technology Institute (GTI), Hartford Steam Boiler Inspection and Insurance Company, several gas pipeline operators and several representatives of State pipeline safety agencies. (

See

DOT Docket No. 7666 for summaries of the meetings.) We also have met separately with Western States Land Commissioners, National Governors Association, National League of Cities, National Council of State Legislators, Environmental Defense Fund, Public Interest Reform Group, and Working Group on Communities Right-To-Know.

On February 12-14, 2001, RSPA/OPS held a public meeting in Arlington, VA, on integrity management in high consequence areas for natural gas pipelines. At this meeting, reports on the status of industry and government activities on how to improve the integrity of gas pipelines were featured and meeting attendees participated in in-depth discussions on the integrity of gas pipelines. The reports can be found in the DOT docket (#7666) and the RSPA/OPS Web site under Initiatives/Pipeline Integrity Management Program/Gas Transmission Operators Rule.

At the public meeting, industry and State representatives presented their perspectives on a number of issues relating to integrity management.

Gas Advisory Committee Consideration

The Technical Pipeline Safety Standards Committee (TPSSC) is the Federal advisory committee charged with responsibility for advising on the technical feasibility, reasonableness, cost-effectiveness, and practicability of gas pipeline safety standards. The 15 member committee is comprised of individuals from industry, government, and the general public.

On February 7, 2001, RSPA/OPS briefed TPSSC members on gas integrity management program development. After canceling the September 13, 2001 meeting with TPSSC members, we sent all presentation materials and progress reports to committee members by mail for their comments or concerns. In May, 2002, we sent a document highlighting major issues in the gas integrity management rule to the TPSSC members. On July 18, 2002 the TPSSC met to review the Gas Transmission Pipeline HCA Rule and the cost-benefit analysis for the Gas Pipeline Integrity Management Program Rule. The committee voted unanimously to accept the cost benefit analysis as the basis for proceeding with the integrity management rule provided RSPA/OPS gives consideration to several issues. These issues and the related RSPA/OPS positions are summarized below.

The committee noted that the pipeline covered by the IMP Rule would include class 3 and 4 locations. RSPA's initial estimates of the total mileage in Class 3 and 4 locations turned out to be low because it was based on earlier data. Natural gas transmission pipeline operators were required to include in their 2001 annual reports the breakdown of their onshore pipeline mileage by class location, but this information was not available at the time the preliminary draft analysis discussed with the TPSSC was prepared.

RSPA/OPS has modified the cost benefit analysis to use the industry-reported mileage in classes 3 and 4. Because the industry regularly determines the classification of its lines, industry is in a better position than RSPA/OPS to estimate the amount of this mileage. RSPA/OPS is aware that there may be some discrepancy both between RSPA/OPS and operators and among operators as to how to calculate Class 3 locations. The variation in the manner in which class 3 locations are calculated involves the concept of clustering of buildings intended for

human occupancy in identifying pipe segments subject to the requirements associated with class 3 locations. The presence of individual isolated buildings within a sliding mile segment will count to raise the classification of the segment to Class 3. The question is whether the immediate area around the isolated building should be routinely classified as a Class 3 cluster. RSPA/OPS does not believe that these isolated buildings are commonly included as Class 3 clusters and does not intend this proposed rule to result in a change of existing practice in this regard.

The committee questioned whether RSPA/OPS intends to use the HCA definition as the starting point for identifying segments requiring additional integrity assurance measures, and to allow use of the potential impact zone to reduce the length of pipe subject to the IMP Rule. Committee members expressed concern both as to the appearance of leaving out some portions of HCAs and at the costs of including protections for areas which do not pose the same risks to population as other HCAs. With respect to the first point, the proposed rule includes all pipe segments within HCAs in the requirements for integrity management. However, if the segment is within a class 3 or class 4 location, but not within the potential impact zone, that is, the segment is in a moderate risk area, the proposed time for completing the baseline assessment will be extended to 13 years. RSPA/OPS expects that during the next seven to ten years, many companies will choose to make many segments in Class 3 locations piggable in their entirety and new technology will be available to minimize the cost associated with assessing these segments. However, an option RSPA/OPS is considering is to not require any assessment of segments located within a Moderate Risk Area, but, rather, to require enhanced preventive and mitigative measures on these segments. Our premise is that if houses are mostly clustered in one area of a Class 3 rectangle, a pipeline failure in an area beyond the cluster (

i.e.

, in the moderate risk area) may have little, if any, impact on the area with the cluster of homes. RSPA/OPS desires information on this option, and underlying assumptions, along with any cost information related to the proposed rule.

Committee members representing distribution companies expressed concern that they currently treat all their lines as Class 3 or 4 to avoid costly excavation and replacement of pipes when population densities increase. They are concerned that this decision will require them to perform segment identification for their lines. This would be an unnecessary cost if the distribution company intends to assess all transmission lines they operate. RSPA/OPS intends that operators choosing to classify their entire system as Class 3 or 4 without regard to population density will be allowed to do so without having to do segment identification according the provisions of the rule. However, these operators will not be relieved of requirements to evaluate the risk-based priority of segments in developing assessment schedules.

The committee expressed some concern that the approach being taken in the rule will lead to doubling protections on pipeline segments near population groups, since existing regulations already require lowering pipe stress levels in Class 3 and 4 locations. RSPA/OPS acknowledges this point, but notes that a significant consideration in our decision to allow a longer reassessment interval than that for liquid pipelines is that the thicker/stronger pipe in areas subject to the integrity management rule lengthens the time for time-dependent deterioration mechanisms to cause significant pipe deterioration.

Notice on Integrity Management Concepts and Hypotheses (Gas Transmission Pipelines)

On June 27, 2001, RSPA/OPS issued a notice of request for comments (66 FR 34318) that stated the objective in developing a rule on gas pipeline integrity management and described the scope and the elements of an eventual gas integrity management rule. We described seven elements that should be included in any integrity rule to fulfill our objectives. We used similar elements to those employed in structuring the liquid integrity management rules. Those seven elements were then elaborated upon through a set of hypotheses that we discussed in detail in the notice. The notice invited comment about these elements and hypotheses.

In addition, the notice summarized the areas where RSPA/OPS was seeking further information to support development of the proposed integrity management program rule for gas operators. The information needs were organized under the seven elements that we saw as essential to any integrity management program rule, and under two other categories where additional information was needed to evaluate the effect of an integrity management rulemaking on costs and gas supply, both seasonally and regionally.

Electronic Discussion Forum

RSPA/OPS also used an electronic discussion forum from June 27 through August 13, 2001, titled “More Information Needed on Gas Integrity Management Program” to help promote discussion of these issues. The electronic forum listed all the areas where we had asked for comment so that commenters could easily focus on those areas of interest to them. A transcript of the electronic discussion forum is included in the docket.

Comments to Notice on Integrity Management Concepts and Hypotheses (Gas Transmission Pipelines)

Comments to the docket were provided by one state, five industry associations (including one association of industrial gas consumers), sixteen companies or groups of companies that operate gas pipelines, one company that operates hazardous liquid pipelines, and one company that builds pipeline bridges.

Comments on all elements envisioned for the gas pipeline integrity management concept, except the element defining high consequence areas, are summarized below. Comments on the HCA element are discussed in a separate proposed rule published in the

Federal Register

on January 9, 2002 (67 FR 1108). RSPA/OPS recently finalized the definition of HCAs (67 FR 50824; August 6, 2002).

Scope

In the notice we indicated that we are considering applying the gas integrity management concept to all gas transmission lines and support equipment, including lines transporting petroleum gas, hydrogen, and other gas products covered under part 192.

The American Gas Association (AGA) and American Public Gas Association (APGA) commented that the integrity rule should apply to gas transmission pipelines operating at or above a hoop stress level of 20% SMYS. These commenters said the rule should also not include pipelines in commercially navigable waterways or environmentally sensitive areas because Congress did not direct this coverage. They also said RSPA/OPS should give special consideration to pipelines operating at a hoop stress between 20% and 30% SMYS. Because these lines fail by leak rather than by rupture, different assurance methods should be considered.

This proposed rule covers gas transmission pipelines, including pipelines transporting petroleum gas, hydrogen, and other gas products

covered under Part 192 in the high consequence areas. The definition for a transmission line is found in section § 192.3. This proposed rule does not apply to gas gathering lines or to gas distribution lines.

Performance-Based Option

Numerous companies argued that we should allow a performance-based option because a purely prescriptive rule would not allow companies to effectively and cost beneficially address the unique features of their systems.

We are proposing a minimum set of criteria for an operator to qualify for a performance-based option. Operators who satisfy this minimum set of criteria will be eligible to deviate from certain requirements—the time frame for remediating anomalies identified during the assessment, the conditions for using direct assessment as a primary assessment method and the reassessment interval (for example, the reassessment interval for on a segment assessed by the DA method could be extended to ten years). However, even if an extended interval were allowed, the operator would still have to conduct a confirmatory direct assessment in the seventh year of the interval. We are incorporating these performance-based considerations because RSPA/OPS recognizes that improving pipeline integrity can only be accomplished through operators improving their understanding of the condition of their piping and taking appropriate action based on this understanding. Operators who excel in these aspects of integrity management should have limited flexibility in making key integrity management decisions.

The proposed conditions an operator would have to satisfy before being allowed to deviate from some of the program's requirements include—

1. The operator must have completed a baseline assessment of all covered segments and at least one other assessment. Problems identified in the second assessment must be remediated. Also the results and insights from the second assessment must be incorporated into the operator's risk model.

2. An operator must also demonstrate that it has an exceptional integrity management program. To demonstrate this an operator must show that its program meets the performance-based requirements of ASME/ANSI B31.8S, has a history of measurable performance improvement, and includes, at minimum:

(1) A documented state-of-the-art risk analysis process;

(2) Complete documentation of all risk factor data used to support the program;

(3) A state-of-the-art data integration process;

(4) A process that explicitly develops lessons learned from assessment of covered pipe segments and applies these lessons to pipe segments not covered by the Rule;

(5) A process for evaluating all incidents, including their causes, within the operator's sector of the pipeline industry for implications both to the integrity of the operator's pipelines and to its integrity management program;

(6) A documented performance history that confirms the continuing performance improvement realized under the performance-based program; and

(7) The extensive set of performance measures documented in the operator's performance plan (ASME B31.8S, Section 9) are accessible to state and federal regulators. These measures would be updated by the operator on a frequency consistent with its performance plan.

Define the Areas of Potentially High Consequence

In the FR notice of June 27, 2001, we said the first element of the integrity management concept involves defining the areas where the potential consequences of a gas pipeline accident may be significant or may do considerable harm to people and their property. In a rule issued on August 6, 2002, we defined these high consequence areas. (67 FR 50824). The definition of high consequence areas (HCAs) includes: (a) Current Class 3 and 4 Locations; (b) pipe segments in the area that would be impacted by a potential pipeline rupture where there is a facility housing people who are confined, have impaired mobility or are difficult to evacuate (

e.g.

, hospital, church, school, prison, day care facility, retirement facility; and (c) pipe segments near areas where a specified number of people congregate on a specified number of days per year (

e.g.

, camping grounds, outdoor recreational facility). The defined areas were those that would be impacted by a potential pipeline rupture, 300, 660 or 1000 feet from the pipeline depending on the diameter and operating pressure of the pipeline.

RSPA/OPS Decision on Using Potential Impact Radius in the HCAs

This proposed rule presents requirements to improve the integrity of pipelines located in areas of potentially high consequences. As discussed earlier, this proposed rule expands the current HCA definition, by presenting requirements to improve the integrity of pipelines located near people living at distances greater than 660 feet from large high pressure pipelines. This proposed expansion is based on the need to provide the same level of added protection to population groups, as the HCA definition provides to facilities that house people who are confined, difficult to evacuate, or of impaired mobility, and to areas where people congregate. The number of buildings intended for human occupancy within the potential impact circle is discussed under the proposed rule section of this preamble. The basis for identifying the physical area where concentrations of people are located so additional protective measures can be applied is discussed below.

The Size of the Zone That Could Be Impacted by a Gas Pipeline Rupture and Explosion

Since existing regulations provide a basic level of protection, the primary focus of the integrity management rulemaking is on reducing the likelihood of a gas release in areas where the potential consequences are greatest. The HCA definition includes areas where a pipeline lies within 660 feet of a building housing people who would be difficult to evacuate (

e.g.

, hospital, school, retirement facility) or where 20 or more people congregate at least 50 days in any 12-month period. The area is expanded to 1000 feet if the pipeline is greater than 30 inches in diameter and operates at pressures greater than 1000 psig. In addition, in this proposed rule we are expanding the HCA definition by proposing to include a new component of high concentration of buildings (as discussed above) intended for human occupancy beyond 660 feet. The 1000-foot limit was based on a mathematical model (developed by C-FER under INGAA funding) that describes a heat affected zone following a pipeline rupture. This heat affected zone is bounded by a “potential impact radius.” This model includes numerous assumptions on the size and orientation of the pipe rupture, the physical behavior of the jet issuing from a ruptured pipeline (the pipeline is assumed to fail by a double-ended rupture), the time of ignition of the gas jet, the rate of decay in the flow of gas issuing from the pipeline, the dominant heat transfer mode, and the criterion for determining the radius within which physical damage results from the heat from a burning gas jet. Given the complexity of this analysis and the scope of assumptions needed, the only

way to validate the adequacy of the resulting mathematical relationship was to compare its predictions of potential impact radius with actual observed burn zone following historic gas pipeline ruptures. This comparison was carried out using the C-FER model which successfully predicted the radius of the burn zone surrounding ruptured gas pipelines.

Incorporating Mathematical Formulation Describing the Heat Affected Zone Into the Rule

We are proposing to require operators to calculate the potential impact radius within the HCA. This potential impact radius would be used to identify the areas within HCAs where the consequences of a rupture would be greatest. An operator would first focus any additional integrity measures on concentrations of people or hard to evacuate buildings or areas where people congregate within the impact radius, then on the rest of the HCA. Using more realistic criteria to define areas where an operator would focus additional integrity assurance measures will allow an operator to better allocate its resources toward areas that need the greatest protection. This approach will particularly benefit operators of small-diameter, low pressure pipelines, where the range of impact following a potential rupture would be small. This approach would also benefit the public because operators of very large diameter, very high pressure pipelines would have an increased impact radius to consider for evaluating where additional integrity assurance measures are required.

Identify and Evaluate the Threats to Pipeline Integrity in Each Area of Potentially High Consequences

The second element of integrity management discussed in the FR notice of June 27, 2001, involves identification of potential threats to the pipeline. In the notice we mentioned one approach suggested by industry in our past discussions was to divide potential threats to pipeline integrity into three categories: Time dependent (including internal corrosion, external corrosion, and stress corrosion cracking); static or resident (including defects introduced during fabrication of the pipe or construction of the pipeline); and time-independent (including third party damage and outside force damage; this threat category was called “random” in the FR notice). These three categories are adopted here primarily to focus resource allocation decisions on useful strategies to improve integrity (

e.g.

, integrity management for the “time-independent” category clearly must incorporate significant preventive measures), but do not eliminate the need for operators to consider all major threats to pipeline integrity. In addition, we said that human error can influence any or all of these threats and therefore must be considered as a potential contributing factor to each threat.

For the gas pipeline IMP proposed rule, we decided to propose that the operator make a threat-by-threat analysis of the entire pipeline. Such an analysis will require identification and evaluation of the significance of threats to pipeline integrity, which must necessarily involve the integration of numerous risk factors. Such risk factors include, but are not limited to, pipe characteristics (

e.g.

, wall thickness, coating material and coating condition; pipe toughness; pipe strength; pipe fabrication technique; pipe elevation profile); internal and external environmental factors (

e.g.

, soil moisture content and acidity, gas operating temperature and moisture content); operating and leak history (

e.g.

, pipe failure history, past upset conditions that have introduced moisture into the gas); land use (

e.g.

, active farming, commercial construction, residential construction); protection history (

e.g.

, corrosion protection data, history of third party hits and near misses, effectiveness of local One Call systems); and the degree of certainty about the current condition of the pipeline (

e.g.

, age of the pipe, completeness of integrity-related records, available inspection data).

The RSPA/OPS data on causes of gas transmission pipeline accidents (

i.e.

, threats to the pipeline) show that between 1990 and1999, there were total 777 reported accidents. The causes of these accidents are broken down as follows:

—319 (41%) were due to outside force damage (30% third party, 11% earth quakes/floods, and other outside forces);

—173 (22%) were due to corrosion (105 (14%) internal, 67 (9%) external);

—119 (15%) were due to construction and material defects; and

—166 (21%) were due to other causes.

The data indicates that the two greatest threats to a pipeline are from outside force damage (41%), and corrosion (22%). Our data also shows there are more failures from internal corrosion than from external corrosion. The internal corrosion is caused by moisture and acidity present in the gas transmission lines at low or near low points. The rupture of the gas transmission pipeline in Carlsbad, New Mexico resulted from internal corrosion. Because corrosion can occur either internally or externally, it essential that gas pipeline operators consider both threats.

We believe this threat-by-threat analysis is necessary not only because it will require the operator to assemble and use a comprehensive set of risk factor data to identify the presence of potential threats, but also because it will support determination of the assessment approach or approaches needed to characterize the significance of these threats.

Our concept of integrity management also includes the following hypotheses: (1) Pipeline segments having threats that represent higher risks should generally be assessed sooner than those with threats that represent lower risk and (2) Pipelines that operate at a stress level less than 30% SMYS fail differently (

i.e.

, leak rather than rupture) from those operating at higher stress, therefore, different integrity assurance techniques may be appropriate. We have discussed this issue elsewhere in this document and have requested comment.

Comments on RSPA/OPS Hypotheses

INGAA provided many comments on this hypothesis. The primary source of information referenced by INGAA was the technical reports prepared by their contractors during the eighteen month interaction among INGAA, RSPA/OPS and the states on technical issues, and the consensus standards currently in preparation. These reports are available in the Docket. Comments from INGAA included the following:

INGAA offered the opinion that laws should be enacted to support strong One-Call Programs. It also pointed out that seam cracking in pre-1970 ERW piping has been observed only in piping from certain manufacturers. Not all pre-1970 pipe has that problem.

INGAA also expressed the opinion that soil erosion is not a significant direct threat to pipeline integrity, however it may lead to increased importance of third-party damage when it results in shallow cover. In addition, it noted that some materials and construction techniques are more susceptible to damage from massive soil movement than others, and that this issue is treated more completely in ASME B31.8 S which was under development at the time of the comment, but has subsequently been issued.

On the subject of operator error, INGAA noted that performance measures are needed to evaluate the importance of this threat to pipeline integrity. Lessons learned from observed operator errors should then be

translated into improvements in operating procedures and communicated among operators. Effective management of change and quality control/assurance programs will also reduce the likelihood of operator error contributing to pipeline failure. Consensus standards were under development at the time of the INGAA response on qualification and certification of individuals involved in analyzing in-line inspection (ILI) results. INGAA expressed concern about the increased demand for ILI services potentially leading to lengthened time requirements by ILI vendors to produce assessment reports, with related implications to the ability of the industry to meet repair and mitigation requirements.

On the subject of gas storage field pipeline systems, INGAA stated that those in high consequence areas should be treated in the same way as natural gas transmission pipelines.

AGA/APGA also noted that the process for managing pipeline integrity should not be affected by the operating stress level. Lower stress pipeline operators should be required to develop and follow integrity management programs having the same elements as operators of higher stress pipelines. Only the tools and techniques used to assess the pipeline and the reassessment intervals should require customization.

NYGAS indicated that it is important to ensure that staff conducting and analyzing results from assessment of pipeline integrity be qualified. In the cases where the operator qualification rule does not apply, operators must ensure proper qualification of these people, and monitor performance measures designed to reveal potential problems with personnel qualification. NISource commented that there needs to be a clear means of identifying a threat as “significant.”

In aggregate these comments are consistent with the RSPA/OPS decisions to require threat-by-threat analysis of the pipelines and to acknowledge the differences in failure mode for pipe operating at stress levels below 30% SMYS by imposing somewhat different requirements for these lines.

Select Appropriate Assessment Technologies

The third element of integrity management discussed in the June 27, 2001 FR notice, involves identification of potential threats to the pipeline in areas of concern. In the notice we used the following hypotheses to support selection of the assessment technologies best suited to effectively determine the susceptibility to failure of each pipe segment that could affect an area of potentially high consequences:

• An integrity baseline needs to be established for all pipe segments that could affect an area of potentially high consequences. An operator will need to evaluate the entire range of threats to each pipeline segment's integrity by analyzing all available information about the pipeline segment and consequences of a failure on a high consequence area. Based on the type of threat or threats facing a pipeline segment, an operator will choose an appropriate assessment method or methods to assess (

i.e.

, inspect or test) each segment to determine potential problems.

• Time dependent threats will require periodic inspection to characterize changes in their significance.

• Acceptable technologies for assessing integrity include in-line inspection, pressure testing and direct assessment. None of these technologies, individually, is fully capable of characterizing all potential threats to pipeline integrity. (

Note:

RSPA/OPS is co-sponsoring with industry an evaluation of direct assessment technology to determine the conditions under which direct assessment is effective in assessing external corrosion. The effectiveness of direct assessment in assessing other threats (

e.g.

, internal corrosion, stress corrosion cracking) is also under evaluation for validation.

• Unless the operator demonstrates by evaluation that they are not a threat to the integrity of a pipe segment, static threats will require pressure testing at some time during the life of the pipeline. If significant cyclic stress, such as that caused by large pressure fluctuations, is present, then pressure testing, or an equivalent technology, will be required periodically throughout the life of the pipeline. If operating conditions for a pipeline with potential seam problems from manufacture are to be changed significantly, then the pipeline must by pressure tested prior to the change of operation.

• Time-independent threats will require the use of two parallel integrity management approaches. The vast majority (over 90%) of ruptures caused by time-independent threats occur at the time that the activity takes place (

e.g.

, when the excavator hits the pipeline), and not at some later time. Therefore, the use of risk management practices (or technologies) to prevent damage or to immediately identify the potential for damage would be more effective than looking for evidence of past damage. Secondly, since some time-independent threats do not result in immediate pipeline rupture, technologies that look for evidence of past damage after the threat has occurred should be focused in areas where delayed failure is most likely.

• Threats related to human error will be addressed largely, but not completely, through the new Operator Qualification Rule. The integrity management rule will require operators to evaluate the impact of operator error on the primary threats to pipeline integrity.

Comments

INGAA summarized the capability of pipeline in Classes 3 and 4 for using internal inspection tools as follows: 24.4% is easily piggable, 25.3% can be easily made piggable, 45.9% would be very costly to make piggable, and 4.4% cannot be pigged.

INGAA provided a set of examples of situations and conditions which may adversely impact the accuracy of results from the indirect processes used in external corrosion direct assessment. These include:

• Rocky backfill with little or no soil around the pipe.

• Very dry, cracked soil where little soil contact is made with the pipe.

• High-dielectric coatings (such as polyethylene tape) that have the propensity to shield the pipe from the flow of cathodic protection current, where no orifices to the soil/water interface are present.

• Resolution and sensitivity of survey equipment.

• Correct selection of the proper diagnostic tool matched to the suspected integrity threat.

• Bare or unprotected pipelines.

INGAA stated that data from the ongoing external corrosion direct assessment process development effort will need to be combined with data from application of the process over time to allow statistical analysis describing reasonable confidence bands.

A preliminary model was presented by INGAA that describes the use of the four step direct assessment process in assessing a pipeline for SCC. This description relies heavily on the assembly and integration of risk factor data that could indicate the possible presence of SCC. These risk factor data are presented in the appendix of ASME B31.8S.

AGA/APGA commented that not all pipelines should be required to be pressure tested for manufacturing or construction defects at sometime during their lifetime. For example, a pipeline should not require pressure testing if it has not experienced leaks during its lifetime. This argument assumes that

operation of the line is not subjected to pressure cycling of sufficient magnitude and frequency to produce growth of existing cracks. AGA/APGA does support existing requirements to pressure test all new pipelines before operation.

AGA/APGA commented that pipelines operating at hoop stress levels between 20% and 30% SMYS, where the failure mode is leakage not rupture, should be allowed to use assurance technologies, including mitigation measures, other than pigging, pressure testing and direct assessment. An AGA paper, dated April 26, 2001, on “Integrity Management for Low Stress Pipelines” (copy filed in the Docket) further expands on these alternate technologies and mitigation measures.

AGA/APGA indicated that direct assessment is: (a) Currently being validated and imbedded in a NACE consensus standard; (b) being evaluated for application to bare pipelines; and (c) should not be defined in an overly prescriptive manner.

AGA/APGA summarized the strengths and limitations of pressure testing and in-line inspection. They noted that all forms of integrity testing will have some impact on gas supply reliability, and that severe constraints or cut-off will be required with pressure testing.

The following table was developed by AGA/APGA on miles of member companies with various assessment capability.

Company membership

Miles in

classes 3&4

Currently piggable

(in percent)

Temp

conversion for

pigging

(in percent)

Extensive

retrofit for

pigging

1

(in percent)

Cannot be pigged

2

(in percent)

AGA

13,500

12

10

43

35

APGA

3,000

13

41

46

1

Retrofit costs range from $5,000 to $250,000 per mile.

2

Costs range estimated to be from $1M to $8M per mile to replace pipe (in urban areas).

The Florida Public Service Commission recommended that both magnetic flux leakage (MFL) pigging and pressure testing be carried out at intervals of five to seven years, not to exceed ten years. They also indicated that Florida gas pipes are typically less than twelve inches in diameter and therefore should be inspected at ten year intervals.

Pacific Gas & Electric Company (PG&E) also indicated that increased leak patrol frequency should be used to minimize the threat of leakage from pipe segments operating at low hoop stress (e.g., less than 30% SMYS).

PG&E commented that pipe segments operating at low stress levels should not be required to conduct a pressure test once in the pipeline life, but rather operating history should be used to validate material strength. They also noted they found direct assessment to be a good tool to identify residual third party damage.

PG&E noted that they do consider erosion to be one of the Outside Forces that needs to be considered, and they conduct annual erosion surveys to support mitigative action where erosion is identified.

PG&E summarized the reasons why some of its pipe is not piggable because of the presence of one or more of the following: telescopic construction, random diameter construction, sharp radius bends, and less than full opening valves.

NYGAS commented that local distribution company (LDC) transmission lines are typically sole source lines and are closely coupled to the distribution system. These facts will greatly increase the cost and impact on customer supply of pigging and pressure testing.

NYGAS further commented, with supporting analysis from Kiefner and Associates, that under typical cyclic loading conditions, the fatigue life of a gas pipeline operating at stresses of 72% SMYS is 100 to 400 times longer than hazardous liquid pipelines, and that lowering the operating stress level to below 30% SMYS will increase this factor to between 900 and 3600. Therefore, pressure testing at some time during the life of a low stress pipe should not be required. NYGAS also noted that experience has demonstrated ILI technologies do not perform satisfactorily at pressures below 400 psi.

NISource commented that it does not believe an integrity baseline needs to be established for all pipe segments. In particular, low stress pipelines have a “baseline” established through application of the exiting regulations and monitoring for evidence of leaks. Current practices identify the physical conditions which increase the potential for gas accumulation resulting from a leak, and the presence of these conditions leads to increased monitoring.

The Association of Texas Intrastate Natural Gas Pipelines commented that it would be useful if the rule spelled out the process by which new assessment technologies would be approved by RSPA/OPS.

Several operators expressed concern about their ability to de-water a pipe segment that is not piggable following a pressure test. Inability to de-water would lead to increased likelihood of internal corrosion. This fact supports the advisability of allowing direct assessment as an alternative assessment technology.

Comments from the public and the pipeline industry generally supported RSPA/OPS's approach in developing this proposed rule. The commenters generally agreed that the proposed rule should include: (1) A threat-by-threat analysis of each pipeline segment; (2) at least one pressure test during the life of a pipeline to characterize its susceptibility to material and construction defects, unless the operator can justify why a pressure test is not necessary; (3) periodic assessment of each pipeline segment for third party damage (denting), unless the operator can justify why such assessment is not necessary. A decision to forgo periodic assessment must address loading conditions (

e.g.

, cyclic loading), pipe susceptibility to delayed failure (

e.g.

, at Edison, NJ), and pipe exposure to potential third party damage; and (4) a description of how to apply direct assessment, including the conditions under which it is not appropriate, and conservative criteria for pipe excavation for direct examination.

Baseline Assessment and Remediation

The fourth element of integrity management discussed in the June 27, 2001 FR notice, related to the baseline assessment and remediation time frame. To determine time frames to conduct a baseline integrity assessment and to complete remediation following an assessment using an approach that prioritizes pipeline segments based on risk, we used the following hypotheses:

• The time frame for conducting the baseline assessment should be based on a graded or tiered approach where pipeline segments are prioritized for

assessment according to the level of risk they pose. Thus, highest risk segments would be scheduled for assessment first, lowest risk last. A schedule for taking remedial action on the pipeline segment after the assessment would also be based on risk factors.

• The time frame for conducting the baseline assessment should, among other factors, consider the impact on gas supply to residents. This could also be a factor in determining if a variance from the required time frame is warranted.

• The sequence in which the segments are prioritized for assessment should be determined by considering information such as, how much pipe is in areas of potentially high consequences, which of these pipe segments represent the highest risk, which threats for these segments represent significant risks, how much time will be needed to develop the infrastructure to perform the required assessments (

e.g.

, validate the required assessment technologies, develop consensus standards for the application of these technologies, expand the industry capability to deploy and effectively use these technologies to assess pipeline integrity). If the assessment finds potential problems, the schedule for making the repairs would also be based on risk factors.

Comments on Baseline Assessment and Remediation

INGAA commented that several practical factors will influence the time frame for completing a baseline assessment. These include time for: (a) Program development (suggested, 18 months); (b) assembly and analysis of risk factor data (suggested, 18 months); (c) limitations on the availability of assessment tools from vendors; and (d) potential detrimental impacts on supply to critical customers. Given these factors, INGAA estimated that the shortest time for completing baseline assessments would be about ten (10) years after promulgation of the rule. Even if ten years were allowed, INGAA estimated in an early analysis that the economic cost to customers over the ten year baseline assessment period would range from $3.9 to $6.1 billion.

INGAA reported that repair time frames should consider the results of a recently completed analysis by Kiefner and Associates in which the allowable repair time is related to the calculated (or pressure tested) safe operating pressure. Three categories were defined: (a) Segments with a safe operating pressure of 110% of MAOP or less should be repaired immediately, (b) those with a safe operating pressure of less than 139% of MAOP but above 110% of MAOP should be repaired on a defined schedule, and (c) those with a with a safe operating pressure of greater than 139% of MAOP require interval monitoring. Interval monitoring implies reassessment on a ten year interval to assure that sub-critical anomalies will not fail during that time.

AGA/APGA commented that factors considered in determining the time frame for the baseline assessment should include scope of the rule (

i.e.

, only above 20% SMYS), availability of pigging equipment, availability of properly qualified people, and the impact on the gas supply. Considering these factors, they believe that a minimum of ten (10) years should be allowed to complete the baseline assessment, with half of the pipeline completed within five years and variances available for those unable to meet the schedule.

AGA/APGA agree that repairs should be scheduled to reflect the seriousness of the defect. However, engineering distinctions among the gas pipeline systems dictate that the highly prescriptive approach to repair requirements in the Large Liquid Pipeline Operator Rule is inappropriate. RSPA/OPS should consider the guidance on repair and mitigation being developed by the ASME/ANSI B31.8S.

The Association of Texas Intrastate Natural Gas Pipelines commented that it would be useful if RSPA/OPS included a special provision for assessment interval for new pipe segments or replaced pipe segments.

PG&E supported a ten year baseline assessment period. PG&E commented that practical considerations (

e.g.

, long-lead materials, construction difficulties, and economies of scale) should be considered in developing assessment schedules to ensure that economic efficiencies can be realized while satisfying the intent of any rule that the highest risk segments be assessed first.

Enron commented that a ten year baseline assessment interval seems appropriate, and that reassessment in class 1 and 2 locations should be on the same interval, but that reassessment in Class 3 and 4 locations should be on a fifteen year interval. Enron also strongly urged RSPA/OPS to allow operators to carry out repairs consistently with existing procedures rather than imposing a prescriptive repair time frame.

Baseline assessment factors: The recent pipeline safety law (Pipeline Safety Improvement Act of 2002) requires that an operator conduct a baseline assessment not later than ten years from the date the law is enacted. This time frame is consistent with the baseline time frame we were considering based on our study of the relevant influencing factors. The law further requires that at least 50% of facilities in high consequence areas must be assessed no later than 5 years from enactment. This requirement is also consistent with what we were considering. Our proposal incorporates these requirements.

The factors we considered relevant to establishing the time frame for an operator to conduct the baseline assessment include:

• The desire to establish an integrity baseline for all affected pipe segments as quickly as possible.

• The ability of the gas pipeline service industry to expand both its assessment equipment, and, of equal importance, its qualified technical staff.

• The ability of the pipeline industry to gather and integrate risk factor data necessary to characterize the significance of threats to pipe integrity.

• The time required for the pipeline industry to modify its lines to accommodate in-line inspection equipment.

• The impact on critical gas supply and the associated impact on the price of natural gas. INGAA recently funded a study to evaluate the supply and consumer cost impacts associated with various baseline assessment intervals. The study did not include the actual cost of modifying the pipeline to accommodate ILI equipment, and the study assumed operators would perfectly coordinate their assessment activities to minimize the impact on customers. The study included supply impacts resulting from modifying a pipeline to accept ILI equipment and from the assessment activity itself. Supply impacts associated with remediation or repair of defects discovered during the assessment were not included. The study included differences in the supply impacts associated with different assessment technologies.

The INGAA analysis found that consumer cost impact was more significant with short baseline assessment periods than with longer times. The cost impacts in the current analysis were estimated to be $7.2B for a 14-year baseline period, $13.1B for a 10-year baseline period, and $20.1B for a 5-year baseline period. Although not quantifiable in the model, the potential for critical supply interruptions, resulting from the need to perform assessments during high demand periods and the increased difficulty of coordinating assessments on lines

feeding the same customers, increases as the baseline period decreases.

•

Class location requirements.

The gas pipeline safety regulations have class location requirements that the liquid regulations do not. As population increases near a pipeline, the class location requirements require establishment of an additional margin of safety. To comply with class location requirements, gas transmission pipeline operators maintain data on the number of residences and other buildings located near their pipelines. Based on threshold levels of near-by dwellings and buildings, operators are required to constrain the maximum stress level in the pipeline to successively lower levels as the number of dwellings increases. When a class location changes to a higher class, an operator must reduce the stress level on the line either by reducing pressure, or in some cases, by replacing the pipe. If an operator replaces the pipe, an operator may use thicker walled or higher strength pipe to ensure that the capacity of the pipeline is not reduced.

The result is that, while gas pipelines in locations of potentially high consequence typically operate at stress levels of 40% SMYS (Class 4) or 50% SMYS (Class 3), corresponding liquid pipelines typically operate at 72% SMYS. A higher stress is typically associated with thinner walled piping or a smaller margin to failure for a given defect size. Therefore, time dependent threats such as external corrosion, which occur at a rate dependent on factors such as soil chemistry, coating integrity and cathodic protection effectiveness, have less wall thickness to penetrate before a critical defect depth is reached and the pipeline ruptures. The lower stress levels and thicker walls of gas pipelines imply that, other factors being equal, corrosion would take longer to penetrate to a critical depth.

These factors support a baseline assessment interval of ten years for operators using in-line-assessment or pressure testing, with at least 50% of the covered segments (the higher risk segments) being assessed within five years. However, for operators using direct assessment as the primary assessment technology, we are proposing a baseline assessment interval of seven years to account for the early state of development of these processes and to allow time to develop data on their validity. The highest risk half of the segments being assessed by direct assessment will, however, be assessed during the first four of these seven years. This proposal is consistent with The Pipeline Safety Improvement Act of 2002 (HR 3609, signed into law Dec. 17, 2002) which provides for a baseline assessment “not later than 10 years” after the law's enactment, with 50 % having to be assessed “not later than 5 years” after enactment. As noted earlier, RSPA/OPS is proposing to require operators choosing direct assessment technologies to undertake extra excavations and direct examinations during the period while validation is continuing.

Our proposal on the baseline assessment also allows for an assessment conducted five years before the law's enactment or date the final rule is effective, whichever is earlier, as a baseline assessment if it satisfies the specified assessment criteria. If an operator chooses this option, under our proposal, the operator would then have to begin complying with the requirements for reassessment of the segment.

Identify and Implement Additional Preventive and Mitigative Measures

The fifth element of integrity management discussed in the June 27, 2001, FR notice, related to identification and implementation of additional preventive and mitigative measures. We used the following hypotheses in the notice:

• Assuring a pipeline's integrity requires more than simple periodic inspection of the pipe. Most threats, including passive threats such as third party damage, require active management to prevent challenges to integrity. Therefore, active integrity management practices are necessary. Some operators already go beyond the current pipeline safety regulations by implementing integrity management practices such as ground displacement surveys, soil corrosivity analysis, gas sampling and sampling and analysis of liquid removed from pipelines at low points.

• Preventive and mitigative measures include conducting a risk analysis of the pipeline segment to identify additional actions to enhance public safety. Such actions may include, damage prevention practices, better monitoring of cathodic protection, establishing shorter inspection intervals, and installing Remote Control Valves (RCVs) or Automatic Shut-Off Valves (ASVs) on pipeline segments. Some operators, particularly hydrogen pipeline operators, have voluntarily installed ASVs on their pipelines closer together than required as a mitigative measure.

Comments

INGAA described a general process used by operators to make decisions on adding risk control or mitigation features beyond those required by regulation. The process involves establishment of a budget for additional safety enhancements and allocating that budget based on some structured form of risk assessment process, including feedback on potential risks from people in the field.

The conclusions of two INGAA-sponsored reports on the value of RCVs and ASVs include:

1. Neither RCVs nor ASVs will reduce fatalities or injuries to the public.

2. Neither control valve system will significantly reduce property damage.

3. RCVs and ASVs increase the likelihood of service disruption (RCVs in particular).

4. RCVs and ASVs can reduce the amount of product lost.

5. Costs for RCVs or ASVs outweigh measurable benefits.

According to INGAA, the only substantive benefit of RCVs and ASVs is that they result in faster valve closure following an incident.

Air Products and chemicals, an operator of 700 miles of pipeline for transporting industrial gas such as hydrogen, currently uses twenty-five excess flow valves along the 150 miles of pipe it operates in what it considers to be high consequence areas. These valves were added as a result of its risk analysis process.

GPTC noted that it expects ANSI to publish a technical report describing industry practices and ideas for managing integrity this Fall and requests that RSPA/OPS consider information in this document as part of its Rulemaking effort.

Remote Control Valves (RCVs)

In response to a Congressional mandate following the March 1994 gas transmission pipeline failure at Edison, NJ (Accountable Pipeline Safety and Partnership Act of 1996; codified at 49 U.S.C. 60102(j)), RSPA/OPS surveyed and assessed the effectiveness of remotely controlled valves (RCVs) on interstate natural gas pipelines. We examined the technical and economic feasibility of RCVs to rapidly shut down a gas transmission pipeline after a rupture.

RSPA/OPS conducted a public meeting in October 1997 to gather data on the technical and economic feasibility of installing RCVs. There was general agreement by the meeting participants, and in written comments following the meeting (contained in Docket No. RSPA-97-2879), that RCVs are technically feasible, but are not economically justifiable from a cost-benefit standpoint. This result is because most casualties and property

damage occur within ten minutes after a pipeline rupture. Although an RCV can be closed within two or three minutes to isolate a pipeline section, a safe condition is not achieved until the gas between valves has either escaped or burned off, which is almost always a longer time period than ten minutes.

These findings from the public meeting were reinforced by the results of a Gas Research Institute (GRI) study of 80 gas transmission pipeline failures over a twelve year period which showed that quick closure of valves could have prevented only one injury out of a total of 28 fatalities and 116 injuries.

We closely monitored a one year field evaluation of 90 RCVs installed by Texas Eastern Transmission Company, mostly in New Jersey and Pennsylvania. The RCVs' reliability was demonstrated by the fact that there were no unplanned closures of the valves during the year and, of the 200 plus valve cycles executed remotely, the valves closed 100 percent of the time on the first attempt.

RSPA/OPS completed a study in September 1999 titled “Remotely Controlled Valves on Interstate Natural Gas Pipelines,” available in Docket RSPA-97-2879. The study shows that installing and using RCVs can effectively limit the time required to isolate ruptured pipe sections when manual valve operation is not feasible, thereby minimizing the consequences of certain gas pipeline ruptures. The study supports RCVs' effectiveness, technical feasibility, and potential for reducing risk. The study indicates that the quantifiable costs of RCV installations would almost always exceed the benefits.

However, we believe that significant risk exists at some locations as long as gas is being supplied to a rupture site, and operators currently lack the ability to quickly close existing manual valves. Any fire would be of greater intensity, and would have greater potential for damaging surrounding infrastructure, if the fire were replenished with gas over a protracted period of time. Therefore, we held another public meeting in November 1999 to consider the need for a rulemaking to establish time limits for isolating ruptured sections of gas transmission pipelines. No new data were presented at the hearing to establish critical locations where RCVs should be installed.

Consistent with the hypotheses prepared earlier, RSPA/OPS decided to incorporate a provision in the rule requiring operators to evaluate the potential value of a spectrum of preventive and mitigative measures, and to act on the results of this evaluation. So that RSPA/OPS may understand the basis on which operator decisions are made, we will require operators to document their decision processes and decision criteria for RSPA/OPS review during inspections. Measures to be considered by operators will include those practices set forth in ASME B31.8S, as well as use of RCVs and ASVs. While these two types of valves have been analyzed generically for gas pipelines, RSPA/OPS believes that each operator should consider the merits of installing these mitigative measures at critical locations on their pipelines and make installation decisions based on pipeline-specific and site-specific evaluations.

A Process for Continual Evaluation and Assessment To Maintain a Pipeline's Integrity

The sixth element of integrity management discussed in the June 27, 2001 FR notice, related to the process for continual evaluation and assessment of pipelines to maintain their integrity. We used the following hypothesis in the notice:

Operators should continually evaluate and reassess at the specified interval each pipeline segment that could affect an area of potentially high consequence using a risk-based approach. The evaluation considers the information the operator has about the entire pipeline to determine what might be relevant to the pipeline segment.

• Managing a pipeline's integrity requires periodic reassessment of the pipeline. The time frame appropriate for this reassessment depends on numerous factors. In the current class location change regulation, gas pipeline operators are required to replace pipe segments with thicker-walled or stronger pipe (or to decrease pressure) as the near-by population increases above threshold levels. This requirement for thicker-walled or stronger pipe in areas of higher population might indicate that a longer reassessment interval would be appropriate where corrosion is the dominant threat.

• If critical risk factor data are not available to support evaluation of risks, then the reassessment interval should be appropriately shortened to reflect that absence of knowledge.

• If an operator has developed a comprehensive picture of past and anticipated threats, including detailed information on risk factors and records of multiple assessments carried out over several years, the operator might be able to justify a longer reassessment interval (see the discussion above on performance-based requirements).

• The periodic evaluation is based on an information analysis of the entire pipeline.

Comments

INGAA's comments included a discussion of the results of a Battelle analysis on assessment intervals. The analysis indicated that while the recommended reassessment interval in their report was developed based on the assumption that operators would use thicker pipe to address the Class Location requirements, the recommended interval would not be affected if operators chose to use higher strength pipe (rather than thicker pipe) to comply with changes in class location.

In addition, INGAA offered the opinion that the series of new integrity management regulations will lead to a situation in which the demand for assessment equipment and people qualified in its use and in interpretation of results will outpace the supply. This factor should be considered in determining the baseline and reassessment interval requirements.

INGAA recommended that RSPA/OPS solicit information from direct assessment service providers to evaluate the ability of the service providers to respond to the requirements for increased assessment included in the new IMP Rules.

AGA/APGA urged RSPA/OPS not to require reassessment on a prescribed interval. Intervals should be dictated by analysis using accepted risk principles along with results from the baseline assessment. If a prescriptive requirement on reassessment interval is needed, then RSPA/OPS should allow operators to deviate from that interval if it can justify such a deviation.

NYGAS commented that local distribution companies (LDCs) need greater flexibility in managing repairs and mitigative action than is implicit in the repair provisions of the liquid operator rule for operators with 500 or more miles of pipeline. The absence of such flexibility will lead to gas supply interruptions to customers.

RSPA believes that once the baseline assessment has been completed, the availability of qualified vendors and assessment equipment are no longer factors, since it is quite likely that the pipeline service industry will expand to meet the new higher level of demand. In addition, the major line modifications required to accommodate in-line inspection (ILI) equipment should be completed. Some of the factors influencing reassessment intervals are discussed above under baseline intervals. Other factors that influence

the periodic reassessment interval include:

• The stress level at which the pipeline operates;

• The growth rate of corrosion defects; and

• The repair criteria used in remediating defects discovered in previous assessments.

Figure 7-1 and Table 8-1 in ANSI/ASME B31.8S sumarize the relevant factors for determining a reassessment interval. The corrosion rates reflected in these charts represent the high end of historically observed corrosion, but are not the highest rates that might be experienced under special conditions, such as the presence of microbiologically influenced corrosion (MIC). Table 8-1 relates the recommended reassessment interval in years to the stress level of the pipe (% SMYS), the type of assessment carried out, and the significance of defects left in the pipeline following mitigation or repair. For a typical pipe segment in a Class 3 Location, the stress level would be 50% SMYS. At this stress, if a pressure test were carried out at 1.39 times the maximum allowable operating pressure (MAOP), then the recommended reassessment interval would be 10 years. This same recommended reassessment interval would result if ILI were used and all defects were repaired that had a predicted failure pressure below 1.39 times the MAOP. The recommendations for reassessment intervals following use of direct assessment are closely related to the details of the excavation criteria used in examining indications. The intervals shown in (Table 8-1 in ASME B31.8S) are based on technical analysis of time-dependent failure mechanisms (

e.g.

, external corrosion).

The recently-enacted pipeline safety law (HR 3609 signed into law Dec. 17, 2002) requires that reassessment be done at minimum intervals of seven-years. Thus, in our proposed rule, we have established a seven-year interval, but we also allow the operator to establish the intervals depending on the assessment method. Depending on the assessment method, the maximum interval an operator is allowed to establish could be longer than seven years. However, if the period is longer than seven years, the operator would have to conduct an interim reassessment by confirmatory direct assessment by the seventh year and then conduct the follow up reassessment in the year the operator has established. Thus, in the seven-year period an operator must either reassess a covered segment using the assessment method the operator has chosen, or if the operator has established a longer interval, conduct a confirmatory direct assessment by the seventh year with a follow up reassessment in the year the operator sets. Our proposal takes into account the factors we have discussed above.

Monitor the Effectiveness of Pipeline Integrity Management Efforts

The seventh element of integrity management discussed in the June 27, 2001 FR notice, related to monitoring the effectiveness of pipeline integrity management activities. We used the following hypothesis in the notice:

• Measures can be developed to track actual integrity performance as well as to determine the value of assessment and repair activities.

• Application of integrity management technologies that exceed current regulations is cost effective because many companies made the decision to implement such programs.

Comments

INGAA suggested that RSPA/OPS should consider including the following performance measures:

• Number of miles of pipeline inspected under IMP.

•

Repairs:

1. Number of immediate repairs completed as a result of the IMP inspection program; and

2. Number of scheduled repairs completed as a result of the IMP inspection program.

• Number of leaks, failures and incidents (classified by cause).

AGA/APGA suggested that RSPA/OPS should work with stakeholders to develop performance measures immediately after promulgation of the integrity management rule. Additionally, in using these measures, RSPA/OPS must avoid inappropriate comparisons of performance among operators with vastly different systems.

NYGAS stated that performance measures should be properly used to monitor the effectiveness of integrity management efforts within individual companies, not to compare the performance among operators.

The Association of Texas Intrastate Natural Gas Pipelines commented that it would be useful for RSPA/OPS to establish performance measures that relate to each operator's integrity management plan, rather than requiring one-size-fits-all reporting requirements.

Enron commented that if RSPA/OPS were to increase the time for required submission of written pipeline incident reports by an additional sixty days, then there would be an opportunity to include better information on the evaluated cause of each incident.

The recently published standard ASME B31.8S discusses operator performance plans in Chapter 9. This discussion describes four measures that are required to be monitored by all operators using the standard. These measures are:

• Number of miles of pipeline inspected (assessed) versus program requirements;

• Number of immediate repairs completed as a result of the integrity management inspection program;

• Number of scheduled repairs completed as a result of the integrity management inspection program; and

• Number of leaks, failures and incidents (classified by cause).

RSPA/OPS is proposing to require operators to track and record these four overall performance measures, and make them electronically accessible (in real time) to RSPA/OPS for review. In addition, RSPA/OPS proposes to require operators to develop performance plans consistent with ASME B31.8S, and to define the extended set of measures that it will track. OPS will be able to review these measures during periodic field inspections. Appendix SP-A of ASME B31.8S tabulates suggested measures for each threat to which a pipeline might be subject.

Consideration of Impact on Gas Supply

The eighth consideration of integrity management discussed in the June 27, 2001 FR notice, related to the impact of the rule on gas supply. Performing an assessment test on gas transmission pipelines has the effect of restricting gas flow. Unless adequate time is allowed and the assessment process is carefully managed, this flow restriction can significantly impact gas supply and cost to customers.

Different assessment technologies have different restrictions on gas supply. In-line-inspection merely restricts flow for the relatively short time when the instrumented internal inspection device (pig) is in the pipe. However, preparing the pipe to make it able to be internally inspected (piggable), requires termination of the gas flow in the segment being tested while modifications are made. At present over 75% of gas transmission lines are not piggable or can be made piggable only with extensive modifications. Pressure testing requires termination of gas flow in the section being tested each time it is carried out. Direct assessment requires flow restriction (associated with lowering the pressure as a safety measure) while selected locations along the pipe are being excavated and directly examined.

We indicated above that assessing pipelines using any of the technologies under consideration may result in a restricted gas supply because of the need to take pipelines out of service or by reduction in throughput. In addition, some types of repairs will also require lines to be taken out of service. If an upstream segment of this gas transmission pipeline were put out of service temporarily for test or repair, many communities located at the end of branch lines, could be negatively impacted by the restricted gas supply. This effect would be caused by the fact that the lines are often sole source feed, (

i.e.

, have no other tie-in's from an alternative source.) Because of this factor, the proposed rule allows a waiver of a reassessment interval greater than seven years, if the operator demonstrates that it cannot maintain local product supply, and OPS determines that a waiver would not be inconsistent with pipeline safety. This proposal is consistent with the provision in the Pipeline Safety Improvement Act of 2002. Because a waiver requires public notice and comment, we are proposing 180-day advance notification.

INGAA Report

INGAA commissioned an extensive analysis of the economic impact of a gas IMP rule. The analysis, performed by Energy & Environment Analysis, Inc., evaluated this impact using various assumptions on the fraction of the affected pipe that is currently not piggable that will be assessed by pigging, pressure testing, or direct assessment. The time frame during which the baseline assessment must be performed was also a parameter in the analysis, varying from five to fifteen years. While (at the time of the INGAA comment—August 14, 2001) sufficient detail was not available to evaluate the credibility of the analysis and its underlying assumptions, the estimated economic impact on gas consumers for the ten year baseline period is large, ranging from $3.9 billion to $6.1 billion. (Note, this analysis and a peer review of report performed by the Volpe National Transportation Systems Center (Volpe Center) and the Department of Energy (DOE) have recently been completed and are discussed below).

AGA/APGA commented that some forms of assessment (

e.g.

, pressure testing) would require outages from 3 to 9 days. Customers would in some cases be without gas during that time, and restoration of gas supply would require extensive work, for example, re-lighting pilot lights of each affected customer.

Discussions on the INGAA Report on “Consumer Effects of the Anticipated Integrity Rule for High Consequence Areas” (February 2, 2002)

On April 3, 2002, RSPA/OPS held a meeting with INGAA, Energy and Environment Associates (EEA), the Volpe Center, and DOE to discuss the INGAA report on “Consumer Effects of the Anticipated Integrity Rule for High Consequence Areas” (February 2, 2002). The meeting was designed to allow RSPA/OPS, and several reviewers retained by RSPA/OPS, to explore the reasonableness of the results in the INGAA-sponsored report. The focus of discussion was on the assumptions made in the analysis. The report was produced in response to the initial need to understand the supply and economic implications of allowing or disallowing direct assessment as a primary assessment technology, and later was expanded to evaluate the supply and economic implications of various baseline assessment intervals ranging from 5 to 15 years.

The report focuses on interstate transmission pipelines. INGAA indicated the industry expects that most HCA mileage will lie in Class 3 and 4 Locations, and that approximately 5% of pipeline is in class 3 and 4 locations, but that the HCA definition will include some pipe segments in other locations as well. INGAA said that Class 3 and 4 Locations are scattered throughout the pipeline system so they appear in about 60% of valve stations and 80% of the discharges from compressor locations.

INGAA further stated that a periodic inspection program was useful only to identify the presence of dynamic failure mechanisms or threats (

i.e.

, corrosion). They questioned the value of periodic assessment of pipelines for static threats (

i.e.

, material and construction) or random threats (

e.g.

, third-party damage).

The reviewers at the meeting requested clarification of the study assumption regarding the fraction of lines that are assumed to be in-line-inspected. Scenarios 1, 2 and 3 in the report assume segments described as “currently piggable” and “relatively easy to make piggable” are treated as “easy to pig” (

i.e.

, about 50%). The other scenarios, 3A, 3B and 3C in the report assume that only “currently piggable” segments are treated as “easy to pig” (

i.e.

, about 25%). This difference in assumptions complicates comparison between Scenarios 1, 2 & 3 and Scenarios 3A, 3B & 3C. EEA stated that market evaluations do show that there are capacity choke points and that spot market prices respond to capacity restrictions. Examples include recent price spikes in the States of California and New York. These capacity restriction effects were the focus of the study. No account was taken of the cost incurred by operators making lines piggable, although the capacity impacts associated with these maintenance activities were considered.

Other key assumptions in the analysis include: (1) 80% of mainline pipe and 50% of laterals/connections will be inspected (these numbers are supported by consideration of the distribution of segments that can affect HCAs throughout the pipeline systems and by the fact that even operators using direct assessment as their primary assessment approach will be required to reduce pressure in long segments of their lines during the direct examination step of the process). (2) Effects on consumers with limited options and flexibility in gas providers will be much more severe (

e.g.

, Florida has one transmission line, with a second to come in service this summer. Load factor on the line is greater than 80% and any interruptions would have significant downstream effect, and therefore cost impacts). It was noted by INGAA at the meeting that gas supply interruptions are not as routinely buffered by storage capacity as liquid petroleum products, which are normally stored in tanks. (3) The industrial sector is more elastic than the residential sector. Demand there was adjusted significantly when gas prices were high over the last couple years. (4) The analysis assumes that the impact of supply restrictions occurs at the time the restriction occurs rather than at a later time, as would occur because of long-term supply contracts. (5) Both pipeline capacity and demand are assumed to increase, as described in the base case of “The Pipeline and Storage Infrastructure for a 30 Trillion Cubic Feet (TCF) Market” better known as the “30 TCF study.”

The TCF study uses the EEA Gas Market Data and Forecasting System. This model was developed in 1995 requiring over ten person years of effort. The model is rigorously calibrated to actual historical behavior. Price differences are calculated as a function of load factor. The calibration is updated annually.

The model is a fairly coarse one in which multiple supply lines between market centers are modeled as a single line. However, the model appropriately considers the effects of capacity restrictions in one line in a corridor, and does not assume that a single line out of service terminates supply through the corridor in which it resides. This effect is treated separately from the model and

provided as an input to the model. The inputs to the model are developed assuming perfect communication among operators with lines in a single corridor, or supplying a single market center such that operators do not take multiple lines out of service that would compound the impact on capacity restriction at that market center. Taking multiple lines out of service in a single corridor might be necessary, if the baseline assessment interval were sufficiently short to require such action.

As the market becomes thinner (

i.e.

, supply is restricted relative to demand at a market center) consumers bid against each other causing spot market prices to rise. Costs developed in the model may be overstated over a 10-year period, because all consumers do not pay spot prices. As pipelines are re-contracted, however, those costs will be reflected in the new contracts.

In response to questions about why pipe assessments carried out prior to the rule currently being considered have not strongly affected gas prices, INGAA indicated that people who currently administer active pigging programs represent only about 25% of the total pipeline mileage and implemented their programs over about a 20 year period. INGAA said that in response to the anticipated rule, operators would have to assess a significant fraction of their systems (the segments covered by a rule) over ten years. The associated supply impacts and consumer costs will therefore be much larger.

The reviewers at the meeting suggested it would be very useful if INGAA would summarize all major assumptions and discuss the direction and approximate magnitude (

e.g.

, small medium, large) of the effect of each assumption on the resultant cost impact. INGAA agreed to consider how best to respond to comments raised during the meeting and in the review documents that had been prepared in advance by Volpe and DOE reviewers. For detailed discussion on this subject see minutes of this meeting in the docket.

Other Issues Including Those Related to Cost/Benefit

The ninth consideration of integrity management discussed in the June 27, 2001 FR notice, related to other issues including those related to the cost/benefit analysis.

Comments

INGAA commented that RSPA/OPS should perform its cost-benefit analysis starting with current industry practices (as described in recent INGAA reports) as the baseline. They also provided some data on the number of incidents and property damage over the past fifteen years, but did not provide any information on the impact of incidents and leaks on the cost of gas to customers.

INGAA provided preliminary information on the estimated costs of inspection of all transmission pipelines for three different scenarios on inspection of hard-to-pig (HTP) pipelines. These preliminary costs include estimates to convert HTP segments to make them piggable. The inspections were assumed to be carried out over a ten year period.

Scenario description

Consumer cost for 10 years period (millions)

1/2

HTP portion pigged,

1/2

HTP portion DA

$3,892

1/2

HTP portion pigged,

1/2

HTP portion Hydro

6,095

1/3

HTP portion pigged,

1/3

HTP portion DA,

1/3

HTP portion DA

4,048

The numbers in this table were updated through the completed INGAA/EEA analysis discussed above.

On the question of small business impacts, INGAA noted that no more than 50,000 miles of approximately 274,000 miles of natural gas transmission pipelines (and probably much less) could be owned by small businesses. Also, many of the contractors likely to be involved in inspections are small businesses. Finally, the potential exists that increased gas costs will impact small business customers.

AGA/APGA strongly suggested that RSPA/OPS develop the integrity rule for gas transmission pipelines around a performance-based approach.

The Florida Public Service Commission noted that performance type regulations can only work if operators are willing to share information on both performance and potential problems with the regulators. They believe that the risk management demonstration program has shown the operators are unwilling to openly share needed information.

The New York Gas Group strongly supports the development of a performance-based rule that will allow companies the flexibility needed to manage the risks associated with their pipelines, as effectively as possible. They asserted that this position is supported by the NY State Public Service Commission staff.

The Process Gas Consumers Group (PGC) commented that RSPA/OPS should give strong consideration to any potential economic impact of interruptions in gas supply to industrial concerns that rely on gas in the conduct of their business.

Conclusions From the Consumer Cost Impact Evaluation

Consumer cost and supply availability are major factors in establishing the period for operators to complete the baseline assessment. There are numerous assumptions made in the INGAA study. In general they are designed to underestimate the predicted cost impact. For example, the study does try to optimize time of testing, and assume infinite availability of pig vendors and equipment. However, there are also assumptions in the study that would lead to prediction of higher cost impact than might realistically be expected. For example, the study does not assume learning on the part of the operators, and the analysis reflects marginal costs rather than contracted costs.

The EEA analysis found that consumer cost impact was more significant with short baseline assessment periods than with longer times. The cost impacts were estimated to be $7.2 billion for a 14-year baseline period, $13.1 billion for a 10-year baseline period, and $20.1 billion for a 5-year baseline period. Although not quantifiable in the model, the potential for critical supply interruptions, resulting from the need to perform assessments during high demand periods and the increased difficulty of coordinating assessments on lines feeding the same customers, increases as the baseline period decreases.

RSPA's Conclusions About the INGAA Study

From its review of the INGAA study RSPA concluded that—

Study Performers.

The organization that performed the study for INGAA is recognized as an expert in the type of analysis performed. This conclusion is supported by the fact that EEA has been called to testify on significant supply issues before Congress, and that the gas pipeline industry is using the results of the study on which the present impact analysis is based as a major factor in expansion decisions.

Study Conservatism.

The peer review identified several assumptions used in the analysis in which it would lead to over-prediction of the gas supply and cost impacts, as well as some areas where the model would be expected to result in under-estimation of these impacts. In balance, the model together with its major assumptions seems to produce a reasonable, possibly an

underestimate, of the anticipated supply and cost impacts.

Baseline Assessment Time Frame.

The decision on a baseline assessment interval must reflect the need to expedite pipeline assessment without dramatically impacting gas availability and price. The INGAA/EEA analysis supports the conclusion that a ten-year baseline assessment requirement is consistent with managing supply and cost impacts resulting from the new assessment requirements. The predicted impact on consumer energy cost associated with this baseline time frame is $13.1 billion. While this is a very large cost, it represents a small percentage impact on total gas costs over the time period of the analysis. RSPA has concluded that a ten-year baseline assessment period, with 50% of covered segments being assessed within five years, will allow the impact on gas supply and cost to be adequately managed by the operators.

Mapping

We stated in the proposed rule on high consequence areas (67 FR 1108; January 9, 2002), that RSPA/OPS is creating the National Pipeline Mapping System (NPMS), a database that contains the locations and selected attributes of natural gas transmission lines and hazardous liquid trunk lines and liquified natural gas facilities operating in the United States.

RSPA/OPS will require operators to provide their pipeline data by a separate rulemaking on mapping. Submission of this information has been voluntary in the past. At present, RSPA/OPS has received data on pipe locations for 90% of liquid pipelines but only 52% of gas pipelines. Currently, RSPA/OPS has no data on areas of higher population density (Class 3 and 4 locations) associated with gas pipelines. Present gas pipeline regulations are structured to provide increasing levels of protections, consistent with predetermined thresholds. Accordingly, gas pipeline operators are required to monitor data on the number of dwellings within 660 feet of their pipelines to either lower operating pressure or to replace the pipe with one having greater wall thickness or strength as the number of dwellings increases above predefined threshold. RSPA/OPS therefore believes that operators have excellent data on population and places where people congregate near their pipelines.

Maps incorporating these data would be useful not only to pipeline operators, but also to federal and state inspectors and for local officials and community needs. RSPA/OPS intends to use operator-supplied information to map the high consequence areas that it defines in a gas integrity management rule, similar to how it is mapping these areas for the liquid operators. A separate rulemaking on mapping will address this issue.

Treatment of Storage Fields

Storage fields have provided a source of pipeline integrity problems for decades. RSPA/OPS asked for information to help identify the cause of and prevent piping-related failures associated with storage fields that could affect high consequence areas. INGAA stated that those in high consequence areas should be treated in the same way as natural gas transmission pipelines.

The proposed rule requirements will include pipelines within the storage fields because under § 192.3(c) such pipelines are defined as transmission lines.

The Proposed Rule

RSPA/OPS is proposing a modification to section 192.761 and addition of a new section 192.763 to subpart M: High Consequences Area Definitions and Integrity Management Programs. The § 192.761 titled “Definitions” defined “high consequence areas” in a recently issued final rule (67 FR 50824; August 6, 2002); and proposed a new section 192.763 “Pipeline Integrity Management in High Consequence Areas” is described in this rule.

High Consequence Area Definitions—§ 192.761

The definition of high consequence areas recently published in the

Federal Register

(67 FR 50824; August 6, 2002) includes: (a) Current Class 3 locations; (b) current Class 4 locations; (c) an area that extends 300 feet from the centerline of the pipeline to the identified site for a pipeline not more than 12 inches in diameter and having a maximum operating pressure lower than 1200 psig; (d) an area of 1000 feet from the centerline of the pipeline to the identified site for a pipeline greater than 30 inches in diameter operating at a pressure greater than 1000 psig; (e) an area that extends 660 feet from the centerline of the pipeline to the identified site for all other pipelines. The areas of 300, 660 and 1000 feet are corridors that have been determined based on generalized estimates of potential rupture consequences. An identified site is defined as a building or outside area that can be identified by one of several means and that houses people who are difficult to evacuate or have impaired mobility (

e.g.

, hospital, church, school, prisons, day care facility); or where there is evidence that 20 or more people congregate at least 50 days in a year (

e.g.

beach, camping ground, religious facility). The full text of the HCA definition can be reviewed in the

Federal Register

document referenced above.

An identified site can be identified by one of several means listed in the rule: it is visibly marked, it is licensed or registered, it is on a list or map maintained by or available from a Federal, State or local agency or a publicly or commercially available database or it is know by public officials. RSPA/OPS is inviting comment on whether we should use the term public safety officials (

e.g.

Police, Fire department) and/or emergency response officials instead of public officials. Currently, pipeline operators are required to conduct liaison activities with public safety officials or emergency safety officials. We would like comment on whether the term “public safety officials or emergency response official” will cover the persons having the relevant information about these identified sites.

On September 5, 2002, the American Gas Association (AGA), the American Public Gas Association (APGA), the Interstate Natural Gas Association of America (INGAA), and the New York Gas Group (NYGAS) filed a petition for the reconsideration of the final rule on the definition of HCAs for gas transmission pipelines (67 FR 50835; August 8, 2002). This petition is in the docket. The petition raised the following issues.

(1) The splitting of the gas integrity rule into two rulemakings—the definition and the integrity requirements—causes confusion, particularly, since the Potential Impact Zone concept was not included in the definition.

(2) The HCA definition should clarify that it applies to those gas transmission pipelines that have the potential to impact high population density areas and does not apply to distribution pipelines.

(3) The identified site component (buildings and outside areas) is overly broad. The definition should instead use the language in 192.5.

RSPA/OPS believes issuance of this proposed rule will alleviate most of the concerns raised in the petition. As previously discussed, the HCA rule only defines general areas of high consequence. It includes corridors (lateral distances of 300, 660, and 1000 feet), but not axial distances along the pipeline. The axial distances can only be determined by analysis of potential

impact zones which are covered in this proposed rule. We have put the proposed potential impact zones definition under the same section 192.761, where HCAs are defined.

The petitioners argued it would be difficult to identify a building or outside area that is frequented by 20 or more persons on at least 50 days in any 12-month period, and would include isolated and infrequently occupied buildings. RSPA/OPS does not know how many rural buildings would be covered by the HCA definition or how many miles of pipeline segments would have to be added to the assessment plans to include these buildings which are populated for a short time relative to the other populated areas. We are trying to focus on high risk areas for assessment. Instead of including rural buildings, such as rural churches as High Consequence Areas, we could designate them as Moderate Risk Areas requiring less frequent assessment or requiring enhanced preventive and mitigative measures only. We would like public comment on this issue. We are proposing to define a Moderate Risk Area as an area located within a Class 3 or Class 4 location, but not within the potential impact zone.

This proposed rule presents requirements to improve the integrity of pipelines located in areas of potentially high consequences that go beyond those HCAs. The proposed IMP rule proposes to expand the definition of HCA by adding consideration of people living at distances greater than 660 feet from large diameter high pressure pipelines. Populated areas at distances less than 660 feet are already accounted for under Class 3 and 4 locations, however, populated areas beyond 660 feet were left out of the HCA final rule of August 6, 2002 (67 FR 50824). In this proposed rule, we are adding a new proposed HCA component of populated areas in paragraph 192.761 (g). We are proposing to require that an operator consider 20 or more buildings intended for human occupancy within an potential impact circle of radius 1000 feet or larger. We calculated that 20 buildings within a circular area of a 1000-foot radius represent a resident density equivalent to 46 buildings within a rectangular area one mile long and 1320 feet wide (current Class 3 location definition). Therefore, by using 20 or more buildings within circular area of radius 1000 feet we are, including areas having the same density of population as Class 3 locations.

To understand the provisions of this proposed rule, it is necessary to understand both the pipe segments covered by the proposal and the ranking of integrity improvement requirements for those pipe segments. The approach involves the six steps that rely on the definitions below: (1) Identify all HCAs for the pipeline using the HCA definitions as expanded by this proposed rule; (2) calculate the Potential Impact Radius (PIR) for each 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 Potential Impact Zones (PIZ) for the pipeline and in Class 3 and Class 4 locations, identify the moderate risk areas; and (6) determine the priority of each segment covered by this proposed rule—covered segments located within a potential impact zone are considered higher priority, whereas those located outside a PIZ are considered lower priority.

The following proposed definitions help to understand these six steps:

Potential Impact Circle (PIC)

—PIC is a circle of radius equal to the threshold radius used to establish higher priority areas within HCAs. A potential impact circle contains any of the following (for greater clarity see the diagram in Appendix E):

• 20 or more buildings intended for human occupancy within a circle of radius 1000 feet, or larger if the threshold radius is greater than 1000 feet;

• A facility that houses people who are difficult to evacuate as defined in § 192.761; or

• A place where people congregate as defined in § 192.761.

Potential Impact Radius (PIR)

—PIR means the radius of a circle within which the potential failure of a pipeline could have significant impact on people or property. PIR is determined by the formula r = 0.69 * (square root of (p*d

2

)), where “r” is the radius of a circular area surrounding the point of failure (ft), “p” is the maximum allowable operating pressure (MAOP) in the pipeline segment (psi), and “d” is the diameter of the pipeline (inches). (

Note:

0.69 is the factor for natural gas. This number will vary for other gases depending upon their heat of combustion. An operator transporting gas other than natural gas must use Section 3.2 of ASME/ANSI B31.8S to calculate the impact radius formula).

Potential Impact Zone

(PIZ)—PIZ is a rectangular area along the pipeline derived from the potential impact circle. The potential impact zone extends axially along the length of the pipeline from the center of the first potential impact circle to the center of the last contiguous potential impact circle, and extends perpendicular to the pipe out to the threshold radius on either side of the centerline of the pipe. For greater clarity see the diagram in Appendix E.

Threshold Radius

—Threshold Radius is a bounding radius intended to provide an additional margin of safety beyond the distance calculated to be the potential impact radius. If the calculated potential impacted radius is less than 300 feet, the operator must use a threshold of 300 feet. If the calculated potential impacted radius exceeds 300 feet but is less than 660 feet, the threshold is 660 feet. If the calculated potential impacted radius exceeds 660 feet, but is less than 1000 feet, the threshold is 1000 feet. And, if the calculated potential impact radius exceeds 1000 feet, the threshold is 15% greater than the actual calculated impacted radius.

Pipeline Integrity Management in High Consequence Areas—Proposed Section 192.763

The proposed new § 192.763 titled “Pipeline integrity management in high consequence areas” imposes integrity management program requirements on all gas transmission pipelines covered under Part 192 that impact high consequence areas.

The proposed rule requires an operator of a transmission line to develop and follow an integrity management program that provides for continually assessing the integrity of all pipeline segments in the high consequence areas using internal inspection, pressure testing, direct assessment or other equally effective assessment means. The proposed rule further requires that the program provide for evaluating the entire range of threats to the integrity of each pipeline segment through comprehensive information analysis. Further, for each covered pipeline segment, the operator must provide additional protection to a pipeline segment's integrity though remedial actions and enhanced preventive and mitigative measures.

(a) Which Operators Must Comply? Proposed § 192.763(a)

The rule proposes that any operator of a gas transmission pipeline must comply with the integrity management program requirements.

(b) Which Pipeline Segments are Covered? Proposed § 192.763(b)

Any gas transmission pipeline located in a high consequence area, including transmission pipelines transporting petroleum gas, hydrogen, and other gas products covered under Part 192. Gas transmission is defined in § 192.3, and

includes pipelines within storage fields as transmission lines. Thus, this proposed rule covers pipelines within storage fields. Pipeline, by definition, means all parts of those physical facilities through which gas moves in transportation, including pipe, valves and other appurtenances attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies. The proposed rule does not apply to gas gathering or to gas distribution lines.

(c) What Must an Operator Do? Proposed § 192.763(c)

The rule proposes that no later than one year after the effective date of the final rule, each operator is required to establish a written integrity management program that addresses the threats on each pipeline segment that could impact a high consequence area. The operator would then implement and follow the program it has developed. Initially, the program would consist of a framework. Within one year after the final rule becomes effective, we would expect an operator's integrity management program to consist of:

• Identification of all pipeline segments that are in a high consequence area as defined in § 192.761 (and expanded by this proposed rule). It would also include categorization of whether these segments fall into a potential impact zone. All segments identified will be required to have enhanced integrity protection. The identification of potential impact zones is required to determine the length of baseline assessment intervals for these segments. Because identification of the pipeline segments is the trigger for all other integrity management requirements, the identification must be done within one year from the final rule's effective date. When evaluating the consequences of a failure within the potential impact zone the operator refer to Section 3.3 of ASME/ANSI B31.8S for a minimum set of consequence factors to consider.

• 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 initially be made to implement each element. To be effective, an integrity management program must constantly change. RSPA/OPS expects that the initial program will consist of a framework that specifies the criteria for making decisions to implement each of the required elements. The program evolves from the framework and must continue to change to reflect operating experience, conclusions drawn from results of the integrity assessments, and other maintenance and surveillance data, and evaluation of consequences of a failure on the high consequence area. In addition, the program must evolve to reflect the best practices used in the pipeline industry to assure pipeline integrity. An operator will have to document any change it makes to its program before implementing the change. In addition, if a change is significant enough that it affects the program's implementation or significantly modifies the program, the operator must notify OPS within 30 days of adopting the change into its program. An initial decision on the type of assessment method an operator is going to use is not considered a significant change.

• A plan for baseline assessment of the pipeline. The plan must identify segments to be assessed, applicable threats for each segment, method(s) selected to assess each pipeline segment (including internal inspection tool or tools, pressure test, direct assessment, or other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe), the basis on which each assessment method was selected, and a schedule for completing the baseline integrity assessment. An operator would also have to show that it is conducting the assessment in a manner that minimizes environmental and safety risks. See also the preamble discussion under section 192.763(e).

• A direct assessment plan for operators intending to use one of the direct assessment processes, describing how these processes will be used, including identification of External Corrosion Direct Assessment Regions.

To carry out the requirements of the proposed rule, an operator would, where specified, follow the prescriptive requirements of ASME/ANSI B31.8S, and its appendices, unless the proposed rule provides otherwise, or the operator demonstrates that an alternative practice is supported by a reliable engineering evaluation and provides an equivalent level of safety for the public and their property.

Performance-Based Option.

ASME/ANSI B31.8S provides the essential features of both a performance-based and a prescriptive integrity management program. The proposed rule allows an operator to use a performance-based approach if the operator satisfies certain exceptional performance requirements. If the operator satisfies these requirements, the proposal would allow an operator to deviate from certain integrity management performance requirements—the time frame for reassessment, as long as a confirmatory direct assessment were done every seven years, using direct assessment as a primary method without having to satisfy the pre-conditions and the time frames for remediating anomalies found during the assessment.

•

Exceptional Performance.

To show exceptional performance the rule proposes that an operator have completed a baseline assessment of all covered pipeline segments, and at least one other assessment; remediate all anomalies identified in the second assessment according to specified requirements; and incorporate the results and lessons learned from the second assessment into the operator's risk model. An operator would also have to demonstrate that it has an exceptional integrity management program that meets the performance-based requirements of ASME/ANSI B31.8S, has a history of measurable performance improvement, and includes, at minimum:

(A) A state-of-the-art process for risk analysis;

(B) all risk factor data used to support the program;

(C) a state-of-the-art data integration process;

(D) a process that applies lessons learned from assessment of covered pipe segments to pipe segments not covered by this section;

(E) a process for evaluating all incidents, including their causes, within the operator's sector of the pipeline industry for implications both to the operator's pipeline system and to the operator's integrity management program;

(F) a performance matrix that confirms the continuing performance improvement realized under the performance-based program;

(G) a set of performance measures beyond those that are required that are part of the operator's performance plan and are made accessible in real time to OPS and state pipeline safety enforcement officials; and

(H) an analysis that supports the desired integrity reassessment interval and the remediation methods to be used for all pipe segments.

(d) What Are the Elements of an Integrity Management Program? Proposed § 192.763(d)

The proposed rule requires an operator to include certain minimum elements in its integrity management program that are either specified in the proposed rule or in the ASME/ANSI B31.8S standard. Initially, an operator

must develop a framework describing these elements. The framework describes how each element of the program will be carried out initially and documents expected near-term improvements to be implemented to these processes. Over time, this framework evolves into a program description as the operator learns from its experience and that of other operators, and incorporates that knowledge into an ever-improving process description. The proposed required program elements include:

• A process for identifying all potential threats to pipeline integrity in each high consequence area. Section 2.2 of ANSI/ASME B31.8S standard describes how all significant threats to the pipeline can be grouped into 9 categories. It further regroups these 9 categories of threats into three types: time dependent threats (

e.g.

, external corrosion, internal corrosion, stress corrosion cracking); stable or static threats (

e.g.

, manufacturing related defects (defective pipe seam, defective pipe), welding/fabrication related (defective girth or fabrication weld, wrinkle bend , etc.), equipment failure (gasket, control/relief valve, pump seal, etc.); and time independent threats (

e.g.

, third party damage).

• A baseline assessment plan (discussed in § 192.763(e).

• Criteria for remedial actions to address integrity issues raised by the assessment methods and information analysis, (criteria for repair are discussed in B31.8S, Section 7). These criteria recognize that the nature and timing of action related to a defect depend on the severity of the defect. Some require immediate action, some require mitigation over a prescribed period, and some must be monitored to ensure they do not represent a future threat to the integrity of the pipeline. ASME B31.8S, Section 7, also recognizes that the repair threshold an operator chooses for taking action on a recognized defect is related to the time acceptable before a follow-up reassessment is performed. If only very small defects are not mitigated in the pipe, then a longer time is acceptable before reassessment is needed. Repair criteria in Section 7 of ASME B31.8S reflect the current reality that developing assessment techniques, such as direct assessment, are not yet as mature as in-line-inspection and pressure testing. Therefore, operators choosing direct assessment must either excavate all indications, or they must reassess their pipe at shorter time intervals.

• A risk analysis that considers all available information about the integrity of the entire pipeline, evaluates its relevance to each segment within an HCA, and estimates the likelihood and consequences of a failure. Requirements and guidance on the gathering, review and integration of risk factor data is provided in ASME B31.8S, Section 4. Acceptable approaches to analyzing the risks associated with each segment are presented in ASME B31.8S, Section 5. The purpose of this analysis is to utilize the best available information, including operating experience on the entire pipeline, to determine the susceptibility to failure of each segment to each potential threat, then to estimate the relative magnitude of the threat so assessment actions can be prioritized.

• A continual process of assessment and evaluation to maintain a pipeline's integrity: Reassessment intervals for different assessment techniques, pipe stress levels and characteristics of residual defects (

e.g.

, predicted failure pressure, hydro-test pressure, or DA repair scope) are discussed in ASME B31.8S, Section 8, and summarized in Table 8-1.

• Identification of preventive and mitigative measures to protect the high consequence area: ASME B31.8S presents an extensive listing of preventive measures in Section 7. RSPA/OPS expects each operator to evaluate the value of instituting these practices in the light of information on threats posed to each segment and to implement applicable and cost-beneficial measures.

• A performance plan, including methods to measure the effectiveness of the program: Performance measurement is treated in the discussion of performance planning in Section 9 of ASME B31.8S, and candidate measures for each threat are presented in Appendix SP-A.

• A process for review of integrity assessment results and information analysis by a person qualified to evaluate the results and information. An operator must use qualified persons with the necessary technical expertise to evaluate and analyze the results and data from the integrity assessments, the periodic evaluation, the information analyses, etc. Qualifications for these people must be documented and records made available to verify qualifications.

• A management of change process, as outlined in ASME/ANSI B31.8S, Section 11.

• A quality assurance process, as outlined in ASME/ANSI B31.8S, Section 12.

• A communication plan that includes the elements of ASME/ANSI B31.8S, Section 10, and that includes a process for addressing safety concerns raised by OPS, including safety concerns OPS raises on behalf of a State or local authority with which OPS has an interstate agent agreement.

• 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.

• A process for ensuring that each integrity assessment is being conducted in a manner that minimizes environmental and safety risks.

One of the most important elements of an integrity management program is operator qualification. This proposed rule requires an operator to verify that supervisors possess and maintain a thorough knowledge of the integrity management program and its elements for which they are responsible. Individuals who qualify as supervisors for any aspect of integrity management programs must have appropriate training or experience in that area. This proposed rule requires the operator to document requirements for these supervisory individuals and others, who are responsible for gathering and interpreting the results of integrity assessments.

(e) What Must Be in the Baseline Assessment Plan? Proposed § 192.763(e)

The proposed rule requires that an operator must include in its written baseline assessment plan each of the following elements:

• Potential threats to the integrity of each pipeline segment. Candidate threats are discussed in this section under § 192.763(f).

• The method or methods selected to assess the integrity of the line pipe in the high consequence area. The integrity assessment method(s) used must be based on threats to which the segment is susceptible. More than one method and/or tool may be required to address all the threats in the pipeline segment. An operator must assess the integrity of the line pipe by: internal inspection tool or tools capable of detecting corrosion, and any other threats to which the pipe segment is susceptible; pressure test conducted in accordance with subpart J; direct assessment in accordance with the proposed requirements; or other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing to use the other technology option must notify RSPA/OPS 180 days before conducting the assessment. RSPA/OPS expects an operator to make the best use of current and innovative technology in assessing the integrity of the line pipe.

• A schedule for completing the integrity assessment.

• An explanation of the assessment methods the operator selected and an evaluation of risk factors the operator considered in establishing the assessment schedule for the pipeline segments.

• For an operator using direct assessment, a plan that takes into consideration the definition of ECDA and ICDA Regions and the complementary tools to be used for each ECDA regions.

• A process describing how the operator is ensuring that the baseline assessment is being conducted in a manner that minimizes environmental and safety risks (

e.g.,

where would launchers and receivers be placed; how the operator plans to dispose of hydrostatic test water; how low point drains would be tested; what extra attention would be given during excavations.). This proposed requirement applies to any assessment method the operator uses and to the reassessments, not just the baseline assessment.

Direction on the analysis of threats, including the data requirements, and on the selection of assessment techniques is provided in ASME B31.8S, Appendix SP-A.

Internal inspection is one of the most useful tools in an integrity management program. Depending on the threats present, RSPA/OPS expects an operator, with pipelines that are piggable or that can easily be made piggable, to consider using geometry tools (for detecting changes in circumference) and metal loss tools (for determining wall anomalies, or wall loss due to corrosion). Both high resolution and low resolution metal loss tools can be beneficial in integrity assessment. For details of each internal inspection tool, including their selection, capabilities, effectiveness, and use, operators should refer to Section 6 of the ANSI/ASME B31.8S. This standard discusses corrosion/metal loss tools for internal and external corrosion threat, crack detection tools corrosion cracking threat, metal loss or geometry tool for third party and mechanical damage threat.

This proposed rule will allow “other technology” as one of the four methods to assess the condition of pipeline segments that could impact high consequence areas. RSPA/OPS expects that as these tools are developed they may become useful assessment tools or as complements to direct assessment tools. We expect these tools could be used where internal inspection tools cannot be used, where pressure testing is not feasible, and where only one type of currently proven direct assessment tool could be used or where pipeline is not easily accessible for direct assessment. Some examples of such applications are, cased piping (

i.e.

, under either a river or road crossing), pipe in frozen ground or where bare pipe needs to be examined. Two examples of emerging technologies currently being reviewed and evaluated by RSPA/OPS are: (1) Long-range ultrasonic testing or guided wave ultrasonic testing for in-service monitoring of corrosion and other metal loss defects; and (2) “No-Pig” technology, a tool that can determine internal and external corrosion of the pipeline from above ground.

(f) How Does an Operator Identify Potential Threats to Pipeline Integrity? Proposed § 192.763(f)

The proposed rule requires each operator to identify and evaluate all potential threats to pipeline integrity in each area of potential high consequence. Threats that an operator must consider include, but are not limited to:

• Time dependent threats such as internal corrosion, external corrosion, and stress corrosion cracking;

• Static or resident threats such as fabrication or construction defects;

• Time independent threats such as third party damage and outside force damage; and

• The effect of human error.

The nine threat categories that comprise the first three general types of threat are discussed in ASME B31.8S, Appendix SP-A. In this Appendix human error is treated as a contributing factor to many of the major threats rather than as a separate threat. For example, it may be the dominant cause of rupture for third party damage incidents in which the equipment operator attempted to locate the pipeline before beginning excavation, but was given erroneous information about the location of the pipeline. In that Appendix, soil erosion is not treated as a separate threat, but viewed as a contributor to making the pipe more vulnerable to third party damage or outside force damage. Appendix SP-A presents detailed prescriptive requirements for managing the integrity of each of the nine threat categories. These requirements include the minimum data set needed to evaluate the presence of a threat, integrity assessment options, responses and mitigation approaches, assessment intervals and candidate performance measures.

The proposed rule also requires each operator to: (1) Collect data needed to evaluate each threat; (2) integrate numerous risk factors; (3) evaluate the susceptibility of each affected segment to each threat; and (4) prioritize affected segments in accordance with the ASME/ANSI B31.8S. The minimum sets of data needed to evaluate each of the nine threat categories are presented in Appendix SP-A of that standard.

Data integration requirements in the proposed rule should be satisfied by addressing the requirements in ASME/ANSI B31.8S, Section 4. Data integration must go beyond risk modeling to include consideration of specific locations where combination of these risk factors may lead to increased risk significance. Examples of data integration are presented in Section 4 of the referenced standard.

Human error analysis required by the proposed rule should follow the proposed training requirements.

If piping with certain material coating and environmental characteristics is in an HCA and the assessment shows it to be severely corroded, then other similar piping outside the high consequence area must also be evaluated, and mitigated as appropriate. This provision is critical in ensuring that the knowledge accumulated in implementing the integrity management requirements on pipe segments within HCAs is effectively utilized to improve integrity throughout the system.

The following additional requirements and guidance applies to the assessment process:

• Pipelines exposed to threats that represent higher risks should generally be assessed sooner than those with threats that represent lower risk. Thus, for the baseline assessment, 50% of covered segments (the higher risk segments) will have to be assessed within five years if pressure test, internal inspection or alternative equivalent technology is used, and within four years if direct assessment is used. The determination of which segments are at higher risk should be made using methods discussed in ASME B31.8S, Section 5. Here several alternative risk assessment approaches are described for use in ranking segments for integrity assessment.

• Pipelines that operate at a stress level less than 30% SMYS fail differently (

i.e.

, leak rather than rupture) from those operating at higher stress. Therefore, different integrity assurance techniques may be appropriate. These low stress pipes have been shown both by fracture mechanics analysis and by evaluation of failure experience data to fail by leaking, not by rupture. Therefore, the techniques most effective in assuring the integrity of these

pipelines could reasonably involve a combination of integrity assessment techniques and enhanced leak detection.

• The proposed rule applies to transmission pipelines, as that term is defined in § 192.5. There may be

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