The Office of Pipeline Safety Proposes Regulations to Require Gas Pipeline Operators to Develop Integrity Management Programs

On January 28, 2003, the Department of Transportation’s Research and Special Programs Administration and Office of Pipeline Safety issued a notice of proposed rulemaking that would require gas pipeline operators to develop integrity management programs for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The proposed rule incorporates the requirements of the Pipeline Safety Improvement Act of 2002 that was enacted on December 17, 2002.

What is the purpose of the proposed rule? The proposed rule is intended to ensure pipeline integrity by requiring owners and operators of gas transmission lines to (1) implement comprehensive integrity management plans; (2) conduct baseline assessments and periodic reassessments to identify and evaluate potential threats to pipelines; (3) remediate significant defects discovered during these processes; and (4) continually monitor program effectiveness so that modifications can be recognized and implemented.

Who must comply? The proposed rule would apply to gas transmission pipelines, including those that transport petroleum gas, hydrogen, and other gas products. The proposed rule would not cover gas gathering lines or gas distribution lines.

What pipeline segments are covered? The proposal would require pipeline operators to develop written integrity management programs that address risks to each covered pipeline segment, i.e. those segments that could affect a high consequence area (HCA) in the event of a failure (Covered Segment). Under the existing regulations, an HCA generally is defined as any Class 3 or Class 4 location, or areas where a pipeline is located within a specified distance from an “identified site” (e.g., facilities with persons who are mobility-impaired, confined, or hard to evacuate, such as hospitals, churches, schools, or prisons, and places where people gather for recreational or other purposes). Such distances are based on a pipeline’s diameter and operating pressure. The proposed rule would expand this definition by including areas with a “threshold radius” (i.e., an additional area of safety beyond the distance calculated as the potential impact radius) of 1,000 feet or larger that have a cluster of 20 or more buildings intended for human occupancy. However, the proposed rule would restrict the existing definition by excluding from HCAs Class 3 and Class 4 locations that are deemed “moderate risk” areas (i.e., areas not within the “potential impact zone”). OPS requests comments on its proposal to create moderate risk areas.

OPS also is proposing new definitions based on specified mathematical equations, including “potential impact circle,” “potential impact radius,” “threshold radius,” and “potential impact zone.” These calculations are intended to enable an operator to determine the actual area within an HCA that likely would be affected by pipeline failure.

What are the requirements for developing integrity management programs? The proposed rule would require gas pipeline operators to develop and follow written integrity management programs that address the risks on each Covered Segment within one year of the effective date of the final rule. Note, however, that independent from this proposed rule, the 2002 Pipeline Safety Act requires gas pipeline owners and operators to develop integrity management programs prior to December 17, 2004, irrespective of whether OPS promulgates implementing regulations. These integrity management programs, which must be kept on site for OPS inspection, must comply with extensive requirements set forth in the proposed rule, as well as in the ASME/ANSI B31.8S Code. The proposed rule allows operators to deviate from certain requirements but only where an operator can demonstrate that it has an exceptional performance-based integrity management program, as specified in the proposed rule. The proposed rule further requires appropriate training for an operator’s supervisory personnel over the integrity management program. Thus, within one year of implementation of the final rule, each operator must do the following:

• Each operator must identify all HCAs and the potential impact zone within the HCA, as well as all moderate risk areas.
• Each operator must develop a pipeline integrity management program addressing each of the fourteen required elements. Specifically, integrity management programs must include: (1) identification of all Covered Segments and their accompanying “potential impact zones;” (2) a baseline assessment plan for Covered Segments; (3) identification of potential threats to Covered Segments, including a “risk assessment” to evaluate the failure likelihood of each Covered Segment; (4) a direct assessment plan, if applicable; (5) provisions for remediating conditions found during an integrity assessment; (6) a process for continual evaluation and assessment; (7) preventive and mitigative measures to protect HCAs; (8) performance measures to assess whether the integrity management program is effective; (9) record keeping requirements; (10) a management of change process; (11) a quality assurance process; (12) a communication plan, including a process for addressing safety concerns raised by OPS; (13) a process for providing a copy of an operator’s integrity management program to a State authority where OPS has an interstate agent agreement; and (14) a process for ensuring that each integrity assessment is conducted in a manner that minimizes environmental and safety risks.
• Each operator must develop a baseline assessment plan. Baseline assessment plans must identify (1) segments to be assessed and threats for each segment; (2) methods selected to assess each pipeline segment; (3) the basis for selecting each assessment method; and (4) a schedule for completing the assessment. A pipeline operator also would be required to demonstrate that it is conducting the assessment in a manner that minimizes environmental and safety risks.

Regarding the identification of threats to each Covered Segment, potential threats that an operator must consider include, but are not limited to, the threats listed in ASME/ANSI B31.8S, section 2 and the following: (1) time dependent threats, such as internal corrosion, external corrosion, and stress corrosion cracking; (2) static or resident threats, such as fabrication or construction defects; (3) time dependent threats, such as third party damage and outside force damage; and (4) human error. An operator must gather and integrate data and information on the entire pipeline that could be relevant to the Covered Segment, including both on the Covered Segment and similar segments, information regarding past incident history, corrosion control records, continuing surveillance records, patrolling records, maintenance history, and all other specific conditions specific to each pipeline. An operator will use the risk assessment to prioritize the segments for baseline and continual re-assessments, and in determining what additional preventive and mitigative measures are needed.

OPS proposes to permit operators to use one or a combination of four assessment methods: (1) internal inspection tools – inline and pig testing; (2) pressure tests; (3) direct assessments – a process that includes data gathering, indirect examination, direct examination, and post-assessment evaluation; or (4) other proven technologies. An operator must select the method or methods best suited to address the threats identified to each segment. Direct assessment is intended to be a supplemental method, but may be a primary method where inline inspection and pressure testing are not possible or economically feasible, where customers would be substantially impacted from use of other methods, or where the pipeline segment operates at a low stress. Significantly, if an operator intends to use direct assessment methods, it must develop direct assessment plans describing how they will be used. The proposed rule describes several direct assessment methods and establishes extensive and complex requirements governing their use.

• As part of the Integrity Management Program, each operator must adopt a plan for continual integrity assessment and evaluation once the baseline assessment has been completed.
• As part of the Integrity Management Program, each operator must develop processes for continually improving and developing its framework into an ongoing integrity management program. This should include methods to measure whether the program is effective in assessing and evaluating the integrity of each Covered Segment and in protecting the HCAs.

What is the proposed timeframe for implementing a Baseline Assessment? The proposed rule would require operators to complete baseline assessments within specified timeframes that vary depending on the assessment method chosen by the operator. Operators must assess highest risk segments first. These timeframes, which are consistent with those mandated in the 2002 Pipeline Safety Act, are as follows:

If an area is newly identified as an HCA, an operator must include it in its baseline assessment within one year from the date of identification. The baseline assessment of any newly identified HCA must be completed within ten years (seven years if direct assessment is used) from that date.

What action must be taken to address discovered integrity issues? The proposed rule would require operators to take “prompt action” to address and remediate all “anomalous conditions” discovered through the assessment process. All conditions that could reduce a pipeline’s integrity must be remediated. Operators would be required to determine the existence of a condition within 180 days of conducting an integrity assessment, except where impracticable. Except in the cases where the proposed rule requires a condition to be repaired immediately (in which case operating pressure must be temporarily reduced or the pipeline shut down until the operator completes repair of such conditions), and those conditions that require remediation within 180 days, operators are required to complete remediation of conditions pursuant to the schedule provided in ASME/ANSI B31.8S.

What additional preventive and mitigative measures must an operator take to protect the HCAs? Each operator must adopt additional preventative and mitigative measures to prevent pipeline failure and to mitigate the consequences of pipeline failure in an HCA. Such measures will depend on the threats identified for each Covered Segment. The proposed rule provides that these measures include, but are not limited to, installation of Automatic Shut-off Valves or Remote Control Valves, installation of computerized monitoring and leak detection systems, replacing pipe segments with pipe of heavier wall thickness, providing additional training to personnel on response procedures, conducting drills with local emergency responders and implementing additional extensive inspection and maintenance programs.

After completing the baseline integrity program, are there continuing requirements? The proposed rule would require operators to continually evaluate and reassess Covered Segments as frequently as necessary to assure pipeline integrity. Operators are required to establish a schedule of reassessment intervals pursuant to certain data integration and various calculations, but in any event, each Covered Segment must be reassessed at a seven-year interval (if the specified calculations establish an interval period greater than seven years, operators must conduct a “confirmatory direct assessment” of the segment within the seven year period and then conduct the scheduled reassessment at the time period determined by the calculation). OPS is seeking comment with respect to whether longer reassessment periods are appropriate for low stress lines. An operator’s integrity management program also must include methods for measuring whether it is effective in assessing and evaluating integrity of Covered Segments and in protecting HCAs. An operator’s measures must include the four overall performance measures specified in ASME/ANSI B31.8S. The proposed rule would require such performance measures to be accessible in real time to OPS and state pipeline safety enforcement officials.

Are there record keeping requirements? The proposed rule would require operators to maintain: (1) a written baseline assessment plan; (2) a written integrity management program; (3) documents to support the decisions, analyses, and processes developed to implement and evaluate the baseline assessment plan and the integrity management program; (4) documents that demonstrate that personnel have the required training, including a description of the training program; (5) documents necessary to carry out the requirements for a direct assessment plan, if applicable; and (6) documents demonstrating the integrity management plan has been provided to the interstate agent, and that any safety concerns raised by OPS on behalf of an interstate agent have been addressed.