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Improve pipeline safety through:
- accelerating the integrity assessment of pipelines in High Consequence Areas,
- improving integrity management systems within companies,
- improving the government's role in reviewing the adequacy of integrity programs and plans, and
- providing increased public assurance in pipeline safety.
The rule applies to gas transmission operators jurisdictional to 49 CFR Part 192. This rule becomes effective February 14, 2004.
- Provides enhanced protection for defined High Consequence Areas. Operators may identify High Consequence Areas using either of two methods:
- Method 1: A pipeline segment is located in a high consequence area if any of the following apply:
- A Class 3 location under 192.5, or
- A Class 4 location under 192.5, or
- Any area outside a Class 3 or Class 4 location where the potential impact radius is greater than 660 feet (200 meters), and the area within a potential impact circle contains 20 or more buildings intended for human occupancy; or
- The area within a potential impact circle containing an identified site.
- Method 2: A pipeline segment is located in a high consequence area if any of the following apply:
- The area within a potential impact circle contains 20 or more buildings intended for human occupancy, or
- The area within a potential impact circle contains an identified site.
- The terms "potential impact radius," "potential impact circle," and "identified site" are defined in the rule.
- When using potential impact circles, the length of the high consequence area extends axially along both directions of the pipe to the edge of the potential impact circles that define the boundaries of the high consequence area (i.e., the boundary of the high consequence area is defined by the circumference of the potential impact circle, not its center point).
- When identifying high consequence areas based on building counts within a potential impact circle that is greater than 660 feet (200 meters) in radius, the operator may elect to prorate the building count criteria and use building counts within a circle of 660 ft radius. An exact formula for this exception is provided in the rule. An operator may elect to use this exception only until December 17, 2006, after which time building counts must be completed for the entire potential impact circle area.
- Gas transmission pipeline operators must develop a written Integrity Management Plan that includes:
- Identification of all covered segments
- A Baseline Assessment Plan to assure the integrity of all covered segments
- A Framework that contains all required elements of the Integrity Management Program
- A process to assure continual improvement to the program
- Provisions to implement industry standards invoked by reference
- A process to document (and notify OPS as required) any changes to its program.
- A gas transmission pipeline operator’s Integrity Management Program must include all of the following program elements:
- Identification of all high consequence areas
- Baseline Assessment Plan
- Identification of threats to each covered segment, including by the use of data integration and risk assessment
- A direct assessment plan, if applicable
- Provisions for remediating conditions found during integrity assessments
- A process for continual evaluation and assessment
- A confirmatory direct assessment plan, if applicable
- A process to identify and implement additional preventive and mitigative measures
- A performance plan including the use of specific performance measures
- Recordkeeping provisions
- Management of Change process
- Quality Assurance process
- Communication Plan
- Procedures for providing to regulatory agencies copies of the risk analysis or integrity management program
- Procedures to ensure that integrity assessments are conducted to minimize environmental and safety risks
- A process to identify and assess newly identified high consequence areas
- Operators may deviate from certain time frame requirements related to reassessment intervals and certain time frame requirements related to remediation, if it demonstrates exceptional performance of its integrity management program, by meeting or exceeding the performance-based requirements of ASME B31.8S. PHMSA has produced guidance for pipeline operators to consider when evalutating and determining inspection reassessment intervals.
- An operator’s integrity management program must document minimum qualification requirements for the following:
- Supervisory personnel
- Persons that carry out integrity assessments and evaluate assessment results
- Persons responsible for additional preventive and mitigative actions
- An operator must identify and evaluate all potential threats to the covered segment. The operator must collect and integrate data from the entire pipeline that could be relevant to the covered segment and conduct a risk assessment in accordance with ASME/ANSI B31.8S.
- If an operator identified any of the following threats, it must take specific actions to address the threats:
- Third Party Damage – Operators must use data integration from the assessment of other threats to identify potential third party damage and take additional preventive and mitigative action
- Cyclic Fatigue – Operators must use cyclic fatigue analysis to prioritize baseline assessments and reassessments
- Manufacturing and Construction Defects – Operators must prioritize a segment containing manufacturing or construction defects as a high risk segments unless it shows by analysis that the defect is stable and that the risk of failure is low
- ERW Pipe – Covered segments containing low frequency electric resistance welded pipe or lap welded pipe must be prioritized as a high risk segment for the baseline assessment or reassessment, and assessed using technologies proven to be capable of assessing seam integrity and of detecting seam corrosion anomalies.
- Corrosion – If corrosion is identified, all similar pipeline segments (both covered and non-covered) with similar coating and environmental characteristics must be evaluated and remediated, as necessary.
- The Baseline Assessment Plan must:
- Identify potential threats to each covered segment
- Identify methods to assess integrity based on the threats identified for each covered segment (acceptable methods include internal inspection, pressure testing, direct assessment, or other technology that the operator demonstrates provides an equivalent level of understanding of line integrity)
- Identify a schedule for completing the assessments including the risk factors used in determining schedule priorities
- If applicable, include a direct assessment plan, appropriate for the threats identified for the covered segments
- Include a procedure for ensuring that the baseline assessments are conducted in a manner that minimizes environmental and safety risks
- Operators must complete the baseline assessment of 50% of its covered segments, beginning with the highest risk segments, by December 17, 2007 and 100% of its covered segments by December 17, 2012.
- An operator may use assessments completed before December 17, 2002 as a baseline assessment if the prior assessment meets the requirements of Subpart O and anomalies have been remediated in accordance with Subpart O. In this case, however, a reassessment must be completed by December 17, 2009.
- Direct assessment may be used for the following threats:
- External Corrosion (Must comply with NACE RP0502-2002)
- Internal Corrosion (Must comply with ASME/ANSI B31.8S)
- Stress Corrosion Cracking (Must comply with ASME/ANSI B31.8S)
- The rule requires that certain defects be remediated within prescribed time limits. For Immediate Conditions, a pressure reduction must be implemented until the condition is repaired.
- Immediate Conditions:
- Remaining strength is less than or equal to 1.1 x MAOP
- A dent with any indication of metal loss, cracking, or a stress riser
- An anomaly judged to require immediate action
- One Year Conditions:
- Dent > 6% (>0.50" for pipe diameter less than NPS 12) between 8:00 and 4:00 (upper 2/3 of pipe)
- Dent > 2% (>0.25" for pipe diameter less than NPS 12) that affects curvature at a girth weld or a longitudinal seam weld
- Monitored Conditions (Remediation not required):
- Dent > 6% (>0.50" for pipe diameter less than NPS 12) between 4:00 and 8:00 (lower third of pipe)
- Dent > 6% (>0.50" for pipe diameter less than NPS 12) between 8:00 and 4:00 (upper 2/3 of pipe) and engineering analysis demonstrates that critical strain levels are not exceeded
- Dent > 2% (>0.25" for pipe diameter less than NPS 12) that affects curvature at a girth weld or a longitudinal seam weld and engineering analysis demonstrates that critical strain levels are not exceeded
- Operators must conduct risk assessments to identify additional preventive and mitigative measures to protect high consequence areas and enhance public safety. Such additional measure include, but are not limited to:
- Installing Automatic Shut-Off Valves or Remote Control Valves
- Installing computerized monitoring and leak detection systems
- Replacing segments with heavier wall pipe
- Additional training
- Conducting drills with local emergency responders
- Implementing additional inspection and maintenance programs
- Enhancements to damage prevention programs
- An operator must perform a periodic evaluation based on data integration and risk assessment and implement a program to continually assess the integrity of its pipelines. Mandatory reassessment intervals are summarized in the following table. PHMSA has producted guidance for pipeline operators to consider when evalutating and determining inspection reassessment intervals.
|Maximum Reassessment Interval
||Pipeline operating at or above 50% SMYS
||Pipeline operating at or above 30% SMYS, up to 50% SMYS
||Pipeline operating below 30% SMYS
|Internal Inspection Tool, Pressure Test or Direct assessment
|Confirmatory Direct Assessment
|Low stress reassessment
||7 years + ongoing actions specified in §192.941
(*) A Confirmatory direct assessment as described in §192.931 must be conducted by year 7 in a 10-year interval and years 7 and 14 of a 15-year interval.
(**) A low stress reassessment or Confirmatory direct assessment must be conducted by years 7 and 14 of the interval.
- Waivers to the maximum reassessment intervals can be requested in two cases:
- Unavailability of internal inspection tools
- Inability to maintain product supply if the assessment is performed within the required interval
- An operator’s integrity management program must include methods to measure the effectiveness of its program. As a minimum, it must include the performance measures specified in ASME/ANSI B31.8S, and submit its performance measures to OPS semi-annually.
- A written integrity management program and records that demonstrate compliance with Subpart O must be maintained for the life of the pipeline and will be reviewed by OPS and/or State regulators during inspections.