Gas Transmission Integrity Management: Performance Measure Reporting
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Protecting America’s High Consequence Areas (HCAs)
Beginning in 2004, gas transmission pipeline operators have been required to submit performance measure reports covering their pipeline infrastructure and their Integrity Management programs. PHMSA uses data from these reports—due on March 15th for the previous calendar year—to monitor and report on industry progress in meeting the requirements of the Gas (Transmission) IM Rule, to prioritize operators for future agency inspections, and to respond to inquiries about PHMSA’s oversight program. For a basic overview of the progress being made under the Gas IM Rule, please refer to the Quick Facts below.
Quick Facts for Gas Transmission Integrity Management
The Gas Transmission IM Performance National Summary depicts various Incident, Failure, and Leak rates on a per mile of pipeline basis. Total HCA mileage is shown, and Incidents, Failures, and Leaks in HCAs are depicted on a per HCA mile basis. Incidents as reported by operators on 30-day Incident Reports are shown along with the Incidents that operators reported on their Annual Reports. Total Non-HCA mileage is shown as well, along with Leaks in non-HCAs on a per non-HCA mile basis.
The Gas Transmission IM Assessment National Summary depicts, by year, the amounts of HCA (High Consequence Area) mileages and both the baseline assessment and ensuing reassessment miles completed on HCA segments of the pipeline. This table also depicts the number of Immediate and Scheduled Condition Repairs, as well as Pressure Test Failure Repairs, made within segments identified as those that could potentially impact an HCA.
The plot below, entitled "Cumulative Baseline and Reassessment Miles", shows the miles of pipelines that have been assessed or, beginning in 2008, reassessed under the Gas IM Rule. A single “assessment” often uses more than one inspection tool, device, or test to adequately assess a particular pipeline. An assessment is complete when all of the required tools, devices, or tests have successfully evaluated the pipeline.
The plot below, entitled "HCA Repairs", shows the total number of repairs made in HCA segments of the pipeline which have been completed in a given year under the Gas IM Rule. These include the specifically-defined types of prioritized repairs occurring within HCA segments that are required by the Gas IM Rule, namely, Immediate and Scheduled repairs (made as a result of In-Line Inspections, External Corrosion Direct Assessment, Internal Corrosion Direct Assessment, Stress Corrosion Cracking Direct Assessment, and other inspection techniques), as well as repairs made as a result of pressure tests that have been conducted.
The pie chart below, entitled "HCA Repairs by Type", depicts the percentages of the two types of HCA repairs (Immediate and Scheduled) made as a result of In-Line Inspections, External Corrosion Direct Assessment, Internal Corrosion Direct Assessment, Stress Corrosion Cracking Direct Assessment, and other inspection techniques carried out since the Gas IM Rule’s inception. (Note: Excluded from this chart are repairs resulting from pressure tests.)
Definitions:
Incidents are releases of gas from a pipeline that results in one or more of the following consequences: a death or personal injury necessitating in-patient hospitalization; estimated property damage of $50,000 or more; the unintentional estimated gas loss of three million cubic feet or more; or, an event that is significant in the judgment of the operator, even though it did not meet the aforementioned criteria.
Leaks are unintentional escapes of gas from the pipeline that are not reportable as Incidents. A non-hazardous release that can be eliminated by lubrication, adjustment, or tightening is not a leak. Operators should report the number of leaks repaired based on the best data they have available. For sections replaced but retired in place, operators should consider leak survey information to determine, to the extent practical, the number of leaks in the replaced section.
Failure is defined in ASME/ANSI B31.8S as a general term used to imply that a part in service: has become completely inoperable, is still operable but is incapable of satisfactorily performing its intended function; or has deteriorated seriously, to the point that it has become unreliable or unsafe for continued use. Failures that result in an unintentional release of gas should be reported as leaks.
Immediate Repair – More specifically defined in 49 CFR 192.933(d)(1), these repairs are deemed important enough to require a temporary reduction in operating pressure or shutdown until such time as the urgent repair is completed.
Scheduled Condition Repair – More specifically defined in 49 CFR 192.933(c), (d)(2), and (d)(3), these repairs include One-year and Monitored Conditions, as well as other scheduled conditions, and are deemed less urgent than Immediate Repairs. These repairs are to be prioritized for completion according to an operator-defined schedule based on 49 CFR 192.933(c).
For all Immediate and Scheduled Condition Repairs - These repairs result from In-Line Inspections (ILI), External Corrosion Direct Assessment (ECDA), Internal Corrosion Direct Assessment (ICDA), Stress Corrosion Cracking Direct Assessment (SCCDA), and other inspection techniques used by operators. In all cases, operators must notify PHMSA (or PHMSA’s state partner agencies, depending on who has jurisdiction) and take additional mitigating action in the event the repair cannot be completed within the described deadlines. Additional repairs can result from Pressure Tests when they are conducted by operators (see definition below).
Pressure Test Failure Repair – These repairs result when failures occur due to pressure tests conducted by operators.
Note: With the publication of the Nov. 26, 2010 rule “Pipeline Safety: Updates to Pipeline and Liquefied Natural Gas Reporting Requirements”, PHMSA discontinued use of the Gas Integrity Management (IM) Semi-Annual Performance Measures Report by merging that reporting onto the Annual Report for gas transmission and gathering pipeline systems. In both the old and the new form, the various repair types were as defined in §192.933. Some repairs could cover multiple anomalies, so 2010 information could have potential skewing compared to previous year’s IM reporting. However, the new reporting aligns with that for hazardous liquid IM reporting, and PHMSA believes the more detailed information will enable better monitoring and analysis of overall IM performance.