American Gas AssociationCurrent Leak Inspection & Maintenance RegulationsMay 12, 2010RegulationProgramOverview49 CFR Part 192.481Atmospheric corrosioncontrol: MonitoringDescription:Leakage inspection and monitoring of aboveground piping to assess evidence of atmosphericcorrosion.Frequency:Onshore piping must be inspected once every 3 years at intervals not to exceed 39 months. Offshorepiping must be inspected once each yearat intervals not to exceed 15 months.Comments:Industry has completed extensive analysis of atmospheric corrosion inspection and leakage surveys.These studies have indicated that certain operators, depending on geographic location and atmosphericconditions, can apply for waivers to extend the inspection interval.49 CFR Part 192.613ContinuingSurveillanceDescription:Continual review of facilities to determine and take appropriate action concerning class location,failures, leakage history, corrosion, substantial changes in cathodic protection requirements, and other unusualoperating and maintenance conditions.Frequency:A class change review of transmission linesoperating over 40% SMYS and population centersserved by the distribution system shall be conducted every 5 years.Comments:Pipeline segments in unsatisfactory condition, but no immediate hazard exists, are reconditioned orphased out. For pipeline segments unable to be reconditioned or phased out, MAOP is reduced.49 CFR Part 192.705Transmission lines:PatrollingDescription:Patrol of surface area on and adjacent to the transmission line right-of-way for indications of leaksand other factors affecting safety.Frequency:The frequency of patrols is determined by the size of the line, the operating pressures, the classlocation, terrain, weather, and other relevant factors. The code provides a table to specify the maximum intervalsallowed between patrols, based on the class location.Comments:Operators integrate patrols and leakage surveys.49 CFR Part 192.706Transmission lines:Leakage surveysDescription:Leakage surveys of transmission lines using walking or mobile equipment.Frequency:Conducted at intervals not exceeding 15 months,but at least once each calendar year. Transmissionlines transporting gas without odorant are required toconduct leakage surveys on a more frequent basis,depending on the class location.Comments:Leakage surveys and patrols are integrated. Frequency based on Class 3 locations.49 CFR Part 192.721Distribution systems:PatrollingDescription:Patrol of distribution main lines for indicationsof leaks and other factors affecting safety.Frequency:The frequency is determined by the severity of the conditions which could cause failure or leakage,and the consequent hazards to public safety. In business districts patrolling must be conducted every 4 1⁄2 monthsand at least four times a year. Outside business districts patrolling must be conducted every 7 1⁄2 months and atleast twice a year.49 CFR Part 192.723Distribution systems:Leakage surveysDescription:Operators are required to conduct periodic leakage surveys of the distribution system.Frequency:Leakage surveys must be conducted in business districts, including tests of the atmosphere in gas,electric, telephone, sewer, and water system manholes, at cracks in pavement and sidewalks, and at otherlocations providing an opportunity for finding gas leaks, at intervalsnot exceeding 15 months, but at least once ayear. Leakage surveys must be conducted outside businessdistricts as frequently as necessary, but at least onceevery 5 calendar years at intervals notexceeding 63 months. Leakage surveysmust be conducted on cathodicallyunprotected distribution lines at least once every3 years at intervals not to exceed 39 months.49 CFR Part 192.905Gas Transmission LineIntegrity ManagementHCA Identification &ReviewDescription:Outlines the two methods for identifying HCAs. When new information on non-HCA pipelinesegments could satisfy the HCA definition, an evaluation is required to determine if segments should bereclassified as HCAs.Frequency:Not specified.Current Leak Inspection & Maintenance RegulationsRegulationProgramOverview49 CFR Part 192.921Gas Transmission LineIntegrity ManagementAssessmentsDescription:Outlines assessment methodology, prioritization ofsegments, assessment for particular threats, theuse of prior assessment completed, assessment of newly identified HCAs, newly installed pipe and assessment ofplastic transmission pipe determined to be susceptible to failure.Frequency:Complete baseline assessment of 50% of covered pipeline segments, beginning with highest risksegments, by December 17, 2007. Complete baseline assessments in 10 yearperiod ending December 17, 2012.Reassessments required every 7 years. Completed investigations and remedial actions as required.Comments:Operators utilize a variety of assessment methods, using knowledge of the operating system andengineering analysis to identify the methods best suited to address the threats identified to the covered segment.49 CFR 192.941Gas Transmission LineIntegrity ManagementLow StressAssessmentsDescription:Outlines assessment methods operator can use for transmission lines that operate below 30%SMYS. The assessment methods noted address external corrosion, cathodically protected pipe, unprotected pipeand internal corrosion. For unprotected pipe, operators are required to: 1) conduct leakage surveys at 4 monthintervals and 2) evaluate leak repair, inspection records and environment at 18 month intervals to identify activeexternal corrosion. Operators are required to: 1) assess for corrosiveagents once a year, 2) test the fluids removedfrom each storage field that may affecta covered segment once a year, 3) integrate data from the analysis andtesting with applicable internal corrosion leak records,incident reports, safety-related condition reports, repairrecords, patrol records, exposed pipe reports, and test records, and define and implement appropriate remediationactions every 7 years.Frequency:Gas analysis sampling bi-monthly. Integrate all sources of data related to internal corrosion every 7years.Comments:Monitoring is necessary to support the Company’s internal corrosion direct assessment program andits assertion that internal corrosion is not a threat.49 CFR 192.1007Required Elements ofa Distribution IntegrityManagement PlanDescription:Outlines required elements for a Distribution Integrity Management Plan(DIMP). DIMP requiresoperators to identify threats to the distribution pipeline. As part of this requirement, operators must considerincident and leak history, corrosion control records, continuing surveillance records, patrolling records,maintenance history, and excavation damage experience. DIMP also requires operators to measure performance,monitor results, and evaluate effectiveness. As part ofthis requirement, operators to review the number ofhazardous leaks either eliminated orrepaired (or total number of leaks ifall leaks are repaired when found),categorized by material.Frequency:Report the results of this analysis once a year.Comments:The final DIMP rule was released December 4, 2009. Operators are currently in the process ofdeveloping plans to meet the distribution integrity requirements.