American Gas Association 

Current Leak Inspection & Maintenance Regulations 

May 12, 2010 

Regulation Program Overview

49 CFR Part 192.481 Atmospheric corrosion 

control: Monitoring 

Description: Leakage inspection and monitoring of aboveground piping to assess evicorrosion. Frequency: Onshore piping must be inspected once every 3 years at intervals not to e

piping must be inspected once each year at intervals not to exceed 15 months. 

Comments: Industry has completed extensive analysis of atmospheric corrosion insp

These studies have indicated that certain operators, depending on geographic location conditions, can apply for waivers to extend the inspection interval. 

49 CFR Part 192.613 Continuing 

Surveillance 

Description: Continual review of facilities to determine and take appropriate action c

failures, leakage history, corrosion, substantial changes in cathodic protection requireoperating and maintenance conditions. Frequency: A class change review of transmission lines operating over 40% SMYS 

served by the distribution system shall be conducted every 5 years. Comments: Pipeline segments in unsatisfactory condition, but no immediate hazard 

phased out. For pipeline segments unable to be reconditioned or phased out, MAOP 

49 CFR Part 192.705 Transmission lines: 

Patrolling 

Description: Patrol of surface area on and adjacent to the transmission line right-of-w

and other factors affecting safety. Frequency: The frequency of patrols is determined by the size of the line, the operatilocation, terrain, weather, and other relevant factors. The code provides a table to speallowed between patrols, based on the class location. Comments: Operators integrate patrols and leakage surveys. 

49 CFR Part 192.706 Transmission lines: 

Leakage surveys 

Description: Leakage surveys of transmission lines using walking or mobile equipmeFrequency: Conducted at intervals not exceeding 15 months, but at least once each clines transporting gas without odorant are required to conduct leakage surveys on a mdepending on the class location. Comments: Leakage surveys and patrols are integrated. Frequency based on Class 3 

49 CFR Part 192.721 Distribution systems: 

Patrolling 

Description: Patrol of distribution main lines for indications of leaks and other factorFrequency: The frequency is determined by the severity of the conditions which couand the consequent hazards to public safety. In business districts patrolling must be cand at least four times a year. Outside business districts patrolling must be conducted least twice a year. 

49 CFR Part 192.723 Distribution systems: 

Leakage surveys 

Description: Operators are required to conduct periodic leakage surveys of the distribFrequency: Leakage surveys must be conducted in business districts, including tests electric, telephone, sewer, and water system manholes, at cracks in pavement and sidlocations providing an opportunity for finding gas leaks, at intervals not exceeding 15 year. Leakage surveys must be conducted outside business districts as frequently as nevery 5 calendar years at intervals not exceeding 63 months. Leakage surveys must b

unprotected distribution lines at least once every 3 years at intervals not to exceed 39 

49 CFR Part 192.905 Gas Transmission Line 

Integrity Management HCA Identification & Review 

Description: Outlines the two methods for identifying HCAs. When new informatio

segments could satisfy the HCA definition, an evaluation is required to determine if s

reclassified as HCAs. Frequency: Not specified. 
Current Leak Inspection & Maintenance Regulations 

Regulation Program Overview

49 CFR Part 192.921 Gas Transmission Line 

Integrity Management Assessments 

Description: Outlines assessment methodology, prioritization of segments, assessmeuse of prior assessment completed, assessment of newly identified HCAs, newly instaplastic transmission pipe determined to be susceptible to failure. Frequency: Complete baseline assessment of 50% of covered pipeline segments, begsegments, by December 17, 2007. Complete baseline assessments in 10 year period e

Reassessments required every 7 years. Completed investigations and remedial actionComments: Operators utilize a variety of assessment methods, using knowledge of thengineering analysis to identify the methods best suited to address the threats identifi

49 CFR 192.941 Gas Transmission Line 

Integrity Management Low Stress Assessments 

Description: Outlines assessment methods operator can use for transmission lines thaSMYS. The assessment methods noted address external corrosion, cathodically proteand internal corrosion. For unprotected pipe, operators are required to: 1) conduct leaintervals and 2) evaluate leak repair, inspection records and environment at 18 month external corrosion. Operators are required to: 1) assess for corrosive agents once a yefrom each storage field that may affect a covered segment once a year, 3) integrate datesting with applicable internal corrosion leak records, incident reports, safety-related records, patrol records, exposed pipe reports, and test records, and define and implemactions every 7 years. Frequency: Gas analysis sampling bi-monthly. Integrate all sources of data related tyears. Comments: Monitoring is necessary to support the Company’s internal corrosion dirits assertion that internal corrosion is not a threat. 

49 CFR 192.1007 Required Elements of 

a Distribution Integrity Management Plan 

Description: Outlines required elements for a Distribution Integrity Management Plaoperators to identify threats to the distribution pipeline. As part of this requirement, oincident and leak history, corrosion control records, continuing surveillance records, pmaintenance history, and excavation damage experience. DIMP also requires operatomonitor results, and evaluate effectiveness. As part of this requirement, operators to 

hazardous leaks either eliminated or repaired (or total number of leaks if all leaks are 

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 cur

developing plans to meet the distribution integrity requirements.