DOT/OPS issued the long anticipated pipeline integrity management rule for gas transmission pipelines on December 12, 2003. The rule is contained in a new Subpart O of §192. The rule is very detailed and specifies requirements for Operators in performing assessments, data collection, integration and analysis, repair and remediation action, implementation of preventative and mitigation measures, assessments intervals and a modified definition of what constitutes a High Consequence Area from that published in the draft rule last January. The rule also makes extensive use of and reference to ASME B31.8S-2001. DOT/OPS has established a website at primis.rspa.dot.gov/gasimp containing the rule’s text and other relevant gas integrity management topics.
One of the most important elements of the new rule is the identification of transmission pipeline segments located in HCA’s. Operators are given the option of two methods to make this determination. These methods may be used exclusively or in combination. One method defines HCA’s as (i) Class 3 or 4 locations, (ii) an area outside a Class 3 or 4 location having a Potential Impact Radius greater than 660 feet and containing more than 20 buildings intended for human occupancy within the Potential Impact Circle or (iii) an area within a Potential Impact Circle containing an Identified Site as defined in §192.903. The alternative method specified HCA’s as the area within (i) a Potential Impact Circle containing 20 or buildings intended for human occupancy or (ii) an Identified Site. Pipeline segments located in HCA’s are called Covered Segments. The algorithm to calculate a Potential Impact Radius is specified in the rule.
The rule also specifies deadlines for implementing a gas pipeline integrity management plan. An Operator of Covered Segments is required to develop and implement a written integrity management plan by December 17, 2004. An Operator’s plan must contain the sixteen elements specified in §192.911. An Operator must complete initial integrity assessments for 50% of the highest risk Covered Segments by December 17, 2007 and the remaining 50% by December 17, 2012. An assessment made prior to December 17, 2002 may be used as an initial if the assessment activities satisfy requirements of the rule including remedial actions.
An Operator is required to determine the risk associated with each Covered Segment. This includes evaluation of several classes of threats to pipeline integrity. These consist of time dependent threats such as internal and external corrosion, static threats such as construction defects, time dependent threats such as third party damage and human error. Consequences of a leak or rupture must also be considered when determining the risk for a Covered Segment.
Operators have some choices in selecting the assessment methods to be used. The choice is to be governed by the method best suited to address the threats identified for a Covered Segment. An Operator may use in-line inspection tools, pressure testing in accordance with Subpart J of §192, direct assessment or other technology that the Operator demonstrates provides equivalent understanding of the pipe’s condition. Four sections of the rule are devoted to the use of direct assessment.
Operators are required to take prompt action to address all anomalous conditions discovered during an integrity assessment. §192.933 contains requirements for establishing Discovery of a Condition, schedule for evaluation and remediation and special requirements for scheduling remediation of immediate repair, one year and monitored conditions.
Requirements for preventative and mitigation measures to protect HCA’s are contained in §192.935. §192.937 specifies elements of an Operator’s process for continual evaluation and assessment.
§192.939 establishes the required reassessment intervals for Covered Segments. The minimum reassessment interval is set at seven years. However depending on the MAOP hoop stress/SMYS ratio, an Operator may extend the time period for completing one or more subsequent assessments using in-line inspection tools, pressure testing or direct assessment by using Confirmatory Direct Assessment (described in §192.931) within specified time intervals. §192.939 contains a table that shows the reassessment intervals allowed by the rule when using Confirmatory Direct Assessment.
The rule also contains requirements for methods to measure a program’s effectiveness (§192.945), record keeping requirements (§192.947) and OPS notification procedures (§192.949).
RCP has developed and / or assisted pipeline operators with 28 pipeline integrity management programs to-date. Our breadth of experience enables us to develop quality integrity management plans, on time and within budget. If you require assistance with any portion (or all) of your integrity management program, please contact our Vice President of Business Development, Mr. Dan Shelledy, at email@example.com.