The PSIA requires that integrity inspections be performed by one of the following methods: (1) an internal inspection device (or a “smart pig”); (2) hydrostatic pressure testing (filling the pipe with water and pressurizing it well above operating pressures to verify a safety margin); (3) direct assessment (digging up and visually inspecting sections of pipe selected based on various electronic measurements and other characteristics), or (4) “other alternative methods that the Secretary of Transportation determines would provide an equal or greater level of safety.” The pipeline operator is required by PHMSA regulations to repair all non-innocuous imperfections and adjust operation and maintenance practices to minimize “reportable incidents.”
Internal inspection devices/smart pigs are the primary means for assessing the integrity of natural gas transmission pipelines due to their versatility and efficiency. The other assessment methods enumerated in the 2002 reauthorization law are useful when smart pig technology cannot be effectively used.
Surveys conducted just prior to implementation of IMP suggested that almost one-third of natural gas transmission pipeline mileage could immediately accommodate smart pigs, another one-quarter could accommodate smart pigs with the addition of permanent or temporary launching and receiving facilities, and the remainder, about 40-45 percent, would either require extensive modifications or would not be able to accommodate smart pigs due to the physical or operational characteristics of the pipeline (i.e., primarily older pipelines that were not engineered to accept such inspection devices). Scheduling these extensive modifications to minimize consumer delivery impacts has been one of the most challenging aspects of the Integrity Management Program.
The natural gas pipeline industry will use hydrostatic pressure testing and direct assessment for segments of transmission pipeline that cannot be modified to accommodate smart pigs, or in other special circumstances that may arise. These methods have drawbacks. Primarily, they both require a pipeline to cease or significantly curtail gas delivery operations for a period of time. Hydrostatic testing also risks exacerbating some conditions while resolving others. Direct assessment necessitates excavation and subsequent disturbance of a landowner’s property and disrupts other infrastructure, including roads and other utilities, creating a risk and an inconvenience for the public.
Finally, while pipeline modification and inspection activity generally can follow a pre-arranged schedule, repair work is an unpredictable factor. A pipeline operator does not know ahead of time how many anomalies an inspection will find, how severe such anomalies will be, and how quickly they must be repaired. Only the completed inspection data can provide such information. Repair work often requires systems to be shut down even if the original inspection work did not affect system operations. The unpredictable nature of repair work must be kept in mind, especially during the baseline inspection period, when the number of required repairs is expected to be the greatest.
Integrity Management Program Progress to Date
PHMSA’s Integrity Management Program is meeting Congressional objectives by verifying the safety of gas transmission pipelines located in populated areas and identifying and removing potential problems before they occur. Based on two years of data since the issuance of the IMP rule, the trend is that natural gas transmission pipelines are safe and becoming safer.
The industry is generally on track to meet the 10-year baseline requirement for inspecting High Consequence Areas (HCAs). The industry is also expected to meet the risk-based prioritization of these HCA segments. This includes identifying the HCA segments with the highest probability of failure so that, by December of 2007, the industry has completed at least half of the total HCA assessments, by mileage, including the segments with the highest probability of failure.
The vast majority of the assessments to date have been completed using smart pig devices. These devices can only operate across large segments of pipeline – typically between two compressor stations. A 100-mile segment of pipeline may, for example, only contain five miles of HCA, but in order to assess that five miles of HCA, the entire 100-mile segment between compressor stations must be assessed. This dynamic is resulting in a large amount of “over-testing” on gas transmission systems. While it has completed assessments on 6,723 miles of HCA pipe thus far, the industry actually has inspected over 50,000 miles of pipe up through 2005 in order to capture the HCA segments. Any problems identified as a result of inspections, whether located in an HCA or not, are repaired. In summary, while only about seven percent of total gas transmission pipeline mileage is located in HCAs, it is anticipated that, due to over-testing situations, about 55 to 60 percent of total transmission mileage will actually be inspected during the baseline period.
PHMSA’s focus is on “time-dependent defects” - problems with pipelines that develop and grow over time and therefore can be managed by re-inspections on a periodic basis. The most prevalent time-dependent defect is corrosion. As such, the IMP effort focuses most intently on corrosion identification and mitigation.
As noted, the primary reason for pipeline incidents is excavation damage by third parties (Excavation was the cause of more than 85 percent of the incidents in HCA areas during the PHMSA study period). Most excavation damage incidents result in an immediate pipeline failure. Periodic assessments are unlikely to reduce the number of these time-independent incidents in any significant way.
Even though it is still early in the baseline assessment period, the data suggest a very positive conclusion regarding the present state of the gas transmission pipeline system and the effectiveness of the Integrity Management Program. The number of incidents associated with time-dependent defects in HCA areas is fairly low. As critical time-dependent defects are found and repaired, these incident and leak numbers should approach zero since the gestation period for these defects is significantly longer than the re-assessment interval. By completing identified immediate and scheduled repairs in a timely fashion, the pipeline industry is reducing the possibility of future reportable incidents or leaks.
Many of the gas pipelines being inspected under this program are 50 to 60 years old. While is it often hard for non-engineers to appreciate, well-maintained pipelines can operate safely for many decades. One important benefit of the Integrity Management Program is the verification and re-establishment of the known safety factors on these older pipeline systems.
The Government Accountability Office (GAO) has reported that the IMP benefits pipeline safety. The GAO Report concludes:
The gas integrity management program has made a promising start. The program’s risk-based approach is supported by industry, state pipeline agencies, safety advocates, and operators. Although the national transmission pipeline system is extensive, much of the population that is potentially affected by a pipeline event is concentrated in highly populated areas, which will be provided additional protection through the program. Thus far, operators are successfully implementing the critical assessment and repair requirements, and their documentation concerns should be resolved as operators gain experience with the program and receive feedback during inspections. While the progress in implementing the program to date is encouraging, PHMSA and state oversight will be critical to ensure that operators continue to effectively implement integrity management. As the program matures, PHMSA’s performance measures should allow the agency to quantitatively demonstrate the program’s impact on the safety of pipelines. However, relatively minor changes in how some of the measures are reported could help improve their usefulness and PHMSA’s ability to analyze and demonstrate the program’s impact over time.
GAO, Integrity Management Benefits Public Safety, but Consistency of Performance Measures Should Be Improved, GAO-06-946 (Washington, D.C.: September 8, 2006).