NTSB Study Seeks Changes to Gas Transmission Integrity Programs

March 2015, Vol. 242, No. 3

Rita Tubb, Executive Editor

A new National Transportation Safety Board (NTSB) study calls for major changes to integrity management (IM) programs of gas transmission pipelines in high-consequence areas (HCAs).

Released were 33 findings and 28 recommendations that highlight shortcomings of the gas transmission IM system and underscored HCA incidents attributed to causes other than corrosion and material defects in pipe or welds, which increased from 2010-13. The recommendations address a broad range of improvements. These include broadened use of inline inspection which detects the most potential problem areas per mile of pipeline.

The recommendations emphasize closer state to-state and federal-state cooperation among inspectors, and call for expanded and improved resources and guidance at the federal level, including improvements to the National Pipeline Mapping System and better integration of geographic information system (GIS) technology.

The findings indicate that while PHMSA’s IM requirements have kept the rate of corrosion and material failures of pipe or welds low, there is no evidence of decline in the overall occurrence of gas transmission pipeline incidents in HCA pipelines. Several areas were listed to improve safety of gas transmission pipelines in HCAs.

The study found that IM programs are complex, requiring expert knowledge and integration of multiple technical disciplines including engineering, material science, GIS, data management, probability and statistics, and risk management.

This complexity requires pipeline operators and inspectors to have a high level of knowledge. As a result, this makes integrity management program development difficult to achieve as well as proper evaluation of operators’ compliance with those requirements. Moreover, the study found that PHMSA’s resources in guiding both operators and inspectors need to be expanded and improved.

As noted in the report, the effectiveness of an IM program depends on many factors, including how well threats are identified and risks are estimated. Aspects of the operators’ threat identification and risk assessment processes were also found needing improvement.

Of the four different integrity assessment methods (pressure test, direct assessment, inline inspection [ILI], and other techniques), ILI yields the highest per-mile discovery of pipe anomalies. Direct assessment by itself was found to have numerous limitations. However, compared to their interstate counterparts, intrastate pipeline operators rely more on direct assessment and less on ILI.

Some of NTSB’s key findings and recommendations:

• There had been a gradual increasing trend in the gas transmission significant incident rate between 1994 and 2004 but this has leveled off since the implementation of the IM program in 2004.

• From 2010-2013, the intrastate gas transmission pipeline HCA incident rate was 27% higher than that of interstate gas transmission pipelines.

• PHMSA’s resources on IM inspections for state inspectors, including existing inspection protocol guidance, mentorship opportunities, and the availability of PHMSA’s inspection subject matter experts for consultation, are inadequate.

• The prevalence of inappropriate threat elimination as a factor in gas transmission pipeline incidents cannot be determined because PHMSA does not collect threat identification data in incident reports.

• A lack of incident data regarding the risk assessment approaches used by pipeline operators limits the knowledge of the strengths and limitations of each risk assessment approach.

• Sufficient guidance is unavailable to pipeline operators and inspectors regarding the safety performance of the four types of risk assessment approaches allowed by regulation, including the effects of weighting factors, calculation of consequences, and risk aggregation methods.

• Professional qualification criteria for pipeline operator personnel performing IM functions are inadequate.

• Inline inspection as an integrity assessment method for intrastate pipelines is considerably lower than for interstate pipelines (68% compared to 96%) in part due to operational and configuration differences.

• Improvements in inline inspection tools allow for inspection of gas transmission pipelines that were previously uninspectable.

• Selection of direct assessment by the pipeline operator as the sole integrity assessment method must be subject to strict scrutiny by the inspectors due to its numerous limitations.

Among the recommendations were several that were specific to certain associations:


• Assess (1) the need for additional inspection protocol guidance for state inspectors, (2) the adequacy of your existing mentorship program for these inspectors, and (3) the availability of your subject matter experts for consultation with them, and implement the necessary improvements.

• Work with the National Association of Pipeline Safety Representatives to develop and implement a program to formalize, publicize, and facilitate increased state-to-state coordination in IM inspections.

• Work with appropriate federal, state, and local agencies to create a national repository of geospatial data resources for processing HCA identification, and publicize the availability of the repository.

• Update guidance for gas transmission pipeline operators and inspectors on critical components of risk assessment approaches. Include (1) methods for setting weighting factors, (2) factors that should be included in consequence of failure calculations, and (3) appropriate risk metrics and methods for aggregating risk along a pipeline.

• Revise 49 Code of Federal Regulations section 192.915 to require all personnel involved in IM programs to meet minimum professional qualification criteria.

• Revise Form F7100.1, Annual Report Form, to collect information about which methods of HCA identification and risk assessment approaches were used.

• Revise Form F7100.2, Incident Report Form, (1) to collect information about both the results of previous assessments and previously identified threats for each pipeline segment involved in an incident and (2) to allow for the inclusion of multiple root causes when multiple threats interacted.

• Require that all gas transmission pipelines be capable of being inline inspected by either reconfiguring the pipeline to accommodate inline inspection tools or by the use of new technology that permits the inspection of previously uninspectable pipelines; priority should be given to the highest risk *transmission pipelines that considers age, internal pressure, pipe diameter, and class location.

• Revise Form F7100.1, Annual Report Form, to collect information on the mileage of both HCA and non-HCA pipelines that can accommodate inline inspection tools.

• Identify all operational complications that limit the use of inline inspection tools in piggable pipelines, develop methods to eliminate the operational complications, and require operators to use these methods to increase the use of inline inspection tools.


• Collect data that will support development of probabilistic risk assessment models, and share these data with gas transmission pipeline operators.

• Develop and implement a strategy for increasing the use of inline inspection tools as appropriate, with an emphasis on intrastate pipelines.

The NTSB staff is making final revisions to the safety report. NTSB Acting Chairman Christopher A. Hart said, “Effective oversight and management of these programs save lives, preserve property, and protect the environment.”

“Improving pipeline safety is a critical human safety issue that can and must be improved now,” Hart said. “With the collaborative input of experts throughout the pipeline industry and community we’ve identified additional ways to find the potential problems before they become tragedies.”

Following the study release, Cathy Landry, communications director of INGAA, offered their response to the study.

“INGAA members take pipeline safety seriously. In fact, it’s job number one for our members. INGAA’s board of directors in 2011 committed to a series of ambitious, voluntary pipeline safety initiatives, anchored with a goal of zero pipeline incidents. We’ve moved forward with those commitments, even as we await action by the federal regulator, PHMSA, to issue new pipeline safety rules.

“As part of preparing its report, NTSB reached out to INGAA for the interstate natural gas pipelines’ perspective on implementation of the Integrity Management Program that was mandated by PHMSA in 2004. NTSB found that the primary focus of the IMP was to reduce incidents involving corrosion and material failures, and it concluded that this program has been effective, especially when using inline inspection technology (so-called smart pigs). INGAA members use ILI technologies widely to inspect interstate transmission pipelines.

“As a result, NTSB recommended that INGAA work with other industry organizations and segments of the industry which have had difficulty employing ILI technologies to find ways to adapt and develop these technologies for use in in complex pipeline configurations. NTSB also recommended changes to the IMP program that INGAA’s members already are making part of our voluntary commitments.

“We intend to work with PHMSA, Congress, other industry groups and NTSB to identify ways to make our systems as safe as possible.”

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