PHMSA Adopts Design and Construction Standards for Gas Pipelines to Reduce Internal Corrosion Risks and Issues Advisory Bulletin Requiring Executive Signature and Certification of Integrity Management Performance Reports

On April 23, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a final rule adopting new regulations requiring operators of onshore gas pipelines to incorporate design and construction features in new and replaced onshore transmission and non-rural gathering pipelines to reduce the risk of internal corrosion. Nothing in the final rule supersedes or negates the requirement to address internal corrosion during operation and maintenance activities. The final rule becomes effective May 23, 2007, and applies to all pipelines installed or line pipe, valve, fitting, or other line components replaced after that date. Also on April 23, PHMSA issued an advisory bulletin informing operators of gas and hazardous liquid pipelines that integrity management performance reports must be signed and certified by a senior executive officer of the company.

Final Rule Regarding Design and Construction Standards to Reduce Internal Corrosion in Gas Pipelines

PHMSA has issued a final rule requiring gas pipeline operators to address internal corrosion risk when designing and constructing new and replaced onshore gas transmission pipelines and non-rural gathering lines. The rulemaking was initiated in response to a recommendation of the National Transportation Safety Board following the investigation into the gas transmission pipeline explosion near Carlsbad, New Mexico, in 2000. That investigation identified severe internal corrosion as the immediate cause of the pipeline failure.

New Regulatory Requirements: The rule requires gas pipeline operators to design and construct each new onshore transmission and non-rural gathering line and each replacement of line pipe, valve, fitting, or other line component with features designed to reduce the risk that liquids will collect in the line. Specifically, unless it is impracticable or unnecessary, an operator must (1) use a configuration that reduces the collection of liquids in the line; (2) have effective liquid removal features; and (3) allow the ability to use corrosion monitoring devices in locations with significant potential for internal corrosion. In addition, when changing the configuration of an existing line, an operator must evaluate the effect of the change on internal corrosion risk to the downstream portion of an existing transmission line and provide for liquids removal and monitoring as appropriate. Finally, an operator must maintain records demonstrating compliance. Such records must include the reasons, and any engineering analysis, for all design and construction decisions related to internal corrosion.

Applicability of the Rule: The new regulations apply to (1) onshore transmission and non-rural gathering pipeline installed and (2) line pipe, valve, fitting, or other line components replaced after May 23, 2007.

• Non-Rural Gathering Lines. PHMSA rejected requests to exempt non-rural gathering lines from the final rule. PHMSA explained that gathering lines regularly transport gas containing liquids, a known corrosive condition. Moreover, PHMSA noted that non-rural gathering lines are subject to most of the same regulations as transmission pipelines, including corrosion control and design and construction requirements. This rule is consistent with that approach.
• Compressor Stations. PHMSA also rejected requests to exempt compressor stations from the final rule’s requirements. PHMSA explained that compressors do not operate well when liquids are present in the gas flow, and that actions to remove liquids before they enter the compressor can result in liquids accumulating in compressor station piping. PHMSA noted further that, between 2000 and 2005, about forty percent of the damage caused by onshore internal corrosion incidents was due to incidents at compressor stations.
• Offshore Pipelines. The final rule does not apply to offshore pipelines. PHMSA stated, among other things, that serious incidents on offshore pipelines have been caused by outside force damage, not corrosion, and that unless the corrosion is widespread, a corrosion failure is likely to result in a leak, not a rupture, and is not likely to cause a risk of harm to people. In addition, installing and operating liquid removal equipment in offshore facilities is not possible in deep water.

Implications of Final Rule

The final rule applies to all gas transmission pipe installed or replaced after May 23, 2007. A large number of pipeline projects recently have been approved or are pending before the Federal Energy Regulatory Commission. Construction of these projects has either begun or is expected to commence soon. The applicability of the rule to these pipelines is not clear, but could be far-reaching.

Advisory Bulletin Requiring Senior Executive Signature and Certification of Integrity Management Program Performance Reports

PHMSA has issued an advisory bulletin notifying operators of gas and hazardous liquid pipelines that integrity management program performance reports must be signed and certified by a senior executive of the pipeline. The advisory bulletin reflects the requirements of the Pipeline Inspection, Protection, Enforcement and Safety Act (PIPES Act), which was enacted in December 2006 and requires that each pipeline integrity management program performance report include a signed statement certifying that the senior executive officer has reviewed the report and to the best of the officer’s knowledge and belief, the report is true and complete. The advisory bulletin states that PHMSA has modified its integrity management electronic filing forms to reflect the new requirement. In lieu of electronic filing, operators may mail or fax the reports to PHMSA.