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Pipeline Safety: Proper Identification of Internal Corrosion Risk

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Information about this document as published in the Federal Register.

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Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT.


Notice; Issuance of Advisory Bulletin.


This advisory bulletin reminds operators of their responsibilities under 49 CFR 195.579(a) and 49 CFR 195.589(c) with respect to the identification of circumstances under which the potential for internal corrosion must be investigated.

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Alan Mayberry by phone at (202) 366-5124.

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I. Background

The Pipeline, Inspection, Protection, Enforcement, and Safety Act of 2006, Public Law 109-468, Section 22, required PHMSA to review the internal corrosion control regulations to determine if the regulations are currently adequate to ensure that the pipeline facilities subject to the regulations will not present a hazard to public safety or the environment. PHMSA completed the required review and reported its results in a Report to Congress on June 23, 2008. To review the Report, log on to, click on “Pipeline Safety Community,” then click on “Reports to Congress.” In conducting this review, PHMSA identified the need to emphasize to the regulated community its responsibilities with respect to determining the need for internal corrosion preventive and mitigative measures. Many technical factors interrelate in complex ways to affect the likelihood, location, and/or aggressiveness of internal corrosion, including the factors listed above.

Pipeline safety regulations at 49 CFR 195.579(a) require operators to determine if the hazardous liquids they are transporting could corrode the pipeline and, if so, take adequate steps to mitigate that corrosion potential. If an operator fails to take adequate steps to mitigate internal corrosion, PHMSA may determine that the operator is not in compliance with 49 CFR part 195. Also, if the operator erroneously determines the fluid is not corrosive and does not take the necessary steps to manage the internal corrosion threat, PHMSA may determine that the operator is not in compliance with 49 CFR part 195.

Although the base commodity may not be corrosive, all hazardous liquids regulated under part 195 could be corrosive during some phase of the production and/or manufacturing process when contaminants could be introduced. Often, the only barrier separating untreated product or corrosive materials from a pipeline transporting processed/refined products Start Printed Page 71090is the processing plant or refinery. These plants occasionally undergo upset conditions where all or a portion of the untreated product may bypass the treatment process and enter the downstream piping. During those upset conditions, corrosive materials might be introduced into the pipeline and could create a corrosive condition.

Pipeline operators who previously concluded that an internal corrosion control program was not needed should critically re-analyze operating conditions and internal corrosion risk factors as described in this advisory and periodically monitor, or otherwise reconfirm, that the pipeline is free of corrosive materials. Operators should perform a periodic system analysis and document the results, confirming that they properly analyzed the pipeline for possible internal corrosion precursors. In addition, operators should also conduct periodic monitoring for changes that might increase this risk and identify possible sites of selective internal corrosion risks.

In addition, operators are required to take the following steps as part of the operator's integrity management program:

  • Examine and record corrosion data;
  • Demonstrate an understanding of the risk of internal corrosion;
  • Identify the locations of greatest risk;
  • Conduct integrity assessments that will effectively discover pipeline defects caused by internal corrosion;
  • Promptly repair or remediate discovered defects;
  • Identify the root cause of discovered internal corrosion defects; and
  • Identify the need for additional or different preventive and mitigative measures, through mitigation measures such as online pigging for removal of the corrosive materials and injection of corrosion inhibitors inline the product stream.

PHMSA's unique statutory role in pipeline safety allows the agency to monitor research and operator performance nationwide and to take action through an array of regulatory actions, including this bulletin, if incident trends or other findings such as research, deem the actions necessary. PHMSA will conduct a workshop on internal corrosion on hazardous liquid pipelines in the first quarter of 2009. Information on this workshop will be posted on the PHMSA Web site.

II. Advisory Bulletin (ADB-08-08)

To: Owners or Operators of Hazardous Liquid Transmission Pipelines.

Subject: Proper Identification of Internal Corrosion Risk.

Purpose: Notice to Pipeline Owners and Operators.

Advisory: PHMSA is advising operators of hazardous liquid transmission pipelines to review and analyze the following risk factors to determine if the commodity transported could corrode the pipeline:

  • Type of commodity;
  • Flow rate;
  • Velocity;
  • Operating Pressure;
  • Topography;
  • Amount of foreign material and/or contaminants present in the pipeline and/or commodity stream such as sand, silt, water, or other materials that could cause or promote internal corrosion;
  • Amount of sulfur, salts, acids, hydrogen sulfide, carbon dioxide or other corrosive material present and corrosive effect based upon partial pressures of material in the pipeline;
  • Presence of microbes;
  • Temperature;
  • Pipe configuration, design, and material specifications;
  • Operating conditions, including but not limited to, steady state conditions, slack line conditions, upset conditions in the pipeline system, and upset conditions in upstream facilities such as refineries or processing facilities; and
  • Any other circumstance or condition that could cause, promote, or increase the likelihood of internal corrosion.

Significant changes to any of the above risk factors and considerations must be promptly reflected in a revised analysis.

PHMSA is further advising operators that, in accordance with 49 CFR 195.589(c), you must maintain a record of the above analysis required by 49 CFR 195.579(a) in sufficient detail to demonstrate the adequacy of corrosion control measures or that corrosion control measures are not necessary. You must retain these records for at least five years. The records must be readily available for inspection.

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Issued in Washington, DC on November 17, 2008.

Jeffrey D. Wiese,

Associate Administrator for Pipeline Safety.

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[FR Doc. E8-27869 Filed 11-21-08; 8:45 am]