A Review of Oil and Gas Pipelines Corrosion Risk Assessment

There are total of 1.38 million miles of pipelines in the United States, including 1.23 million miles of gas transportation pipelines, and many of them are aging coated pipelines. Close to 50 percent of gas transmission and gathering pipelines were constructed in the 1950’s and 1960’s, over fifty years old. Barrier protective coatings and cathodic protection (CP) have been used to prevent corrosion. However, for aging pipelines, coating degradation/defects, shielding, disbondment, delamination and blistering can result in less than adequate protection, no protection, pitting and or stress corrosion cracking.

So

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how can we know what’s cooking down there? Down there being the aging coated pipes and assets which are located in corrosive soils exhibiting disbondment and delamination of the coating with little or no protection because of poor CP design or shielding. Murphy’s famous law states that “left to themselves, things will always go from bad to worse.” This can be related to the second law of thermodynamics that stated entropy (disorder) increases. To offset the effects of entropy, energy must be injected; otherwise the system will become increasingly disordered and unstable. This is indeed true because the past is not an indication of the future for aging structures. A well thought out corrosion risk assessment process enables asset owners and integrity engineers to carry out effective risk management by providing specific actions/tasks that can reduce the risk. The intention is to minimize risk to the lowest practical level such that no unacceptable risks remain. It is generally not practical to completely remove all risks due to feasibility, time, and cost.

The development of pipeline integrity assessment methods and criteria for determining unacceptable risk is of great importance in preventing corrosion failure, SCC, and rupture. Corrosion risk assessment of aging pipes must rely on a variety of tools and techniques to determine existing condition and to measure the probability and consequences of all the potential corrosion related hazards. In addition to the age of the pipe, the design as well as in-service utilization must be accounted for. As a starting point, an overview of the coatings and failure mechanisms is presented followed by the methods that are performed by field inspectors to determine the condition of an aging pipeline below grade and its projected serviceability or life expectation. Here, corrosion risk assessment based on soil corrosivity mapping in addition to procedures outlined in NACE standards such as NACE SP 0204-2015.

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AUTHOR: M. Zamanzadeh, R. Mirshams, P. Taheri

Copyright Materials Engineering Solutions, LLC

Disclaimer: While every effort has been made to ensure the accuracy of this publication, it is not intended to provide legal advice as individual situations will differ and should be discussed with an expert and/or lawyer.For specific technical or legal advice on the information provided and related topics, please contact the author.