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51317--9742-Root Cause Analysis of an Upstream Pipeline Failure Due to Multiple Operating Factors

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A 22-year-old liquid line experienced an unexpected failure due to internal corrosion after adding the production from one well. Investigation included ILI records, operating pressures and temperatures, oil pressure / volume / temperature (PVT) data, possible flow regimes, failure analysis reports, and mitigation practices.

 

Product Number: 51317--9742-SG
ISBN: 9742 2017 CP
Author: Jenny Been
Publication Date: 2017
Industry: Gas/Liquid Pipelines
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An upstream pipeline operator of a NPS 12 22-year old liquid line experienced an unexpected failure due to internal corrosion only a short time after adding the production fluids of one additional well. A root cause analysis was conducted to discover the reasons for the high corrosion rates experienced after many years of operation examining ILI records operating pressures and temperatures oil pressure / volume / temperature (PVT) data possible flow regimes failure analysis reports and mitigation practices. The dominant corrosion mechanism was found to be carbon dioxide corrosion which was supported by a change in gas to oil ratio (GOR) leading to the release of CO2 gas in response to pressure changes along the line in areas of relatively high pressure and temperature. Additional contributory factors included a high water cut with chloride concentrations underdeposit corrosion underneath pipeline deposits and corrosion scale and microbiologically induced corrosion. Monitoring and mitigation measures are discussed.

Keywords: root cause analysis, carbon dioxide corrosion, gas to oil ratio, under deposit corrosion, microbiologically induced corrosion, mitigation, flow regime

An upstream pipeline operator of a NPS 12 22-year old liquid line experienced an unexpected failure due to internal corrosion only a short time after adding the production fluids of one additional well. A root cause analysis was conducted to discover the reasons for the high corrosion rates experienced after many years of operation examining ILI records operating pressures and temperatures oil pressure / volume / temperature (PVT) data possible flow regimes failure analysis reports and mitigation practices. The dominant corrosion mechanism was found to be carbon dioxide corrosion which was supported by a change in gas to oil ratio (GOR) leading to the release of CO2 gas in response to pressure changes along the line in areas of relatively high pressure and temperature. Additional contributory factors included a high water cut with chloride concentrations underdeposit corrosion underneath pipeline deposits and corrosion scale and microbiologically induced corrosion. Monitoring and mitigation measures are discussed.

Keywords: root cause analysis, carbon dioxide corrosion, gas to oil ratio, under deposit corrosion, microbiologically induced corrosion, mitigation, flow regime

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Corrosion features in energy pipelines can adversely affect the stress/strain state of the pipe body leading to potential integrity concerns. This study demonstrates the application of Reliability-Based Surrogate Models as a means of integrating FEA and reliability analysis in a more reasonable timeframe for integrity programs.
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51314-3723-Pipeline Corrosion Management; a Compendium

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