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 understand the factors that contributed to the sudden high corrosion rates experienced after many years of operation. The investigation included examination of 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 moderate chloride concentrations, under deposit corrosion underneath pipeline deposits and corrosion scale, and microbiologically induced corrosion. Monitoring and mitigation measures are discussed.

Subject
Water, Batteries, Corrosion rate, Solids, Pipelines, Gas pressure, Partial pressures, Corrosion scales, Bubbling, Mechanical failure, Microbiologically influenced corrosion, Cleaning, Oil
Keywords:
root cause analysis, carbon dioxide corrosion, gas to oil ratio, under deposit corrosion, microbiologically induced corrosion, mitigation, flow regime
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2017
Association for Materials Protection and Performance (AMPP)
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