13%Cr steel tubing corroded at shallow depths in deep, hot Minami-Nagaoka Gas-condensate wells onshore Japan. The produced gas contains 6% CO2 and 2~3ppm H2S, and the produced water contains 400 ppm acetate. The localized corrosion apparently initiated from mechanical damages produced by wire line operations. The corrosion damage was more severe in wells with longer shut in periods. These observations are contradictory to the traditional understanding that the corrosion performance of 13%Cr steel deteriorates at high temperatures in wet CO2 environments. And abovementioned observations suggest that the corrosion initiated during well’s shut in period at shallow depths due to pH lowering by higher CO2 solubility at low temperatures and the existence of acetic acid. Based on this understanding, corrosion performance of Super 13Cr steel containing Ni and Mo was evaluated as a potential countermeasure in comparison with 13% Cr and 22Cr steels at a low temperature in addition to at high temperatures using flow loop and rotating cage. The effect of Cl- concentration and the influence of trace amounts of H2S on the corrosion performance of Super 13Cr steel was elucidated.

Subject
Materials, Corrosion rate, Chloride ion concentration, Corrosion cracking, Partial pressures, Acidity, Tubing, Steel, Acetic acid, Corrosion resistance, Localized corrosion, Uniform corrosion, High temperature
Keywords:
Corrosion experience, 13%Cr tubing, Super 13Cr steel, sweet environments, acetic acid, trace amounts of H2S
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2009
Association for Materials Protection and Performance (AMPP)
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