Corrosion Experience of 13%Cr Steel Tubing and Laboratory Evaluation of Super 13Cr Steel in Sweet Environments Containing Acetic Acid and Trace Amounts of H2S

13%Cr steel tubing corroded at shallow depths in deep, hot Minami-Nagaoka Gas-condensate wells onshore. The produced gas contains 6% CO₂ and 2~3 ppm H₂S, and the produced water contains 400 ppm acetate. The localized corrosion apparently initiated from mechanical damages by wire line operations. The corrosion damage was severer in wells with longer shut in period. These observations are in 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 these understandings, corrosion performances of Super 13 Cr steel containing Ni and Mo was evaluated as a potential countermeasure in comparison with 13% Cr and 22 Cr steels at a low temperature in addition to at high temperatures using flow loop and rotating cage.

Very interesting corrosion performances of S-13Cr steel was elucidated such as the effect of Cl^- concentration and the influence of trace amounts of H₂S.