This paper contains the results of laboratory and field tests where the corrosion system was carbon steel exposed to oilfield brines comaining dissolved carbon dioxide and dissolved hydrogen sulfide, contaminated with oxygen. Both uninhibited and inhibited systems were examined. The results are analyzed and placed in context with previously reported work dealing with related systems. Oilfields, in general, have less gas pressure as they mature. As a result, ingress of oxygen into well annuli, into the vapor space in tanks, and through pump packing becomes more commonplace. The corrosion consequences of this condition can now be quantified and corrective action can be taken to avoid equipment replacement and production losses. To the author's knowledge, few reports of systematic treatments of these subjects exist in corrosion literature. Quantification of the effects, recognition of duration, and
influence of corrosion inhibitor chemical types are among the novel contributions of this paper. Some of the significant conclusions from the work concern the magnitude and persistency of corrosion acceleration by oxygen in oilfield fluids. At common oil well temperatures, acceleration was in the order of 10 to 30 mpy per part per million of oxygen for sweet systems, and six (6) to 40 mpy per ppm oxygen influence in sour
systems.. The concentration of oxygen was not reduced preferentially from these solutions but occurred at approximately the same rate as reduction of dissolved carbon dioxide (undissociated carbonic acid) or dissolved hydrogen sulfide concentration. Inhibition of corrosion in oxygen contaminated systems was more difficult that in CO2/H2S alone but could be accomplished.
Keywords: Kettle test, sweet corrosion, sour corrosion, oxygen acceleration, field test, corrosion inhibitor