Effects of Temperature and Partial Pressure on H2S/CO2 Corrosion of Pipeline Steel in Sour Conditions

Abstract During the exploitation of Sichuan sour gas field in China, the content of hydrogen sulfide in some wells is more than 10%, where the H2S partial pressure reaches about 3MPa. The temperature in the well is about 95~115°C. Since there is not much experience on the corrosion of carbon steels under these kinds of conditions, it is difficult to design corrosion control methods and select inhibitors. In this paper, the H2S/CO2 corrosion of X60 pipeline steel under 0.15~2.5MPa H2S partial pressures and 30~120°C were studied. High temperature and pressure corrosion simulation experiments, SEM and XRD were employed to investigate the effects of partial pressure and temperature on corrosion rate, characteristics of localized corrosion and evolution of corrosion product. Under 1~2MPa H2S, the corrosion rate increased with elevating temperature up to 60°C and then decreased gradually. Serious pitting corrosion was found at 30°C. At 60°C, corrosion rate increased gradually with H2S and CO2 partial pressure, close to a stable value up to 1.5MPa H2S. Under higher partial pressure, obvious pitting corrosion can also be found, whose morphology was different from that formed at low temperature. Temperature and partial pressure directly affected the morphology and composition of corrosion products, which in turn caused the change of corrosion rate and occurrence of localized corrosion.