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

During the exploitation of Sichuan highly sour gas field in China, the content of hydrogen sulfide in some wells is more than 10%. Since there is not so much experience on the corrosion of carbon steels under this kind 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 ^oC 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 increases with elevating temperature up to 60 ^oC and then drop down gradually. Serious pitting corrosion can be found at 30^oC. At 60 ^oC, 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.