This paper reports the corrosion behaviour of X65 steel in a mixed 1% H2S (in CO2) brine after exposure to a pure CO2-saturated brine at 40°C. The objective of the study was to identify the scales formed and understand their effect on the corrosion performance of X65 steel upon transition from pure sweet to sour conditions. Electrochemical testing indicated reduced general corrosion rate during the exposure to pure CO2 environment, which is mainly attributed to the formation of protective but porous siderite scale. After the introduction of mixed CO2/H2S gas, the corrosion rate decreased further for a short period due to precipitated mackinawite above the existing siderite. As H2S and brine were diffusing through the pore network in siderite, the corrosion rate exhibited an increasing trend due to the accelerating effect of the formed mackinawite within the intermediate layers and on the steel surface. Owing to the possible development of internal stresses in the newly formed scale, the existing siderite layers were ruptured, leading to the precipitation of more mackinawite and promoting further the dissolution of ferrite into the solution. The estimated corrosion rates indicated that the uniform attack is more widespread than the local attack.
Oil field reservoir souring is a known problem which has significant financial impact on the oil and gas industry, such as decrease in the value of exploration and production assets, increase in operational costs (i.e. chemical treatments), and at worst, shut-in of wells. The causes of excessive H2S production in previously ‘non-sour’ environments can be numerous. Anthropogenic causes include certain operational practices such as injection of seawater under pressure into the reservoir to sweep the crude oil towards the production wells. Oil and gas exploration and production (E&P) companies have noticed that the transition from the injection of seawater to the initial production of H2S gas can take several years.