Modeling CO2–H2S–water–rock interactions at Williston Basin reservoir conditions

Abstract A series of laboratory experiments, field observations from a small-scale CO 2 enhanced oil recovery project, and numerical modeling of geochemical reactions have been conducted to determine the chemical kinetics of potential mineral dissolution and/or precipitation caused by the injection of CO 2 and of sour gas. Kinetic experiments were conducted using core samples from potential Williston Basin storage formations. Two sample sets consisting of 16 samples each, under the same experimental conditions, were “soaked” for a period of 4 weeks at 172 bar and 80 °C in synthetically generated brine conditions. Over that time period, one set was exposed to pure carbon dioxide and the other to a mixture of carbon dioxide (88 mol%) and hydrogen sulfide (12 mol%). The analysis of obtained reaction products suggests that (1) there is no strong evidence for higher reactivity of samples exposed to a mixture of CO 2 and H 2 S if compared to the pure CO 2 stream; however, (2) if H 2 S is present in the stream, it seems to be more dominant in the reactions; and (3) reactivity of the sample is strongly driven by its mineralogy.