Numerical modeling of injection and mineral trapping of CO2 with H2S and SO2 in a sandstone formation

Carbon dioxide (CO2) injection into deep geologic formations could decrease the atmospheric accumulation of this gas from anthropogenic sources. Furthermore, by co-injecting H2S or SO2, the products respectively of coal gasification or combustion, with captured CO2, problems associated with surface disposal would be mitigated. We developed models that simulate the co-injection of H2S or SO2 with CO2 into an arkose formation at a depth of about 2 km and 75 °C. The hydrogeology and mineralogy of the injected formation are typical of those encountered in Gulf Coast aquifers of the United States. Six numerical simulations of a simplified 1-D radial region surrounding the injection well were performed. The injection of CO2 alone or co-injection with SO2 or H2S results in a concentrically zoned distribution of secondary minerals surrounding a leached and acidified region adjacent to the injection well. Co-injection of SO2 with CO2 results in a larger and more strongly acidified zone, and alteration differs substantially from that caused by the co-injection of H2S or injection of CO2 alone. Precipitation of carbonates occurs within a higher pH (pH > 5) peripheral zone. Significant quantities of CO2 are sequestered by ankerite, dawsonite, and lesser siderite. The CO2 mineral-trapping capacity of the formation can attain 40–50 kg/m3 medium for the selected arkose. In contrast, secondary sulfates precipitate at lower pH (pH < 5) within the acidified zone. Most of the injected SO2 is transformed and immobilized through alunite precipitation with lesser amounts of anhydrite and minor quantities of pyrite. The dissolved CO2 increases with time (enhanced solubility trapping). The mineral alteration induced by injection of CO2 with either SO2 or H2S leads to corresponding changes in porosity. Significant increases in porosity occur in the acidified zones where mineral dissolution dominates. With co-injection of SO2, the porosity increases from an initial 0.3 to 0.43 after 100 years. However, within the CO2 mineral-trapping zone, the porosity decreases to about 0.28 for both cases, because of the addition of CO2 mass as secondary carbonates to the rock matrix. Precipitation of sulfates at the acidification front causes porosity to decrease to 0.23. The limited information currently available on the mineralogy of naturally occurring high-pressure CO2 reservoirs is generally consistent with our simulations.