Experimental investigation of porosity and permeability variations in reservoirs and caprock following co-injection of sulfur dioxide and hydrogen sulfide with carbon dioxide

Carbon dioxide (CO2) capture, transport and storage (CCTS) in deep geological formations can mitigate the atmospheric concentration of greenhouse gases. Purity of this gas is an important aspect for CCTS since it drives up the cost of capture. When leaving some impurities from the flue gas in the CO2 stream, a cost reduction may be achieved but the risks at transport and storage may increase. In order to investigate the effects of the possible impurities (H2S and SO2) in the CO2 stream during subsurface storage laboratory experiments were performed on Permian Rotliegend reservoir and Zechstein cap rock core samples from gas fields in northeast Netherlands. The rock samples were subjected for 30 days to static in situ conditions (300 bar, 100 °C) in the presence of brine and an injected gas mixture of CO2 +100 ppm SO2+100 ppm H2S. Following injection of the mixture permeability of the reservoir and caprocks increased by a factor of 1.02-1.9 and 1.2-3.1, respectively. Although an enhanced level of anhydrite precipitation was observed, the increase in permeability of the samples show that dissolution of carbonate, feldspar and kaolinite minerals is dominant. In addition it was shown that the initial porosity-permeability relation of the samples remains valid to predict the behavior of the reservoir after injection of the gas mixture. For the caprock, the precipitation of anhydrites results in a less enhanced permeability than in the case of injection of pure CO2. This may lead to the conclusion that the addition of low quantities (100 ppm) of SO2 and H2S in CO2 during subsurface storage does not increase the risk of leakage through the Zechstein caprock more than when using pure CO2.