Experimental and Modeling Study of Salt Precipitation During Injection of CO2 Contaminated with H2S into Depleted Gas Fields in Northeast Netherlands

Abstract

Abstract Depleted gas fields are amongst the most probable candidates for subsurface storage of CO2. With proven reservoir and qualified seal these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine due to formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and cap-rock. Thus, for adequate, safe and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. In order to investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30 days) laboratory experiments on reservoir and cap-rock core samples from gas fields in northeast Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream (H2S) in these fields. The injected gases were CO2, CO2+100 ppm H2S and CO2+5000 ppm H2S. Before and after the experiments the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. Also the permeability of the samples was measured. Following the experiments, dissolution of feldspars, carbonates and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S in the CO2 stream. Firstly we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection where dissolution of anhydrite was dominant in the samples. Secondly, severe salt precipitation took place in the presence of H2S. This is caused by the higher solubility of H2S in water and a higher water content of gas phase in the presence of H2S. This was confirmed by modeling using CMG-GEM (CMG, 2011) modeling software. The precipitation of salt, anhydrite and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and <3%, respectively. In caprock samples permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5000 ppm H2S the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, salt precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.