Abstract Modeling of supercritical CO2 injection into a deep saline aquifer from a carbonate formation (calcite and dolomite, with minor anhydrite) was performed using TOUGHREACT (Xu et al. 2006) with Pitzer ion-interaction model implementation for handling high salinity problems (Zhang et al. 2006). The formation brine salinity is ~225,000 ppm (NaCl dominant), temperature at 102oC and pressure at 225 bars. CO2 injection rate was considered constant for a period of 1 year through a horizontal well in a 3D model domain. The carbonate formation was assumed to have homogeneous porosity and permeability and to be overlaid by an impermeable seal. The effect of a higher permeability fault with orientation perpendicular to the horizontal well, and bounded by the impermeable overburden, was evaluated. The impact on mineralogical and rock property changes in the saline aquifer during injection has been assessed. The simulations found that:the higher permeability fault acts as a CO2 conduit;
a dryout zone is developed within a few meters from the injection well due to displacement by supercritical CO2 and dissolution of water into CO2 stream
at the front of the dryout zone, brine is further concentrated due to water dissolution into CO2, pH is lowered from 5.5 to 3.1, halite (NaCl) and anhydrite (CaSO4) precipitate, and the brine becomes CaCl2-dominant;
near well-bore porosity reduces by ~5%-17% due to halite precipitation (dryout zone);
HCl gas is generated from the dryout front;
calcite and dolomite dissolve as the CO2 plume advances during injection;
anhydrite, however, slightly dissolves along the CO2 front, but precipitates in the area corresponding to the CO2 plume with higher proportions near well-bore.
These findings are valuable for the assessment of injectivity changes and near well-bore stability of saline aquifers in carbonate formations during injection of CO2. The overall mineral trapping in hundreds of years is not the focuss of this paper. However, from ongoing modeling experiments, mineral trapping is anticipated to be not significant for the mineralogies and brine chemistries and salinities of the carbonate formation under assessment. This study method is useful for the further evaluation of engineering options to enhance immobile trapping of CO2 and mitigation measures for potential injectivity impairment.
Introduction Carbon Capture and Storage (CCS) is one of the most technically mature options to increase energy supply while reducing CO2 emissions (e.g. Holz et al. 2001; Gale 2004; Friedmann 2007; Benson and Cole 2008). Most previous studies have concentrated on evaluating the impact of CO2 injection on saline aquifers from siliciclastic formations (Pruess et al. 2003; Chadwick et al. 2004; Doughty and Pruess 2004; Johnson et al. 2004; Forster et al. 2006; Dashtgard et al. 2008). Nevertheless, their limited availability, or their too deep occurrences, in certain specific regions with high CO2 emissions, leads saline aquifers in carbonate formations to be considered as alternative solutions for CO2 Storage (e.g.Weyburn in Canada, Li 2003; Emberley et al. 2005). The available information on the impact of CO2 injection in carbonate formations is limited. However, the general geological knowledge of rock: CO2 interaction in carbonate formations (e.g. Baines and Worden 2004) is of great value to provide a preliminary estimation of 1) the plausible reactions and products and 2) the impact on mineralogical and rock property changes.