Geochemical Modelling of CO2 Injection: Role of Capillary-Driven Transport of Dissolved Salt on CO2 Injectivity

Abstract

Abstract One of the main risks of CO2 injection into sedimentary formations, especially saline aquifers, is well clogging due to salt precipitation. Capillary-driven backflow of formation brine may serve as a continuous transport of dissolved salt toward the dry zone around the injection point. This salt will eventually precipitate due to water vaporization, jeopardizing the CO2 injectivity. The study objective is to apply to a potential CO2 storage complex, constituted by a multi-layered depleted gas field, a multi-step, mineralogical-geochemical workflow emphasizing the role of capillary-driven transport of dissolved salt on CO2 injectivity. An integrated workflow, starting from real samples, and coupling laboratory activities with numerical simulations, is given. The workflow consists of the following steps: Lithological, mineralogical, and geochemical characterization of field core samples Laboratory ageing experiments on caprock samples with CO2 Preliminary geochemical numerical models’ calibration to reproduce the results of CO2 ageing experiment Geochemical numerical modelling at different spatial/temporal scales and complexity levels The CO2 injection is simulated via multi-layered 2D radial reactive transport model. The CO2 injection scheme and the pressure buildup have been maintained as per field 3D dynamic model. The formation brine chemical composition is retrieved from laboratory analysis. The mineral dissolution/precipitation and CO2 dissociation reactions are modelled using a rate-dependent and an equilibrium approach respectively. The overall mineralogical composition can be defined as highly heterogeneous due to the presence of not-negligible amounts of quartz, feldspar, mica, clay, and carbonate minerals. The latter are more present in the caprock (around 45% wt.) and less in the reservoir samples (15% wt.). The ageing experiment performed using caprock samples resulted in partial Calcite mineral dissolution in the presence of CO2-rich water and allowed to better calibrate parameters used for numerical geochemical modelling activities. The simulations at reservoir conditions show a limited dissolution of calcite due to the pH lowering associated to the CO2 plume evolution, and water vaporization phenomenon is observed in the near wellbore area. The effect of capillary-driven back flow is acknowledged by comparing the water movements in the near wellbore area with and without the capillary pressure. The capillary-driven back flow has shown a limited impact on Halite precipitation around the injection well, even when the capillary pressure is doubled. Further simulation work has been performed to check whether the conclusions are still applicable even in the worst-case scenario where Halite precipitation is instantaneously modelled via an equilibrium approach instead of a kinetic one. The presented workflow gives a new perspective in geochemical application for CO2 storage studies, which increases the reliability and specificity of the investigation via a strong integration between experimental analyses and numerical modelling.