CO2 Mineralization and Overall System Response to Coupled Thermal-Hydrological-Chemical (THC) Processes During CO2 Sequestration in Saline Aquifers

Abstract

Abstract

Abstract Reactive transport processes play a critical role in the prediction of geochemical effects on the CO2 storage behavior and should not be neglected in reservoir simulations. This study evaluates the coupled thermal–hydrological–chemical (THC) mechanisms during CO2 injection and long-term sequestration in saline aquifers. We investigate how rock-fluid interactions and temperature-dependent mineral reactions of both the aquifer and the caprock formations can affect (a) porosity and permeability variations, (b) near-wellbore properties, (c) trapping mechanisms, and (d) the reservoir sealing capacity, in an effort to assess the overall containment performance of the storage site. We developed a three-dimensional reactive-transport model using the TOUGHREACT code with the ECO2N-EOS module to simulate a multiphase system of CO2, brine, and minerals representing a part of the Frio formation saline aquifer. The model combines equilibrium and kinetic reactions for key minerals under various temperature and salinity conditions. We simulated the injection of supercritical CO2 through a vertical well for 10 years, followed by 90 years of a post-injection rest phase. We also extended the simulation up to 500 years to monitor the evolution of the CO2 state and mineralization processes. Additionally, we conducted a sensitivity analysis to understand the influence of main operational and subsurface parameters, including the storage formation type (sandstone, carbonate, and shale), injection rate, well configuration, and boundary conditions on the CO2 plume behavior, the pressure evolution and the geochemical system stabilization. Results show that geochemical coupling significantly affects CO2 plume propagation and injectivity compared to cases with no geochemical coupling. For a sandstone aquifer system, strong acidification near the injector increases porosity and permeability, improving injectivity. With time, pH rises due to carbonate precipitation and buffering reactions, thus stabilizing the reservoir properties within 500 m from the well. Thermal effects are localized but critically important near the injector. The caprock shows minimal porosity and permeability change, with slight calcite and siderite precipitation that could enhance the sealing capacity. In contrast, carbonate formations experience fast calcite dissolution, strong pH buffering, and limited mineral trapping; shales show limited CO2 mobility. Analysis of the effects of boundary conditions shows that regional hydraulic connectivity is the main controlling mechanism of pressure buildup and caprock loading. For the same injection rate, horizontal injection wells are more effective in spreading the plume over a larger area and improving CO2 entrapment--both in the gas phase and dissolved in the aqueous phase--than vertical wells. The THC modeling and sensitivity framework developed in this study provides a comprehensive understanding of the interactions of thermal effects, mineral reactions, formation type, injection strategy, and regional hydraulic communication in controlling long-term CO2 plume migration and storage security. The findings indicate that, even under conservative operational and boundary conditions, caprock integrity is preserved, and geochemical as well as thermal feedbacks contribute to the stabilization of the injected CO2 over extended periods.