Experimentally Constrained Kinetic Modeling of Long-Term Permeability and Injectivity Bounds in CO2–Brine–Sandstone Systems

Maintaining injectivity is essential for the success of CO2-enhanced oil recovery (CO2-EOR) and CO2 storage. This study develops a simple, experimentally based framework to evaluate how sandstone reservoir properties evolve over time during CO2 injection. Static aging experiments were conducted on Berea sandstone for exposure periods of up to three months using CO2-saturated brine at representative reservoir conditions (150 °F and 1500 psi). Changes in rock and fluid properties were quantified using X-ray diffraction (XRD), aqueous chemistry (ICP-OES), and dry mass-loss measurements to quantify reaction progress. Dissolution kinetics were derived from these data and combined with a mass-balance porosity model and the Kozeny–Carman porosity–permeability relationship to project time-dependent porosity and permeability evolution. Short-term experimental results show limited alteration of the quartz-dominated sandstone framework over the duration of the laboratory tests, while the measured permeability decreased by 5.7% and 11.7% after 1 and 3 months of CO2 exposure, respectively. However, kinetic projections indicate that slow dissolution of reactive carbonate cements can gradually enhance pore connectivity over longer timescales. Scenario-based projections over a 30-year injection period predict a potential permeability increase exceeding 140%, accompanied by a model-projected absolute porosity increase of approximately 5.5 percentage points; the permeability projection is contingent on the assumptions of the Kozeny–Carman relationship. The framework links laboratory geochemical measurements with long-term permeability assessment for CO2-EOR and CO2 storage.