Abstract
<jats:title>Abstract</jats:title> <jats:p>Maintaining injectivity is essential for the success of CO2-enhanced oil recovery (CO2-EOR) and geological CO2 storage projects. Injectivity controls the ability to safely and efficiently place large volumes of CO2 into the subsurface over long periods. This study develops a simple, experimentally based framework to evaluate how sandstone reservoir properties evolve over time during CO2 injection, with particular emphasis on the geochemical contribution to injectivity changes. Rather than directly measuring flow performance, the work focuses on quantifying reaction-driven changes in intrinsic rock properties that govern injectivity.</jats:p> <jats:p>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). Static conditions were intentionally selected to isolate geochemical reactions from flow-related effects such as fines migration, salt precipitation, and capillary end effects. Changes in rock and fluid properties were quantified using X-ray diffraction (XRD) to track mineralogical alterations, aqueous chemistry measurements (ICP-OES and titration) to monitor dissolved species, and dry mass-loss measurements to quantify reaction progress. Dissolution kinetics were derived from these data and combined with reactive surface area estimates based on the Kozeny–Carman relationship to project time-dependent porosity and permeability evolution.</jats:p> <jats:p>Short-term experimental results show limited alteration of the quartz-dominated sandstone framework over the duration of the laboratory tests. 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 an absolute porosity increase of approximately 5.5 percentage points within the reacted zone under brine-saturated conditions.</jats:p> <jats:p>These findings suggest that CO2–brine–rock interactions in carbonate-cemented sandstones can support sustained or improved injectivity over operational timescales. The proposed framework provides a clear and physically grounded link between laboratory-scale measurements and injectivity assessment, supporting more realistic evaluation of reservoir performance and injection strategy design for CO2-EOR and CCUS projects.</jats:p>