## 1 Introduction
[PERSON] et al., recognized that the impact of calcite dissolution may be limited to the area near the scCO\({}_{2}\) injection point, while at distances far from the injection point, only minimal or no change was observed in the pore structure, pore roughness, and pore populations [20]. The interaction between the injected CO\({}_{2}\) and carbonate rock can also promote the diffusion of CO\({}_{2}\) in the carbonate reservoir. It has been found that the effective diffusion coefficient of CO\({}_{2}\) can increase by approximately one order of magnitude when the interaction of the CO\({}_{2}\)-brine-carbonate rock matrix is considered in comparison to the pure CO\({}_{2}\) diffusion in the carbonate reservoir [21]. Many studies have been conducted to optimize the dissolution effects on CO\({}_{2}\) storage in carbonate reservoirs. [PERSON] et al. found that scCO\({}_{2}\) can substitute acids and be used as safe, non-aqueous fracturing fluid in reservoir fracturing [22]. They claimed that the use of scCO\({}_{2}\) enables a greater development of fractures, and the permeability of such fractured rocks is three orders of magnitude higher than the ones created by conventional hydraulic fracturing [23]. [PERSON] et al., using a combined CT scanning and discrete element method (DEM), found that the carbonate dissolution will be much stronger when scCO\({}_{2}\) is injected after live brine flooding [24]. A series of carbonate water injection tests revealed that flow rate can notably influence the natural fracture profiles in carbonate rocks. The fracture widening is more pronounced when CO\({}_{2}\) is injected at a higher rate [24]. In addition, the carbonate dissolution rate can be changed by adding some external material during CO\({}_{2}\) injection, such as microbials and nanoparticles. For example, in [PERSON]'s study, samples from deep carbonate formations are treated with microbial media and scCO\({}_{2}\). The results indicate that carbonate dissolution is slower with appropriate post-injection remediation [3]. In another study, [PERSON] et al. found that CO\({}_{2}\)-brine-rock interactions can be more intense and occur in small pores with the addition of SiO\({}_{2}\) nanoparticles [25]. In summary, it is known that the injection of large amounts of CO\({}_{2}\) into geological reservoirs may lead to a series of alterations due to chemical and physical interactions between minerals and fluids in carbonate- or carbonate-rich reservoirs. However, some research gaps need to be filled. First, so far, most of the CO\({}_{2}\) capture, utilization, and sequestration (CCUS) studies are focused on siliciclastic formations rather than highly chemically reactive carbonate formations [26]. Also, even though few studies regarding CO\({}_{2}\) storage in carbonate reservoirs have been conducted, researchers prioritized scCO\({}_{2}\) injection in deep saline aquifers rather than shallow hydrocarbon reservoirs, whose CO\({}_{2}\) storage advantages, such as low-cost drilling, injection, and transportation, abundance of available reservoir data and knowledge, and minimal uncertainties, should not be ignored. In this study, the carbonate rocks are selected as CO\({}_{2}\) storage sites, and different carbonate geological models are constructed to numerically investigate the effects of chemical CO\({}_{2}\)-brine-carbonate rock interactions on CO\({}_{2}\) storage and sequestration. Specifically, a sensitivity analysis of four factors, i.e., lithologies, pore-throat structures, pore sizes, and rate, is presented, and the physical property variations before and after CO\({}_{2}\) injection in different carbonate reservoirs are compared. This study, to some extent, fills the knowledge gap in rock-pore fluid interaction in CO\({}_{2}\) storage in shallow carbonate reservoirs and helps researchers and engineers in aspects of reservoir selection and operation optimization in the projects of CO\({}_{2}\) storage in carbonate reservoirs.