## 1 Introduction  
Carbon dioxide emissions from fossil-fuel combustion are projected to increase from 13 Gt yr\({}^{-1}\) in 2010 to 20-24 Gt yr\({}^{-1}\) in 2050 [1]. CO\({}_{2}\) capture and storage (CCS) technologies beneficially affect the lifecycle of greenhouse gases emitted from fossil-fuel power plants [2; 3], with CCS expected to account for up to 19% of global CO\({}_{2}\) emission reductions by 2050, making it the most significant technology worldwide in this area [4]. Suitable geological formations for CCS include depleted oil and gas reservoirs, un-mineable coal seams, salt caverns, and deep saline aquifers [5; 6]. After CO\({}_{2}\) injection, the initial physico-chemical equilibrium between saline formation fluid and reservoir rocks can be disturbed by the triggering of reactions between CO\({}_{2}\), fluid (brine), and reservoir rock [2]. Such interactions could lead to the dissolution of carbonates, feldspars, and clay cement in the aquifers [7; 8]. In the absence of dynamic forces, such mineral dissolution could increase porosity and permeability by etching new pore spaces or widening narrow pore channels, temporarily increasing injectivity [9; 10]. However, while sequestration of CO\({}_{2}\) in carbonate minerals can contribute to long-term storage security [11], rapid mineral dissolution, especially of carbonates, could corrode caprocks, wellbores, and fault seals,potentially leading to migration of CO\({}_{2}\) into overlying formations. Study of CO\({}_{2}\)-fluid-rock interactions is thus crucial for us to understand the physico-chemical processes involved.  
Laboratory experiments can reveal the mineralogical and chemical changes resulting from CO\({}_{2}\)-brine-rock interactions, how they impact the lithological porosity and permeability of the geological sequence, and the effects on CCS potential [12; 13; 14; 15]. However, experiments are limited to short-term effects of CO\({}_{2}\) injection, whereas CCS is a long-term geochemical issue. Numerical modelling or simulation is useful for longer-tern studies. Several reactive geochemical transport models have been developed to simulate CCS, including NUFT [16], PFLOTRAN [17], CMG-GEM [18], STOMP [19], and TOUGHREACT [20; 21]. The TOUGHREACT program has been widely used in studying geological CO\({}_{2}\) sequestration [22; 23; 24; 25; 26]. However, simulations are less reliable without the availability of parameters derived from laboratory studies, so a combination of physical experiments and numerical simulation is the optimal choice for investigating the geochemical effects following CO\({}_{2}\) injection.  
In this study, both laboratory experiments (physical simulation) and numerical modelling were used to study geochemical interactions between CO\({}_{2}\)-induced fluids and reservoir rock during CCS. In the physical simulation, synthetic cores with composition consistent with geological samples were used to avoid interference from other geological factors such as sedimentary processes and diagenesis. The numerical simulation involved the same conditions of sample compositions, temperature, pressure, and fluid composition, with the two simulation types being mutually authenticating. Both numerical and physical simulations were used to document the process of short-term geochemical interactions after CO\({}_{2}\) injection. A consistency of results would indicate the reliability of the simulations, with outcomes expected to be similar to those pertaining to actual geological conditions.