## 3 Results
### Capillary Pressure and Relative Permeability Curves  
The PORE simulations were performed on a sub-cube centered on the lower right quadrant comprising 1000 slices with a width of 1000 pixels and a height of 1000 pixels. A threshold of 56 was used, which yielded a porosity of 15.4% and permeability of 813 mD. At 9.97 microns per pixel resolution, the porosity compares favorably with the NMR porosity at a diameter greater than 10 microns (16.2%), and the computed permeability is close to the measured permeability of 765 mD.  
Primary drainage consists of the displacement of water by oil until reaching the connate water saturation. As the rock is fully saturated with brine and has not been in contact with oil prior to the primary drainage, the water-wet conditions of an unaged rock represent this stage [64]. Primary drainage capillary pressure curves were obtained experimentally and by numerical simulations using the procedures described in Section 2. Connate water saturation (S\({}_{\text{wi}}\) = 0.089) was obtained experimentally and used as input in the simulations for quality control. The contact angle value obtained in Section 3.3 for the unaged rock (CA = 42.7\({}^{\circ}\)) was considered. In addition, the experimentally measured interfacial tension for this oil-brine system with no CO\({}_{2}\) content (IFT = 10.5 mN/m) previously reported by our group [43] was applied. Figure 7 shows good agreement between the experimental and simulated curves.  
Figure 6: Equilibrium contact angles between Pre-salt crude oil and formation brine on clean and 15 day aged coquinas. The test with CO\({}_{2}\) considers oil and brine saturated with CO\({}_{2}\). Experiment conditions: 60 \({}^{\circ}\)C and 6.895 MPa. The reported value is the mean of triplicate measurements, and the error bars represent the standard error of the mean.  
Figure 7: Experimental and numerical simulated primary drainage capillary pressure curves for the coquina sample considered in this work.  
Imbibition, consisting of the displacement of oil by water, represents the oil recovery process. It starts with the rock saturated with oil (at connate water saturation) at oil-wet conditions [64]. To compare the effects of water injection and carbonated brine injection, the imbibition relative permeability curves were simulated using the experimentally measured CA and IFT values for each case. CA values are reported in Figure 6 in this work, and IFT values were presented and discussed in previous work by our group [43]. It should be noted that the objective of these curves is to qualitatively analyze the effects of wettability and IFT alteration due to CO\({}_{2}\) injection on multiphase flow in the porous medium. They aim to support discussions regarding the effects of CO\({}_{2}\) on fluid displacement. As the quantitative effects of mineral dissolution and reactive transport were not included in these simulations, they are not intended to provide quantitative input data for reservoir modelling.  
Considering the results in Figure 6, the water injection case (with no CO\({}_{2}\)) indicated a neutral-wet (CA = 89.5\({}^{\circ}\)) rock and an IFT of 10.5 mN/m previously measured by our group [43]. By contrast, the carbonated brine injection case consisted of a water-wet rock (CA = 64.5\({}^{\circ}\), Figure 6) and an IFT of 16.4 mN/m, as reported in the aforementioned study. The results are shown in Figure 8.