## 3 Results
### Rock-Fluid Interaction
Partial Saturation  
To analyze the effect of salinity on oil-wet samples, rocks initially aged in oil at 80 \({}^{\circ}\)C were later placed in the 1% Na\({}_{2}\)SO\({}_{4}\) and 100% Na\({}_{2}\)SO\({}_{4}\) primes. The T\({}_{2}\) distribution collected after the oil aging process is considered the initial state of the rock sample (Figure 13a). The rock wettability alteration after the aging process into the two different salinitiy brines is shown in Figure 13b. Figure 13a corresponds to the wetting state after oil aging, showing the dominant mode location at 28.6 \(\pm\) 0.1 ms, which is comparable to the results in Figure 10, where the dominant mode is located at 25.5 \(\pm\) 0.1 ms. The T\({}_{2}\) response was expected, regardless of the observed difference that is a confirmation of the heterogeneity of the rock although both samples corresponds to Berea Sandstone. This differences could complicate the analysis of the partially saturated samples, since for common methodologies wettability alteration is directly related to saturation [11; 28]. Figure 13b shows the T\({}_{2}\) distribution of the rock sample after being aged in the two different brines. The appearance of a new peak between 100 and 200 ms corresponds to the brine intrusion into the rock. Since the effect of the the brine is the primary analysis target, a comparison between the trend offered by both brines can be developed. The dominant mode for 1% Na\({}_{2}\)SO\({}_{4}\) partially-saturated rock is located at 103.5 \(\pm\) 0.1 ms, while for the 100% Na\({}_{2}\)SO\({}_{4}\) partially-saturated rock the dominant mode is located at 137.5 \(\pm\) 0.1 ms, indicating the favorable effect of low-salinity on the pore surface and therefore the wettability alteration. This results cannot be directly related with the results in Figure 11a,b corresponding to rock fully saturated in 1% Na\({}_{2}\)SO\({}_{4}\) and 100% Na\({}_{2}\)SO\({}_{4}\) respectively, due to sample-to-sample variability. However, all systems show similar beneficial trend for low-salinity. A potential detachment of oil layers (or components) from the rock surface in the presence of low-salinity brine can produce a redistribution of phases in partially saturated systems, as the minimum of energy would require re-accommodation of fluid interfaces. This would be driven by changes in capillary pressure. The latter in conjunction with changes in relaxation mechanisms upon more exposure of the surface to water can contribute to the shifts in T\({}_{2}\) distribution modes, as shown in this section. This might help to provide an interpretation of T\({}_{2}\) distributions in partially saturated porous systems. Figure 12: Diffusion coefficient for rock saturated with different fluids 25 \({}^{\circ}\)C. (**a**) 1% Na\({}_{2}\)SO\({}_{4}\) and 100% Na\({}_{2}\)SO\({}_{4}\) for 21 days; (**b**) Crude oil for 21 days. Figure 14 shows more clearly the differences between the initial state of the rocks and after the aging process with the respective brine. These two plots indicate that for higher salinity (Figure 14a) there is not a significant change on the oil component T\({}_{2}\) dominant mode location, going from 28.9 \(\pm\) 0.1 to 25.9 \(\pm\) 0.1 ms. Meanwhile, the differences for the low salinity (Figure 14b) are more significant going from 28.8 \(\pm\) 0.1 to 21.38 \(\pm\) 0.1 ms. This indicates that low-salinity brine improves the oil production. However, the different position of the brine component dominant mode between both salinities, indicates that changes on wettability induced by the low salinity are more beneficial.