## 3 Results and Discussion  
### Optimal Surfactant Ratio Concentration  
In Figure 1, we observe that the oil/formation water contact angle shows a specific pattern of variation as a function of solution salinity. The data clearly show that the contact angle tends to stabilize and maintains a constant value of about 75\({}^{\circ}\) as the solution salinity drops below about 1800 mg/L. This phenomenon indicates that at this salinity level, the wetting characteristics of the oil/water interface are less affected by salinity, suggesting that the optimum surfactant ratio concentration is reached. Figure 1: Trend chart of contact angle of oil/formation water with salinity variation. As can be seen from the graph, the effect of low-salinity rationed solutions on the contact angle is negligible, an observation that provides an important basis for investigating the mechanism of the effect of low-salinity solutions on wettability alteration. The potential causes of wettability alteration are as follows:  
(1) Effect of salinity: In low salinity environments, salinization is reduced, making it easier for polar organic molecules to dissolve in the aqueous phase. This is due to the increased solubility of organic molecules under low salinity conditions, which reduces their aggregation in the oil phase. During formation aging, these polar organic substances are usually adsorbed on the surface of hydrocarbon-occupied pores, resulting in an oil-wet surface. As salinity decreases, the desorption of these molecules from the pore surface increases, resulting in a more hydrophilic wettability of the porous medium. However, in the actual oil recovery process, measures to enhance recovery efficiency tend to have a positive impact only at the micro level due to the spatial distance limitation of the osmotic adsorption effect. This means that although recovery enhancement can be observed at a small scale, it is often difficult to significantly improve overall recovery efficiency at the macro level, i.e., over the entire stratigraphic expanse. To address this issue, according to the relevant experiments of [PERSON] and [PERSON] et al. (2023) on low-salinity water drive for enhanced recovery, we also used NaCl solutions with mass fractions of 10.00%, 1.00%, and 0.10%, respectively, and kept the injection rate at 0.2 mL/min, and the change of oil drive efficiency with the amount of injection is shown in Figure 2.  
As can be seen from Figure 2, in the final stage of the experiment, the recovery rate was 54.79% when the mass fraction of NaCl aqueous solution was 10.00%; while the recovery rate increased to 57.69% when the salinity was reduced to 1.00%; and the recovery rate was highest at 62.17% when the salinity was further reduced to 0.10%. This indicates that low-salinity aqueous solutions can achieve higher recovery rates in the oil drive process. However, higher salinity leads to a faster oil drive rate in the initial stage of injection, which is consistent with the experimental results of [PERSON] as well as [PERSON] et al. (2014, 2023). (2) Interlayer Swelling Effect: In the context of fractured reservoirs, the phenomenon of interlayer swelling significantly influences wettability alterations. The rock surface charge distribution is intricately linked to the ionic concentration within the brine. Reducing the salinity of the brine induces swelling of the water molecule layer adjacent to the rock surface. Predominantly, this swelling arises from ion exchange processes, where sodium ions in the aqueous solution are replaced by calcium ions released from dissolved carbonate rocks. This exchange leads to a reduction in the positive charge density on the rock surface. Figure 2: The variation of water-oil displacement efficiency with different salinities over time (according to [PERSON] et al., 2023). Such a modification facilitates the segregation of oil and water phases, thereby enhancing the wettability of the reservoir.