# Using Low Salinity Waterflooding to Improve Oil Recovery in Naturally Fractured Reservoirs
## 4 Results and Discussion
### Single Matrix Block Model  
An exponential weighting factor was used to simulate the low salinity waterflooding scenario, and the outcome was compared with the same model using a linear weighting factor. The results of the two weighting factor approaches were almost similar with a marginal difference of 0.1%, 0.2%, and 0.7% of the ultimate oil recovery for the minimum, average, and maximum alteration, respectively. However, the improvement in the oil recovery of the fine-scale model due to the impact of low salinity  
Figure 7: The effect of low salinity waterflooding on the relative permeability curves. (**A**) Generated relative permeability sets due to wettability alteration and residual oil saturation. (**B**) Fractional flow of water for the generated relative permeability sets, where the water breakthrough time delayed by 47% when maximum alteration used (indicated by red legend) compared to the high salinity set (indicated by black legend).  
waterflooding is 2.3%, 7.5%, and 13% of STOIIP for the earlier mentioned alteration degree, respectively, as illustrated in Figure 8. These incremental percentages were calculated based on the result of the high salinity waterflooding scenario. In this fine-scale model, the single-porosity model was used in the simulation. Meanwhile, the same matrix block has been modelled using the dual-porosity model. The increment in oil recovery for the single block model using the dual-porosity option is 1.5%, 6.7%, and 10.7% of STOIIP for the minimum, average, and maximum cases, respectively, compared with the high salinity waterflooding scenario. The results of the above scenarios were compared to highlight the outcome differences, as illustrated in Figure 9 and summarised in Table 3.  
The highlighted differences in the above table confirm the tendency of the dual-porosity model to overestimate the predicted oil recovery, the recovery speed, and the saturation profile, as concluded by [1; 39]. Furthermore, the recovery speed and saturation front were significantly higher compared with the fine-scale modelling, as shown in Figure 9. The optimistic oil recovery of the dual-porosity model resulted from an exaggeration in the fluid exchange rate between the matrix and fractures. Moreover, the total height of the matrix block in the dual-porosity model (i.e., 12 ft) contributed to the oil exchange rate in the transfer rate calculations. Meanwhile, the height of a single cell in the fine-scale model (i.e., 1 ft based on the model resolution) has used in the fluid exchange calculations, which has a lower contribution. Moreover, the advancement of the low salinity waterfront took a longer time to sweep the same equivalent volume of the corresponding matrix block of the dual-porosity model. Figure 10 illustrates the saturation profile of the low salinity water phase in the fine-scale model and the single block model after 10 days. A single saturation value was computed for the matrix cell in the dual-porosity model, as illustrated in Figure 10A. Meanwhile, every cell in the fine-scale model show variations in saturation, see Figure 10B. Furthermore, the total exposed volume of the matrix for the fluid exchange with fractures are 480 ft\({}^{3}\), and 300 ft\({}^{3}\) for the dual-porosity model and the fine-scale model, respectively, which affected the matrix recovery in the early time. Therefore, the dual-porosity model exhibited a higher oil recovery due to the larger matrix volume exposed to the fluid exchange with fractures. The dominant force of the capillary pressure can be identified in Figure 10B, where the fluid transfer occurs in all directions of the matrix blocks.