# Using Low Salinity Waterflooding to Improve Oil Recovery in Naturally Fractured Reservoirs
## 4 Results and Discussion
### Full Field Scale Modelling  
A low salinity injection scenario has carried out in the north region of the Qamchuqa reservoir using six injection wells to sweep the oil towards the nearby producers, see Figure 13. The proposed locations of the injectors were designed to evaluate the impact of high salinity and low salinity brine injection scenarios on the performance of the Qamchuqa reservoir. Therefore, this injection design does not represent an optimal scenario of a secondary recovery project to develop the reservoir. The dual-porosity model was used to simulate the effect of change in wettability on the performance of the Qamchuqa reservoir under a low salinity recovery scheme and included the exponential weighting factor. A secondary recovery mode of low salinity brine injection was carried out for 14 years. The uncertainty in the change to the Qamchuqa reservoir wettability has been addressed by using three levels of alteration to the relative permeability (minimum, average, and maximum). Initially, the low salinity waterflooding scenarios gave a similar performance to the high salinity brine injection in the first six years of injection. Then, the change in wettability started to take effect  
Figure 11: Comparison of the simulation results between the single block model (solid line) and the intermediate scale model (dashed line). Almost identical recoveries were obtained which indicate that single block results can be used as a representative solution to a larger scale model under the same condition. Figure 12: Comparison of the simulation results between the imbibition case (solid line) and injection case (dashed line) of the intermediate scale model. Faster oil recovery in the imbibition case was observed in the early time while higher ultimate recoveries were obtained by the injection case. and could be seen at the producers. This helped maintain the oil productivity for an extra two and a half years at a rate of 38,000 STB/D compared to an average rate of 32,500 STB/D for the high salinity waterflooding. Meanwhile, the oil flow rate maintained its high rate of 32,500 STB/D to the end of the prediction scenario of year 14 compared with 25,000 STB/D for the high salinity brine injection. At the same time, a reduction in the field water cut by 32.5% was also observed, as the injected low salinity brine exchanged with the oil in the matrix blocks. This process led to a reduced volume of injected water reaching the producer (i.e., less water cut) and increased oil production, as illustrated in Figure 14.  
We can conclude from the above behaviour that the impact of the change in wettability required a longer time to sense its influence at the reservoir scale (six years were needed to show a significant effect on the Qamchuqa reservoir). Moreover, other impacts of the low salinity water injection on reservoir behaviour such as pressure maintenance. Pressure maintenance, in turn, has controlled the gas cusping in the producers; hence, preserving the drive mechanism energy of the dissolved gas or the gas cap in the Qamchuqa reservoir as well as less technical problems at the surface facilities due to excessive gas flow rate (e.g., field Gas-Oil Ratio (GOR) in Figure 15). That enabled the reduction of the  
Figure 14: Comparison of the waterflooding scenarios using high salinity and low salinity schemes in the Qamchuqa reservoir, using the exponential weighting factor. Figure 13: Contour maps of Upper and Lower Qamchuqa formations illustrates the northern region. The filled black dots refer to the drilled wells in the area, while the empty dots with an arrow indicate the proposed injection wells. workover cost, as most of the reported workover operations in the Qamchuqa reservoir were carried out due to the gas coning. The advantage of low salinity brine injection is the ability to initiate a chemical reaction that changes reservoir wettability to be more water-wet. This reduces the mobility of the water phase in the flooded regions of the reservoir.