Soroush Ahmadi

In this work, the process of low salinity water injection (LSWI) into reservoirs at various salt concentrations was simulated in order to study the change in the oil recovery factor during oil production. The simulation results of the recovery factor were compared with the experimental data. The results demonstrated that the simulation data were in good agreement with the experimental results. In addition, the formation damage (rock permeability reduction) in carbonate core samples was evaluated through coreflood experiments during LSWI in the range of salt concentration and temperature of 1500–4000 ppm and 25–100 °C, respectively. In the worst scenario of LSWI, the rock permeability has reached about 83% of the initial value. Our previous correlation was used to predict the formation damage in LSWI. In this case, the R-squared value between predicted and experimental data of rock permeability ratios was more than 0.97. Furthermore, the recovery factor during LSWI was analyzed with and without the use of DTPMP scale inhibitor (diethylenetriamine penta (methylene phosphonic acid)), and various nanoparticles (TiO2, SiO2, Al2O3). The results of the coreflood experiments showed that the use of scale inhibitor provides an increase in the recovery factor by more than 8%. In addition, the highest recovery factor was observed in the presence of SiO2 nanoparticles at 0.05 wt.%. The oil displacement during LSWI in the porous media with SiO2 particles was better than TiO2 and Al2O3. The recovery factor in the presence of SiO2, TiO2, and Al2O3 with DTPMP was 72.2, 62.4, and 59.8%, respectively. Among the studied nanoparticles, the lowest values of the oil viscosity and interfacial tension (IFT) between oil and water were observed when using SiO2. Moreover, the contact angle was increased by increasing the brine concentration. The contact angle with the use of SiO2, TiO2, and Al2O3 at 0.05 wt.% was reduced by 11.2, 10.6, and 9.9%, respectively.