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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.

Scale precipitation is one of the major problems in the petroleum industry during waterflooding. The possibility of salt formation and precipitation should be monitored and analyzed under dynamic conditions to improve production performance. Scale precipitation and its dependence on production parameters should be investigated before using scale inhibitors. In this study, the precipitation of barium sulfate salt was investigated through dynamic tube blocking tests at different injection rates and times. For this purpose, the pressure drop caused by salt deposition was evaluated at injection rates of 1, 2, 3, 4, and 5 mL/min. The software determined the worst conditions (temperature, pressure, and water mixing ratio) for barium sulfate precipitation. Moreover, during the experiments, the pressure drop caused by barium sulfate precipitation was measured without using scale inhibitors. The pressure drop data were evaluated by the response surface method and analysis of variance to develop a new model for predicting the pressure drop depending on the injection rate and time. The novelty of this study lies in the development of a new high-precision correlation to predict barium sulfate precipitation under dynamic conditions using the response surface methodology that evaluates the effect of injection rate and time on the possibility of salt precipitation. The accuracy and adequacy of the obtained model were confirmed by using R2 statistics (including R2-coefficient of determination, adjusted R2, and predicted R2), adequate precision, and diagnostic charts. The results showed that the proposed model could fully and accurately predict the pressure drop. Increasing the time and decreasing the injection rate caused an increase in pressure drop and precipitation of barium sulfate salt, which was related to the formation of more salt due to the contact of ions. In addition, in a short period of the injection process, the pressure drop due to salt deposition increased sharply, which confirms the need to use a suitable scale inhibitor to control salt deposition. Finally, the dynamic tube blocking tests were repeated in the presence of two well-known scale inhibitors, which prevented salt deposition in the tubes. At the same time, no pressure drop was observed in the presence of scale inhibitors at all injection rates during a long period of injection. The obtained results can be used for the evaluation of salt precipitation during oil production in the reservoirs, in which barium sulfate is precipitated during waterflooding. For this purpose, knowing the flow rate and injection time, it is possible to determine the amount of pressure drop caused by salt deposition.

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In this work, the corrosion inhibition of carbon steel in 1 molar HCl solution was evaluated by experimental and modeling approaches using 2-mercaptobenzimidazole (2-MBI). To this end, an experimental design for the weight loss method using response surface methodology (RSM) was carried out and the corrosion rate (CR) and inhibition efficiency (IE) were determined. The study was completed at various values of temperature, exposure time, and inhibitor concentration to determine the optimal conditions for corrosion prevention. Using experimental data on the corrosion rate and inhibition efficiency of 2-MBI, new models were developed, the significance of which was tested using ANOVA-analysis of variance. The developed RSM-based CR and IE models were highly accurate and reliable, and their P-values were less than 0.0001. The novelty of this study lies in the newly developed model for the evaluation of 2-MBI inhibition performance and its application to high-temperature conditions in the petroleum industry. Besides, the R2-statistics (R2, adjusted-R2, and predicted-R2), adequate precision and diagnostic plots were used as main measures to verify the accuracy and adequacy of both CR and IE models. In addition, it was observed that inhibitor concentration had the most impact on both CR and IE models compared to other parameters due to its largest F-values (561.65 for CR and 535.56 for IE models). Moreover, the results indicated that adding 140–150 ppm of 2-MBI at low-level temperatures of 30–35 °C had the most interaction effect on the performance of the corrosion inhibition process. In this case, the CR was less than 0.9 mm/y and the IE more than 94%, even after a high exposure time of 105 h. Furthermore, numerical optimization of the corrosion inhibition process for 2-MBI showed that the optimum conditions for maximum IE and minimum CR were achieved at a concentration of 115 ppm, temperature of 30.7 °C, and exposure time of 60.4 h. Under these conditions, the efficiency and corrosion rate were 92.76% and 0.53 mm/y, respectively. Finally, the adsorption of 2-MBI on the sample surface was studied at various exposure times and temperatures. In all cases, the adsorption behavior obeyed the Langmuir isotherm. In this case, the Gibbs adsorption free energy varied from − 33 to − 37 kJ/mol, which reflects both physical and chemical adsorption of the corrosion inhibitor at all tested temperatures and test times.