Low volumetric sweep efficiency, early breakthrough of injected fluid, and high risk of gas leakage from the reservoir are the major technical challenges associated with direct gas and water injection into oil reservoirs. Injection of carbonated water (CW) into oil reservoirs is a carbon dioxide-augmented water injection technique, which results in improved oil recovery and possible CO 2 storage in the reservoir. In this paper, the potential of carbonated water injection (CWI) into an Iranian carbonate reservoir for the purpose of improving oil recovery was investigated. In addition, the interfacial tension (IFT) of crude oil and two different carbonated brines (carbonated formation brine and carbonated seawater) as well as CO 2 solubility in these two carbonated brines was determined. Experimental results showed that CO 2 solubility in both brines increases with pressure and decreases with temperature. However, CO 2 solubility was more promising in seawater compared to formation brine because of the lower salinity. The IFT results showed that increasing the temperature from 40 to 100°C and increasing the pressure from 1000 to 2500 psi had a positive impact on reducing the IFT between carbonated brines and oil. In addition, core flooding experiments showed that oil recovery increased with CWI as compared to conventional water flooding (WF). However, secondary carbonated water injection (SCWI) resulted in higher oil recovery compared to tertiary carbonated water injection (TCWI). A maximum oil recovery of 21.75%, 61.63%, and 52.58% was achieved with conventional WF, SCWI, and TCWI, respectively.

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The solubility of CO 2 in brine is one of the trapping mechanisms by which the CO 2 is sequestrated in aquifers. In this research, an unconventional method, called the potentiometric titration, was used to obtain the solubility of CO 2 in distilled water and NaCl brine. The solubility data for the low salinity range are scarce in the literature. Thus, in this research, the CO 2 solubility was obtained in NaCl brines of low salinity (0−15 000 ppm) at temperatures between 60°C and 100°C and pressures up to 25 MPa. Moreover, the salting-out effect was estimated using the Setchenov's constant as a measure of reduction in solubility when salt is added to the solution. The solubility points obtained by the potentiometric titration method demonstrated very good consistency with those obtained by the previous methods.

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The creation of oil emulsions due to mechanical strength and natural surfactants during production is undesirable. The challenges associated with transporting and refining oil have led researchers to probe into practical demulsification methods. An in-depth understanding of crude oil rheology and operating conditions to treat emulsion is necessary. The main objective of the current study was to investigate the rheological behavior and demulsification rate of crude oil emulsions. The rheological behavior of a crude oil emulsion was studied by manipulating its temperature (30 °C–90 °C), shear rate (0.1–1000 s–1), and water volume fraction (20%, 30%, and 40%). For emulsions of various water content, the rheological studies followed the non-Newtonian shear thinning behavior, which was explained effectively by the Herschel–Bulkley model. Experimental results also indicated that the measured viscosity of emulsion decreased significantly with temperature, while increasing water volume fraction increased viscosity. The rates of demulsification of water in crude oil emulsion in direct current fields were investigated under various conditions by using an electrochemical cell. The separation rate of water increased along with the applied field, water content, and salt concentration. Results of this study indicated that emulsion separation was governed by the magnitude of the applied electric field as well as the type of electrode.