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Crude oil reservoirs have different temperatures, compositions, and pressures, therefore oil recovery performance by CO 2 injection varies from one case to another. Furthermore, it is predicted that lower interfacial tension between injected CO 2 and reservoir fluid results in more oil recovery. In this study, we investigate the effect of temperature on the equilibrium interfacial tension between CO 2 and three different oil fluids at different pressures. Also minimum miscible pressure (MMP) is measured by the vanishing interfacial tension (VIT) technique to determine the temperature effect on the CO 2 miscible gas injection. The results on different pure and mixtures of hydrocarbon fluids show that for pressures up to 5.2 MPa, the higher the temperature was, the lower was the interfacial tension (IFT) measured. However, for the cases with pressure higher than 5.2 MPa, as the temperature was increased, the IFT increased too. In addition the VIT technique is used to measure the MMP of CO 2 and pure paraffin; the heavier paraffin was, the higher was the MMP noticed. Also, we have learned that paraffin groups have an important effect on multicomponent interfacial tension behavior.

The use of adjusted/optimized saline water categorized into two different classes namely smart water (SW) and low salinity (LoSal) water injection has been proposed for more oil recovery from specific types of oil reservoirs. There are possible mechanisms concerning SW flooding that have been proposed in the literature, some of them are still subject to more examination. In this study, an experimental investigation is performed to determine the influence of type and amount of salt to the surface properties including interfacial tension (IFT) and contact angle (CA) of aqueous solution + acidic and asphaltenic crude oil + carbonate rock systems. For this purpose, the concentration of different salts including NaCl, KCl, Na2SO4, MgSO4, CaSO4, CaCl2, and MgCl2 are examined in a wide range of concentrations. The measurements revealed that salinity has dual impacts on the CA of water wet surfaces of carbonate rock. That is, CA could remain unchanged or increase as a function of brine salinity, though the increase was still within the strongly water-wet region of wettability with high film stability. The results of IFT measurements show that using ions especially divalent cations in the presence of chloride anion could substantially decrease the IFT values. The results show that the lowest IFT values are obtained at high salinity conditions (above 0.053 mol·kg–1) especially if divalent ions of MgCl2 are utilized. High values of IFT are obtained if monovalent salts such as NaCl and KCl are used.

Carbon dioxide miscible flooding has become a popular method for Enhanced Oil Recovery (EOR) because it not only efficiently enhances oil recovery but also considerably reduces green house gas emissions. However, it can significantly cause asphaltene deposition, which leads to serious production problems such as wettability alteration, plugging of the reservoir formation, blocking the transportation pipelines, etc. It is crucial to investigate the effects of different factors on asphaltene deposition. A novel experimental setup was prepared to employ a high-pressure visual cell for investigation of asphaltene deposition on a model rock under typical reservoir conditions. The evolution of asphaltene deposition was monitored via a highresolution microscope. Image processing software was utilized to check the amount of deposited asphaltene and its size distribution under different conditions. Crudes from two Iranian oil fields were used in the experiments. The amount of asphaltene deposition was measured during pressure depletion under two operating conditions: with/without CO 2 -injection. It was observed that the amount of deposited asphaltene decreases with pressure depletion. For instance, asphaltene deposition at 140 bar and 90 °C is 5.7 times greater compared to 30 bar and 90 °C condition. The results of CO 2 gas injection confirm that the deposited asphaltene increases with the concentration of injected CO 2 . According to the results, a temperature increase from 35 to 90 °C contributes to growth and aggregation of asphaltene particles. A comparison of two different asphaltene sources in terms of aggregation and flocculation behavior revealed that the asphaltene molecular structure could have a noticeable influence on asphaltene deposition. A new parameter was defined as the potential of deposition to describe, quantify, and compare the tendency of different asphaltene samples for flocculation and deposition.