Due to the high viscosity of heavy crude oils, production from these reservoirs is a demanding task. To tackle this problem, reducing oil viscosity is a promising approach. There are various methods to reduce viscosity of heavy oil: heating, diluting, emulsification, and core annular flow. In this study, dilution approach was employed, using industrial solvents and gas condensate. The viscosity of two Iranian heavy crude oils was measured by mixing with solvents at different temperatures. Dilution of both oil samples with toluene and heptane, resulted in viscosity reduction. However, their effect became less significant at higher concentrations of diluent. Because of forming hydrogen bonds, adding methanol to heavy crude oil resulted in higher viscosity. By adding condensate, viscosity of each sample reduced. Gas condensate had a greater impact on heavier oil; however, at higher temperatures its effect was reduced. Diluting with naphtha decreased heavy oil viscosity in the same way as n-heptane and toluene. Besides experimental investigation, different viscosity models were evaluated for prediction of heavy oil/solvent viscosity. It was recognized that Lederer' model is the best one

Nanofluids and low-salinity water (LSW) flooding are two novel techniques for enhanced oil recovery. Despite some efforts on investigating benefits of each method, the pros and cons of their combined application need to be evaluated. This work sheds light on performance of LSW augmented with nanoparticles through examining wettability alteration and the amount of incremental oil recovery during the displacement process. To this end, nanofluids were prepared by dispersing silica nanoparticles (0.1 wt%, 0.25 wt%, 0.5 wt% and 0.75 wt%) in 2, 10, 20 and 100 times diluted samples of Persian Gulf seawater. Contact angle measurements revealed a crucial role of temperature, where no wettability alteration occurred up to 80 °C. Also, an optimum wettability state (with contact angle 22°) was detected with a 20 times diluted sample of seawater augmented with 0.25 wt% silica nanoparticles. Also, extreme dilution (herein 100 times) will be of no significance. Throughout micromodel flooding, it was found that in an oil-wet condition, a combination of silica nanoparticles dispersed in 20 times diluted brine had the highest displacement efficiency compared to silica nanofluids prepared with deionized water. Finally, by comparing oil recoveries in both water- and oil-wet micromodels, it was concluded that nanoparticles could enhance applicability of LSW via strengthening wettability alteration toward a favorable state and improving the sweep efficiency.

In recent years, the application of smart water and surfactant in order to improve oil recovery has attracted special attention in carbonate reservoirs. In this research, the effects of various salts in smart water and two surfactants of Cetyl Trimethyl Ammonium Bromide (CTAB) and Sodium Dodecyl Sulfate (SDS) on the wettability alteration of carbonate rock and IFT were studied. Besides, along with micromodel flooding, core flooding tests were conducted to assess the amount of oil recovery at reservoir conditions as an injection scheme was used. In this regard, the results illustrated that the presence of CTAB or SDS in seawater (SW) can act better in contact angle reduction compared to smart water. Also, a four times increase in the concentration of SO₄²⁻ and removing Na⁺ from SW reduced the contact angle to 68° and 71°, respectively, being the best possible options to alter the carbonate surface wettability to more water-wet states. Moreover, in the second-order process in which the rock section was first placed in SW, and then was put in the smart solution (with or without surfactant), CTAB had a great effect on the wettability alteration. In the case of IFT reduction, although SW4Mg²⁺, compared to other ions, better decreased the IFT to 17.83 mN/m, SW + SDS and SW + CTAB further declined the IFT to 0.67 and 0.33 mN/m, respectively. Concerning different ions, divalent cations (Mg²⁺ and Ca²⁺) show better results in improving oil recovery factor. However, the combination of SW and surfactants has a more positive effect on boosting oil recovery, as compared to smart water flooding. It should be mentioned that the first-order injection is better than the second-order one since SW is flooded at first, and then, after the breakthrough, smart water is injected into the micromodel. In addition, the core flooding tests showed that SW + CTAB and SW + SDS in tertiary injection increased the oil recovery to about 59 and 57%, respectively, indicating that the presence of CTAB could be more effective than that of SDS.