This study investigated the mechanisms and performance of SiO 2 nanofluid for enhanced oil recovery (EOR) in low-permeability cores. Three-phase contact angles for quartz/oil/brine systems were measured, and the microscopic imbibition characteristics of nanofluids in a capillary were observed through visualization experiments. In addition, the effects of the adsorption of the nanoparticles on the oil−water relative permeability was studied using core displacement tests. Furthermore, a total of 11 core flooding tests were performed, and the effects of injection parameters, such as nanoparticle concentration, injection rate, and injection scheme, on the oil recovery were investigated. Wettability alterations were observed among quartz/ oil/brine systems that contributed to higher displacement efficiencies in microscopic imbibition tests. Relative permeability measurements showed that, upon the adsorption of the nanoparticles, the irreducible water saturation and oil-phase relative permeability increased whereas the water-phase relative permeability decreased. Moreover, nanoparticles tended to adhere to the pore surface of the rock, which significantly changed the wettability of cores to strongly water-wet conditions. Nanofluid displacement tests showed that additional 4.48−10.33% increments in the oil recovery can be obtained compared to conventional waterflooding. With increasing nanoparticle concentration, the viscosity and asphaltene content of the produced oil gradually decreased. The results showed that the optimum nanoparticle concentration was 10 ppm, whereas further a increase in the injected nanoparticle concentration could plug the pore throats, resulting in a slight decrease in tertiary oil recovery. The effects of nanofluid imbibition on the recovery were more significant at lower injection rates, leading to higher recoveries. Furthermore, it was found that cyclic nanofluid injection can provide higher tertiary oil recovery than a continuous nanofluid injection scheme.
The deposition of asphaltenes in porous media is one of the most difficult problems during CO2 flooding. In this paper, the adsorption of asphaltenes onto Al2O3 nanoparticles was studied through two methods: (i) by adding a certain mass of nanoparticles in a fixed volume of solution with different initial concentrations of asphaltenes and (ii) by exposing a certain amount of asphaltenes in a fixed volume of solution to different nanoparticles additions. Then, the impact of Al2O3 nanoparticles on the asphaltene precipitation was investigated using the IFT behavior of the oil–CO2 system. Coreflood tests were conducted to study the potential of nanoparticles for inhibition of asphaltenes damage during CO2 flooding, and the effect of injection parameters of nanofluid. It is found that the solid–liquid equilibrium (SLE) can well describe the isotherms of asphaltene adsorption. The trend of the IFT–pressure curve is affected by asphaltene accumulation at the oil–CO2 interface. The slopes in the high pressure region can be used to examine the intensity of asphaltene precipitation. As the addition of nanoparticles increases, the IFT slope in the high pressure range decreases. This is because the asphaltenes are absorbed at the surface of nanoparticles. As a result, the nanoparticles prevent asphaltene precipitation from accumulating at the CO2–oil interface, hence causing asphaltene to remain within the bulk of oil. The higher the mass fraction of Al2O3 nanoparticles is, the lower the intensity of the asphaltene precipitation would be. The coreflood results show that the injection of Al2O3 nanofluid can lessen the oil permeability reduction because the nanoparticles can inhibit the deposition of asphaltenes onto the sand surfaces in the porous media. The 0.5 wt % nanoparticles and the 0.1 nanofluid/CO2 slug volume ratio are considered as the optimum for inhibiting asphaltenes damage during CO2 flooding. Continuous CO2 and nanofluid injection could be more effective compared with the cyclic injection pattern.
Foamy oil flow has been successfully demonstrated in laboratory experiments and site application. On the basis of microscopic visualization experiments of the heavy oil from Orinoco Belt in Venezuela, effects of the pressure depletion rate and temperature on foamy oil microflow characteristics were researched. Through physical simulation experiments for solution gas drive, effects of the pressure depletion rate, temperature, and permeability on foamy oil drive were investigated. In comparison to solution gas drive for light oil, gas disperses in heavy oil forming a stable foam state for foamy oil. There are bubble division, bubble merging, and bubble deformation during foamy oil flow in porous media. As the pressure depletion rate increases, bubbles in foamy oil are more dispersed and foamy oil is more stable. As the temperature increases, bubble move velocity increases obviously. The increase of the pressure depletion speed is beneficial to improve the oil recovery efficiency of foamy oil. The oil recovery efficiency of foamy oil first increases and then decreases with the temperature. The best temperature for the foamy oil in the MPE3 block is about 110 °C. Oil recovery efficiency of foamy oil increases with the sandpack permeability, and foamy oil is adapted to high-permeability reservoirs. The experimental results can provide theoretical support for foamy oil production.
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