Nowadays, molten salts are widely used in concentrated solar plants as working media to transfer and store solar energy. However, the relatively poor thermal properties of molten salts have restricted their further application. Nevertheless, the addition of nanoparticles to molten salts excellently improves these thermal properties. In present work, solar salt-based nanofluids were prepared using a lyophilizer. The specific heat of solar salt-based SiO 2 nanofluids was experimentally measured based on the sapphire method, and its heat transfer performance was numerically investigated using the lattice Boltzmann method. Results indicated that an optimum nanoparticle mass fraction that could enhance heat transfer performance existed. This optimum nanoparticle mass fraction, which was found to be 1.0 wt%, improved the heat transfer coefficient and Nu number by 8.58 and 7.29%, respectively. The parameter analysis indicated that the considerably large change in the specific heat dominated the change in heat transfer performance. Meanwhile, the simulation results of the average Nu numbers exhibited good agreement with the Shah-London correlation prediction to within ±3.0%, indicating the feasibility of using this correlation in designing heat exchangers that utilize solar salt-based SiO 2 nanofluids.
This study investigated the mechanisms and performance of SiO2 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.
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