Wettability alteration can occur at different stages during the producing life of a reservoir. Oil recovery from oilwet reservoirs can significantly be increased by altering its wettability from an oil-wet to a strongly water-wet condition. Chemical agents such as surfactants are known as wettability modifiers in oil-wet systems. More recently, nanofluids prepared by dispersing nanoparticles in several liquid agents have been considered as potential wettability modifiers. In this work, the effectiveness of alumina-based nanofluids in altering the wettability of sandstone cores with an induced oil-wet wettability was experimentally studied. Eight nanofluids with different nanoparticles concentration, ranging from 100 ppm to 10000 ppm, were prepared by dispersing alumina nanoparticles in an anionic commercial surfactant. The effect of nanofluids on wettability alteration was investigated by contact angle and imbibition tests, and it was shown that designed nanofluids could significantly change the wettability of the sandstone cores from a strongly oil-wet to a strongly water-wet condition. Imbibition tests also allowed identifying the effect of nanoparticles concentration on the suitability of the treatment for enhancing the imbibition process and restoring the original core wettability. Results showed that the effectiveness of the anionic surfactant as wettability modifier could be improved by adding nanoparticles in concentrations lower or equal than 500 ppm. The best performance was achieved when a concentration of 100 ppm was used. Additionally, a core displacement test was carried out by injecting in a sand pack a nanofluid prepared by dispersing alumina nanoparticles in distillated water. The treatment was effective in altering the sand pack wettability from an oil-wet to a strongly water-wet condition as indicated by a significant reduction in the residual water saturation and a displacement to the right of the oil relative permeability curve and the crossover point.

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This work aims to investigate the effect of active catalytic nanoparticles on the improvement of the efficiency in recovery of a continuous steam injection process. Catalytic nanoparticles were selected through batch-adsorption experiments and the subsequent evaluation of the temperature for catalytic steam gasification in a thermogravimetric analyzer. A nanoparticulated SiO 2 support was functionalized with 1.0 wt % of NiO and PdO nanocrystals, respectively, to improve the catalytic activity of the nanoparticles. Oil recovery was evaluated using a sand pack in steam injection scenarios in the absence and presence of a 500 mg/L SiNi1Pd1 nanoparticles-based nanofluid. The displacement test was carried out by constructing the base curves with water injection followed by steam injection in the absence and presence of the prepared treatment. The oil recovery increased 56% after steam injection with nanoparticles in comparison with the steam injection in the absence of the catalysts. The API gravity increases from 7.2 • to 12.1 •. Changes in the asphaltenes fraction corroborated the catalytic effect of the nanoparticles by reducing the asphaltenes content and the 620 • C+ residue 40% and 47%, respectively. Also, rheological measurements showed that the viscosity decreased by up to 85% (one order of magnitude) after the nanofluid treatment during the steam injection process.

Foams in the oil and gas industry have been used as divergent fluids to attenuate the fluid channeling in high-permeability zones. Commonly, foams are generated using a surfactant solution in high-permeability reservoirs, which exhibit stability problems. Therefore, the main objective of this study is to stabilize the foams by the addition of modified silica nanoparticles, varying the surface acidity and polarity for natural gas flooding in tight gas-condensated reservoirs. Four types of modified silica-based nanoparticles with varying surface acidity and polarity (coated with vacuum residue) were synthesized and evaluated using surfactant adsorption. The basic nanoparticles exhibited a greater adsorption capacity of the surfactant, reaching an adsorbed amount of approximately 200 mg of surfactant per gram of nanoparticles, and Type I adsorption behavior. Foams were generated and evaluated based on their stability using two routes, namely, (1) with mechanical agitation and (2) methane flooding, to determine the optimal concentration of nanoparticles to be used. In both scenarios, foam height was monitored against time, and the half-life of the foam was established. The nanofluid prepared using a surfactant solution and 500 mg/L of basic nanoparticles reached a half-life 41% greater than that of the fluid that does not contain nanoparticles. In addition, a core flooding test was performed to evaluate the generation and perdurability of the foam (with and without nanoparticles) by methane flooding and the mobility reduction at typical reservoir conditions (confinement and pore pressure of 5200 and 1200 psi, respectively, and temperature of 100 °C). The porous medium was obtained from a tight gas-condensate reservoir, and it has an absolute permeability of 65.1 mD and a porosity of 7%. The oil recovery with methane injection was about 52%; with foam injection, an additional 10% was obtained, and an 18% additional recovery was reached with the injection of foam and nanoparticles.