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An important factor during the life of a heavy crude reservoir is the oil mobility. It depends on two factors, oil viscosity and oil relative permeability. Two characteristics of nanoparticles that make them attractive for assisting IOR and EOR processes are their size (1 to 100 nm) and ability to manipulate their behavior. Due to their nano-sized structure, nanomaterials have large tunable specific surface areas that lead to an increase in the proportion of atoms on the surface of the particle, indicating an increasing in surface energy. Nanoparticles are also able to flow through typical reservoir pore spaces with sizes at or below 1 micron without the risk to block the pore space. Nanofluids or "smart fluids" can be designed by tuning nanoparticle properties, and are prepared by adding small concentrations of nanoparticles to a liquid phase in order to enhance or improve some of the fluid properties. However the use of nanoparticles and nanofluids for oil mobility has been poorly studied. Hence, the scope of this work is to present the field evaluation of nanofluids for improving oil mobility and mitigate alteration of wettability in two Colombian heavy oil fields; Castilla and Chichimene. Asphaltenes sorption tests with two different types of nanomaterials were performed for selecting the best nanoparticle for each type of oil. An oil based nanofluid (OBN) containing these nanoparticles was evaluated as viscosity reducer under static conditions. Displacement tests through a porous media in core plugs from Castilla and Chichimene at reservoir conditions were also performed. OBN was evaluated to reduce oil viscosity varying oil temperature and water content. Maximum change in oil viscosity is achieved at 122°F and 2% of nanofluid dosage. The use of the nanofluid increased oil recovery in the core flooding tests, caused by the removal of asphaltenes from the aggregation system, reduction of oil viscosity, and the effective restoration of original core wettability. Two field trials were performed in Castilla (CNA and CNB wells), by forcing 200 bbl and 150 bbl of nanofluid respectively as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 270 bopd in CNA and 280 bopd in CNB and BSW reductions of ~11% were observed. In Chichimene also two trials were performed (CHA and CHB), by forcing 86 bbl of and 107 bbl of nanofluid as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 310 bopd in CHA and 87 bopd in CHB were achieved not BSW reduction has been observed yet. Interventions were performed few months ago and long term effects are still under evaluation. Results look promising making possible to think extending application of nanofluid in other wells in these fields.

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.