Kim, Ijung (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Worthen, Andrew J. (McKetta Department of Chemical Engineering, The University of Texas at Austin) | Lotfollahi, Mohammad (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Johnston, Keith P. (McKetta Department of Chemical Engineering, The University of Texas at Austin) | DiCarlo, David A. (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Huh, Chun (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin)
The immense nanotechnology advances in other industries provided opportunities to rapidly develop various applications of nanoparticles in the oil and gas industry. In particular, nanoparticle has shown its capability to improve the emulsion stability by generating so-called Pickering emulsion, which is expected to improve EOR processes with better conformance control. Recent studies showed a significant synergy between nanoparticles and very low concentration of surfactant, in generating highly stable emulsions. This study's focus is to exploit the synergy's benefit in employing such emulsions for improved mobility control, especially under high-salinity conditions.
Hydrophilic silica nanoparticles were employed to quantify the synergy of nanoparticle and surfactant in oil-in-brine emulsion formation. The nanoparticle and/or the selected surfactant in aqueous phase and decane were co-injected into a sandpack column to generate oil-in-brine emulsions. Four different surfactants (cationic, nonionic, zwitterionic, and anionic) were examined, and the emulsion stability was analyzed using microscope and rheometer.
Strong and stable emulsions were successfully generated in the combinations of either cationic or nonionic surfactant with nanoparticles, while the nanoparticles and the surfactant by themselves were unable to generate stable emulsions. The synergy was most significant with the cationic surfactant, while the anionic surfactant was least effective, indicating the electrostatic interactions with surfactant and liquid/liquid interface as a decisive factor. With the zwitterionic surfactant, the synergy effect was not as great as the cationic surfactant. The synergy was greater with the nonionic surfactant than the zwitterionic surfactant, implying that the surfactant adsorption at oil-brine interface can be increased by hydrogen bonding between surfactant and nanoparticle when the electrostatic repulsion is no longer effective.
In generating highly stable emulsions for improved control for adverse-mobility waterflooding in harsh-condition reservoirs, we show a procedure to find the optimum choice of surfactant and its concentration to effectively and efficiently generate the nanoparticle-stabilized emulsion exploiting their synergy. The findings in this study propose a way to maximize the beneficial use of nanoparticle-stabilized emulsions for EOR at minimum cost for nanoparticle and surfactant.
Lotfollahi, Mohammad (The University of Texas at Austin) | Kim, Ijung (The University of Texas at Austin) | Beygi, Mohammad R. (The University of Texas at Austin) | Worthen, Andrew J. (The University of Texas at Austin) | Huh, Chun (The University of Texas at Austin) | Johnston, Keith P. (The University of Texas at Austin) | Wheeler, Mary F. (The University of Texas at Austin) | DiCarlo, David A. (The University of Texas at Austin)
The use of foam in gas enhanced oil recovery (EOR) processes has the potential to improve oil recovery by reducing gas mobility. Nanoparticles are a promising alternative to surfactants in creating foam in the harsh environments found in many oil fields. We conducted several CO2-in-brine foam generation experiments in Boise sandstones with surface-treated silica nanoparticle in high-salinity conditions. All the experiments were conducted at the fixed CO2 volume fraction (g = 0.75) and fixed flow rate which changed in steps. We started at low flow rates, increased to a medium flow rates followed by decreasing and then increasing into high flow rates. The steady-state foam apparent viscosity was measured as a function of injection velocity.
The foam flowing through the cores showed higher foam generation and consequently higher apparent viscosity as the flow rate increased from low to medium and high velocities. At very high velocities, once foam bubbles were finely textured, the foam apparent viscosity was governed by foam shear-thinning rheology rather than foam creation. A noticeable "hysteresis" occurred when the flow velocity was initially increased and then decreased, implying multiple (coarse and strong) foam states at the same superficial velocity.
A normalized generation function was combined with CMG-STARS foam model to cover the full spectrum of foam flow behavior observed during the experiments. The new foam model successfully captures foam generation and hysteresis trends observed in presented experiments in this study and other foam generation experiments at different operational conditions (e.g. fixed pressure drop at fixed foam quality, and fixed pressure drop at fixed water velocity) from the literature.
The results indicate once foam is generated in porous media, it is possible to maintain strong foam at low injection rates. This makes foam more feasible in field applications where foam generation is limited by high injection rates (or high pressure gradient) that may only exist near the injection well. Therefore, understanding of foam generation, and foam hysteresis in porous media and accurate modeling of the process are necessary steps for efficient foam design in field.