No abstract

One of the common challenges of applying foam for enhanced oil recovery is the foam instability in the presence of crude oil and nonwater-wet surfaces. In this experimental study, we systematically distinguish the effect of rock surface wettability from that of crude oil saturation on foam rheology under reservoir conditions. Neutral-wet Berea and reservoir sandstone cores are prepared by aging with crude oil, followed by the wettability index measurements. Transient foam generation and steady-state foam quality scans are conducted in neutral-wet cores, with/without water-flood residual oil. Nuclear magnetic resonance imaging is also utilized to measure the remaining oil saturation at the end of the foam-flood. It is shown that strong foam can be generated in a neutral-wet core with no residual oil because of the solubilization of the adsorbed crude oil components and the wettability alteration toward more water-wet conditions. However, in a neutral-wet core containing residual oil, foam generation is initially hindered. Foam generation occurs after injecting several pore volumes of surfactant solution and increasing the superficial velocity to overcome the minimum pressure gradient required for in situ foam generation. The findings from this study suggest that surface wettability in the presence of bulk oil saturation significantly affects transient foam generation. The final steady-state foam strength becomes comparable to the water-wet and oil-free case once the residual oil saturation is adequately reduced.

The effects of velocity and gas type on foam flow through porous media have yet to be completely elucidated. Pressure drop and capillary pressure measurements were made at ambient conditions during a series of foam quality scan experiments in a homogenous sandpack while foam texture was simultaneously visualized. New insights into foam-flow behavior in porous media were discovered. Previously accepted “limiting” capillary pressure theory is challenged by the findings in this work, and the “limiting” terminology is replaced with the word “plateau” to reflect these novel observations. Plateau capillary pressure $${(P}_{c})$$ ( P c ) and transition foam quality were found to increase with velocity. Transition foam quality was found to depend mostly on liquid velocity rather than gas velocity and is physically linked to foam type (continuous vs. discontinuous) and texture (fine vs. coarse). Distinct rheological behaviors also arose in the low- and high-quality foam regimes as a function of velocity. Foam flow was found to be strongly shear thinning in the low-quality regime where foam texture was fine and discontinuous. In the high-quality regime, the rheology was weakly shear thinning to Newtonian for coarsely textured foam and continuous-gas flow respectively. When all other variables were held constant, at ambient conditions, CO2 foam was found to be weaker with also lower capillary pressures than N2 foam and the differences in gas solubility is a likely explanation.

Nonionic surfactants are increasingly being applied in oil recovery processes due to their stability and low adsorption onto mineral surfaces. However, these surfactants lead to the production of emulsified oil that is extremely stable and difficult to separate by conventional methods. This research characterizes the stability of crude oil mixed with a nonionic surfactant, L24-22, in a brine solution. When subjected to gravity separation, a middle oil-rich and bottom waterrich emulsion are generated for various water-oil ratios. Thermal treatments can effectively break oil-rich emulsions, but the bottom water layer remains contaminated with micron-sized crude oil droplets. A magnetic nanoparticle treatment is shown to demulsify the crude oil emulsions, dropping the total organic carbon (TOC) in the water layer from 1470 to 30 ppm. K E Y W O R D S application of surfactants, analytical chemistry and techniquesLeilei Zhang and Chutian Bai contributed equally to this study.