Experimental Evaluation of Surfactant-based Nanofluids on Wettability Alteration and Oil Recovery
Economic concerns about chemical flooding could be taken as opportunities to develop new cost-effective technologies that lead to high recoveries. Application of surfactants to lower oil-water interfacial tension has never been an economically attractive EOR method due to the high amount of adsorption. However, the use of inexpensive surfactants in low concentrations or combination of diluted surfactants with other low-cost chemicals to change the wettability of the system could play a major role in reducing the residual oil saturation and consequently improving oil recovery. This experimental study aims at investigating the potential of nanoparticles to improve the ability of surfactants for enhancing oil recovery in carbonate rocks through wettability alteration using contact angle measurements and coreflood experiments at different experimental conditions.
Dual-Drop Dual-Crystal (DDDC) technique was used to measure the dynamic water advancing contact angles along with the interfacial tension at both ambient and reservoir conditions. A range of surfactants with different chemical structures was tested to select a candidate with the weakest and strongest ability for wettability alteration. The optimum concentration of nanoparticles was determined to combine with the surfactant. The improvements in the wettability alteration behavior of surfactant-based nanofluids were determined through contact angle measurements and supported by coreflood experiments through oil recovery and simulated relative permeability curves.
The optimum concentration of nanoparticles (0.4% wt.) helped to change the wettability of a limestone rock from strongly oil-wet (water advancing contact angle of 167°) to weakly oil-wet (146°) at ambient conditions. The combination of nanoparticles with the least effective surfactant resulted in an incremental recovery of about 37% and improved the wettability alteration capability to reach an intermediate-wet condition (116°) and stayed in the intermediate-wet zone (121°) even after lowering the concentration of surfactant. The combination of nanoparticles with the most effective surfactant reached an incremental recovery of about 45% compared to using only surfactant. At reservoir conditions, the surfactant-based nanofluid changed the wettability behavior from strongly oil-wet (156°) to intermediate-wet (108°) and led to an incremental recovery of about 30%. The contact angle measurements agreed well with the oil recovery and oil-water relative permeabilities simulated from the coreflood experiments. A preliminary cost analysis showed that combining nanoparticles with diluted surfactants could result in an extra $4.39 profit per barrel of oil.
By measuring precise and reproducible advancing contact angles at both ambient and reservoir conditions and conducting coreflood experiments at different experimental conditions and through investigating the simulated relative permeability curves, this study clearly reveals a potential for nanoparticles to improve the performance of surfactants to change the wettability of carbonate rocks toward less-oil wet or intermediate-wet, which could lead to a significant reduction in the residual oil saturation and enhancement in the oil recovery. Introducing nanoparticles to diluted surfactant solutions affords an opportunity to change the wettability of carbonate rocks toward enhancing oil recovery, thus provides an economically appealing chemical flooding technique.