Surfactants are one of the essential additives included in hydraulic fracturing fluids to decrease interfacial tension to improve flow back to the surface for better well productivity. The surfactant can be adsorbed on the formation surface, changing reservoir wettability, which can be beneficial to the initial oil recovery when the well is put back on production after the fracturing treatment. Considering the high chemical costs and low oil prices, maximizing the utilization of surfactants placed in hydraulic fracturing fluids can be an economical solution.

Due to the unique characteristics of shale formations including low permeability, existence of micro-fractures, and sensitivity to the contact fluids, it is difficult to evaluate the complex microscopic interactions between surfactant and the formation in a traditional laboratory setting. Prior work (Kim et al. 2015) demonstrated the value of a new testing method using Nuclear Magnetic Resonance (NMR) to evaluate the surfactant performance on fracturing fluid flowback recovery. This work further optimizes surfactant to benefit both flowback recovery and oil recovery to provide a recommendation for Eagle Ford formation.

For oil recovery testing, Eagle Ford outcrop cores were aged with associated crude oil from South Texas and then subjected to spontaneous imbibition testing in different commercial surfactants. Upon completion of the initial imbibition, the cores were re-saturated with crude oil to examine the performance of secondary oil recovery, utilizing the adsorbed surfactant on the core without additional surfactants.

For fracturing fluid recovery testing, dry Eagle Ford outcrop cores were saturated in fracturing fluid formulated with a surfactant, followed by lab-simulated flowback recovery using vacuum. The fluid volume change in the core was quantified using NMR. The fluid recovery efficiency was defined as the ratio of the recovered fluid volume after the simulated flowback to the saturated fluid volume in the core during the treatment.

The cores treated with four surfactants—S1, S3, S4, and S6—showed improved initial oil recovery compared to the baseline without surfactant. The core treated with S3 had the best ultimate recovery, recovering 30.5 % of the oil after 15 days, which is 176.5 % improvement compared to the core treated with the baseline fluid with no surfactant. For flowback recovery, the core treated with S1 had the most fluid recovery, flowing back 28.4 percent more treatment fluid than the core treated without any surfactant. Considering both oil recovery and flowback recovery performance, the Eagle Ford outcrop cores treated with S1 and S3 had the best results.

Currently, hydraulic fracturing surfactant selection for shale is based on minimal testing or even solely on experience gained from conventional formations, rather than demonstrated performance in particular shale formations. This work serves as the guideline for selecting fracturing fluid surfactants for use in the Eagle Ford shale to benefit both flowback recovery and initial oil recovery.

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