Forced and Spontaneous Imbibition Experiments for Quantifying Surfactant Efficiency in Tight Shales

Abstract

Surfactants have been used extensively in well completion practices and have been shown to favorably alter the wettability of a formation from highly water-wet to intermediate-wet, resulting in increased water recovery and in a reduction of water blockage around the wellbore. Spontaneous imbibition and contact angle measurements are the most popular methods for studying the efficacy of a given surfactant. Forced imbibition experiments on fractured cores under confining pressure provide a more realistic representation of the actual formation settings, but have not been used extensively to measure the effect of surfactant solutions. They are commonly avoided due to their additional experimental complexity when compared to their spontaneous imbibition counterparts. The forced imbibition data reveal information about the porosity and provide an estimate of fluid flow values under different confining pressures of the micro-fracture network and the core matrix from the imbibition rate. Compined with the pure water invasion rates, forced imbibition experiments with surfactants reveal potential impacts that the surfactant may have on a given formation.In this work, 1 in by 1 in shale core plugs have been used to study the efficacy of a surfactant towards increased load recovery. Each core plug undergoes two forced imbibition experiments lasting 24 hr in succession: One experiment is carried out with pure water while the second experiment employs a surfactant solution. The permeability and porosity of the samples are measured before each experiment to be able to account for any changes to the cores as a result of the forced imbibition experiments. During forced imbibition, the fluid is injected at a pressure of 3500 psi. We observe an increase in water recovery of approximately 60% for a low (ppm-level) concentration of a surfactant solution. We argue that spontaneous and forced imbibition experiments provide more realistic observations of the capillary pressure effects at play than do contact angle measurements, and that they should be used together for direct quantification of surfactant efficacy in these tight porous materials under realistic reservoir conditions. IntroductionIn low permeability porous media like gas shales, more than 70% of injected water during fracturing is lost to the formation and hence water recovery during flowback is very low. In completion practices, surfactants are generally used along with the fracturing fluid to increase recovery of the injected water. Surfactants aid the water recovery through their ability to reduce surface and interfacial tension, and alter wettability.Typically, contact angle measurements and spontaneous imbibition experiments are used to characterize the efficacy of surfactants. These experiments form the basis of wettability studies on most formations (Morrow et al., 1994). In our previous work (Roychaudhuri et al., 2013), we have seen that the addition of surfactants shows a beneficial effect by substantially increasing both the static and dynamic contact angles of w...

Water imbibition of shale and its potential influence on shale gas recovery—a comparative study of marine and continental shale formations

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