Routine measurement of hydraulic diffusivity of ultra-low permeability rocks, such as shale, is a prolonged process. This study explores the effects of sorptive characteristic of porous medium on hydraulic diffusivities of shale rocks. The examined rock types include Mancos Shale, Catoosa Shale, Eagle Ford Shale, and core samples from Gulf of Mexico. Firstly, the adsorption isotherms of the selected shale rocks were obtained. Then, the hydraulic properties of the selected shale rocks were determined using Shale-Fluid Interaction Testing Cell, which employs the pressure transmission technique. The experimental results show that the moisture content of shale is correlated with water activity using a multilayer adsorption theory. It is found that the adsorption isotherms of various shale formations can be scaled using their respective cation exchange capacity, into a single adsorption isotherm. The study proposes an isotherm correlation, which represents ten different shale formations. Analyzing the transient pore pressure response in the downstream side of shale sample allows calculating the transport coefficients of shale samples. Hydraulic properties of shales are obtained by matching the pore pressure history with a 1-D coupled fluid flow model. The experimental results indicate that sorptive properties can be inversely related to the hydraulic diffusivity of shale rocks. It is found that with an increase in the magnitude of sorption potential of shale, the hydraulic diffusivity decreases. This work is useful for shale characterization and provides a correlation, which can have various applications including, but not limited to, wellbore stability prediction during well planning.
Prolonged exposure of shale formations with aqueous drilling fluids has shown to be problematic and leads to wellbore instability issues (Rahman et al., 2003; Nes et al., 2012). According to York et al., 2009, the wellbore instability problems in a deepwater offshore well could at least cost $2.5 million. Many efforts have been done to reduce shale instability by modifying the chemical composition of drilling fluid using different categories of fluid additives (Reid and Minton, 1992; Clark and Benaissa, 1993; van Oort et al., 1996; Patel, 2009). One of the important interaction processes between shale and drilling fluid is hydration of clay minerals. This phenomenon often leads to various operational problems such as shale swelling, bit balling, stuck pipe, high torque, and reduction of rate of penetration, which ultimately increase the non-productive time and hence the drilling cost (van Oort et al., 1996; Labenski and Reid, 2003). Basically, two kinds of clay swelling can be recognized, namely, the intercrystalline swelling due to the hydration of exchangeable cations and osmotic swelling, where the latter is due to a substantial difference between chemical potential of shale and drilling fluid (Cases et al., 1992; van Oort, 2003).