Permeability of Fractured Shale and Two-Phase Relative Permeability in Fractures

Abstract

Abstract Darcy s law, which is used to compute permeability of conventional reservoir rocks, highly underestimates permeability of ultra-tight shale rocks. Darcy s law assumes that the flow of a fluid with constant viscosity across a rock is only a function of its pressure difference, and the rock properties (e.g., permeability) remain constant with time. Applying the hypothesis of Darcy s law to shale highly underestimates the flow rate when compared to field observations, which leads to an inaccurate prediction of permeability. Laboratory studies over the years have shown that additional flow mechanisms that are not accounted for by Darcy s law, such as desorption and diffusion, contribute significantly to the gas produced from the shale matrix. The permeability of shale matrix derived from this assumption leads to an expression that is a sensitive function of pressure, besides other parameters. Accurate representation of fracture permeability in shale requires adjusting the aperture size with time because of its sensitivity to pore pressure. The permeability of fractures in shale can be further defined in terms of the fluids present in the fracture for multiphase flow studies. This chapter presents a critical overview of the methods available to predict shale permeability from experimental and modeling perspectives, at both the laboratory and fieldscales. This chapter also presents a nonempirical model for two-phase relative permeability in shale fractures, derived using conservation of momentum, which does not require any experimental data or curve fitting. In conclusion, a method to predict field-scale permeability of shale as a function of its spatially varying attributes (fractures, matrix, and organic matter) is discussed.