Dual-Continuum Modeling of Shale and Tight Gas Reservoirs

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Abstract Shale and tight gas reservoirs are characterized by very low permeabilities at the nano-scale which gives rise to non-Darcy effects such as Knudsen diffusion that makes the use of conventional (Darcy) models inadequate. Slip-flow and Knudsen diffusion have been shown to be accounted for in an apparent permeability that is not just pressure dependent but can be strongly non-linear. Available apparent permeability models are either an empirical function of the matrix permeability or capillary tube models based on the ideal gas law. We use the latter in this work but correct for real gas and porous media effects. Incorporating slip-flow and Knudsen diffusion in developing a dual-continuum reservoir simulator capable of modeling natural fracture flows in shale and tight gas reservoirs is tricky because the matrix-fracture interporosity term can no longer be treated as the historic constant for single phase flows but as a complex function of pressure. In this work, we show that we can circumvent this complexity only if we use a modified pseudo-pressure approach and treat the resulting variable diffusivity as an explicit term in the derivation of an adequate matrix-fracture interporosity shape factor. We also develop a 2D implicit compositional single phase dual-continuum reservoir simulator suitable for modeling naturally fractured (or fissure rich hydraulically fractured) shale and tight gas reservoirs. Our results show that natural fractures (and/or fissures) can play a very crucial role in shale and tight gas recovery, which is significantly enhanced by slip-flow and Knudsen diffusion and hence, should not be ignored. Our model can also be used to model flows through the hydraulic fractures for situations where hydraulic fracturing is dense and hence present a computational challenge to model explicitly.