A novel compositional model of simulating fluid flow in shale resrvoirs-Some priliminary tests and results

Multiple porosity systems exist in shale reservoirs: organic matter, inorganic matter, natural fractures and hydraulic fractures. Accurately simulating fluid storage and flow in this complex environment still remains a challenge. One key is to properly account for the multi-component adsorption and diffusion phenomena occurring in the shale matrix. Most studies conducted in recent years use a single gas phase model or a black oil model to consider these aspects. A compositional model specifically tailored for the characteristics of shale reservoirs is required to properly model all of the physics. In this paper, such a compositional model is introduced. The model takes the pressure and component molar masses as the primary variables, and applies the IMPEM method (implicit pressure and explicit mass) as the solution technique at the current stage. The multi-component adsorption and diffusion terms are incorporated into the component mass balance equations. Adsorption is described through the Extended Langmuir equation, and multi-component diffusion can be described either through the classical or the generalized Fick's law. The latter has the capacity of accounting for component interactions and the phase thermodynamic non-ideality. Knudsen diffusion can also be incorporated through the concept of an augmented effective diffusion coefficient. Several preliminary tests have been conducted to validate the model. The influences of the important parameters, such as total carbon content, wettability, and fluid composition, on shale reservoir fluid recovery were also investigated with the new simulator.