Physics of fluid flow in shale reservoirs cannot be predicted from standard flow and mass transfer models due to presence of nanopores (1-100s of nanometer) in shales. Recently, few models have been developed to account for Slip-flow and Knudsen diffusion due to nanopores in apparent permeability. The limitation with all of these models is that they employ use of some form of empirical coefficient and its value form the basis of accuracy of their models. Additionally, to date, there is no reliable empirical data available for shales due to complexity of the system, i.e., different organic materials and mineral types as well as different gas components in gas shales.
In this paper a new analytical model for permeability of an ultra-tight porous media, consisting of tortuous micro/nano-pores, which is free of any empirical coefficients is incorporated in a dual-continuum reservoir simulator. We use an implicit compositional single phase dual-continuum reservoir simulator capable of modeling gas recovery from naturally fractured, or fissure rich hydraulically fractured, tight to ultra-tight reservoir.
A field scale case study is used to validate the accuracy of the nonempirical permeability model by comparing our predicted results with the results reported by other empirical models. The simulation results obtained with nonempirical permeability model closely match the simulation results reported by other authors with their case study. The nonempirical model shows that the pore-surface roughness and mineralogy has negligible influence on gas flow rate in the complete range of reservoir operating conditions. Finally, apparent permeability for ultratight reservoir (r < 100 nm) is a dynamic parameter and should be adjusted with other reservoir conditions, specifically, reservoir pressure. The model is valid throughout the operating conditions of a reservoir i.e. from the beginning of production until the limit of economic production.