Tight Oil and Shale Gas PVT Modelling for Flow Simulation with Matrix-Fracture Interaction

Abstract

Abstract Tight oil and shale gas reservoirs have a significant part of their pore volume occupied by micro (below 2nm) and mesopores (between 2 and 50nm). This kind of environment creates strong interactions forces in the confined fluid with pore walls as well as between its own molecules and then changes dramatically the fluid phase behavior and its thermodynamic properties. Pressure-Vapor-Temperature (PVT) modeling of such fluids becomes therefore a challenge in order to get accurate production forecast reservoir simulations. Furthermore along the flow from the matrix to the well through the fractures, the fluid will pass through a very heterogeneous pore size distribution which will alter it differently according to the pore size and the spatial distribution. An important work has therefore to be done on developing upscaling methodology of the pore size distribution for large scale reservoir simulations. Firstly molecular simulations will be performed on pure components and mixtures in order to get reference thermodynamic properties at liquid/vapor equilibrium for different pore sizes. The comparison with commonly used modified equation of state (EOS) in the literature highlighted the model of flash with capillary pressure and critical temperature and pressure shift as the best one to match reference molecular simulation results. Secondly fine grid matrix/fracture simulations have been built and performed for different pore size distributions. The study has shown that the pore size distribution has an important impact on reservoir production and that this impact is highly dependent of the volume fraction of nanopores inside the matrix. Capillary pressure heterogeneity and pore radius dependent EOS cause gas flow slowdown or gas trapping inside the matrix and postponed gas flow apparition in the fractures during depletion which reduce the GOR (Gas-Oil Ratio) at the well. Coarse grid upscaling models have then been performed on the same synthetic case and compared to the reference fine grid results. The commonly used upscaling methodology of dual porosity model with average pore radius for the pore size distribution is unable to match the fine grid results. A new triple porosity model considering fracture, small pores and large pores with their own capillary pressure and EOS, together with MINC (Multiple Interacting Continua) approach, has shown very good match with the reference fine grid results. Finally a large scale stimulated reservoir volume with different pore size distribution inside the matrix has been built using the upscaling method developed here. The proposed triple porosity methodology is able to model the PVT of the confined fluid and its flow across a very heterogeneous pore size distribution up to the well through fractures in a large scale reservoir simulation.