Shale reservoirs have a significant fraction of total pore volume coming from pore sizes in the range of nanometers. Fluid phase behavior in these small pores deviates from the behavior in larger pores (known as bulk PVT). Modifications to thermodynamic modeling coupled with capillary pressure, interfacial tension, and relative permeability are used to analyze the impact of the aforementioned phenomena on hydrocarbon production of liquids-rich shale reservoirs. Furthermore, the impact of rock properties on production performance has to be assessed. Therefore, this paper aims to research the fluid-rock interactions developed within nanoscale reservoirs and their influence on recovery of gas and liquids.
We analyzed the phase behavior in nanopores using two approaches: (i) critical properties shift, and (ii) capillary pressure. Reservoir simulation is selected to evaluate these two mechanisms. To attain this goal three cases are constructed, all with constant reservoir porosity, using an in-house compositional simulator: (i) constant permeability reservoir with both bulk and confined fluid properties, (ii) variable permeability reservoir with bulk fluid properties, and (iii) variable permeability reservoir with confined fluid properties. The first case exclusively evaluates the effects of confined vs. bulk fluid properties, the second case only focuses on rock properties changes, whereas the third case studies rock-fluid interactions. For the heterogeneous cases, published pore sizes reported for shale formations are used. Consistency between pore size, porosity and permeability is maintained within the simulation models.
Simulation results indicate confinement affects volumetric fluid and transport properties within shales. Significant changes in saturation pressures, which impact relative permeabilities, are manifested with respect to bulk conditions. Comparison of the simulation results allows identification of the contributions of both rock and fluid properties on hydrocarbon recovery. PVT behavior under confinement impacts incremental production during depletion. The methodology introduced in this study is a powerful practical tool for describing rock-fluid interactions in liquids-rich shale reservoirs and helps to understand the shales’ production behavior observed in the field. Detailed comparisons with a gas condensate and a volatile oil reservoir fluids are presented in detail.
The physics-based approach implemented in this work provides a novel and important foundation for the analysis of production from confined porous media such as shale reservoirs. Phase behavior in these types of reservoirs is corrected to account for confinement effects in a thermodynamically consistent way to achieve a more accurate performance prediction of nano-porous formations. The modeling developed in this paper is simple, yet robust, as opposed to computationally expensive molecular simulations. The main advantage of the proposed methodologies is that they can be easily implemented into other in-house or commercial simulators.