Phase Behavior Change Due to Rock Deformation in Shale Reservoirs: A Compositional Modeling Approach

Abstract

Pore diameters for shale reservoirs are on the order of few nanometers which become even smaller during production because of rock deformation. This dynamic interaction between pore fluid pressure and rock stress affects the phase behavior in unconventional reservoirs. In this paper, a new mathematical formulation of fully-coupled geomechanics and compositional dual-porosity model was used to determine the impact of rock deformation and confinement on the nanopore fluids as well as their effect on the production performance of Eagle Ford formation. The formulation presented was derived from our multiphase poroelasticity model which was an extension to the single-phase, single-porosity Biot's linear poroelasticity theory allowing to characterize the rock deformation and pore diameter reduction using the bulk modulus of the matrix-fracture system. Changes in reservoir pore pressure and rock deformation that cause the pore diameter to reduce increases the capillary pressure in the pores which affects the bubble-point pressure suppression and significant shift in the phase envelope, favoring longer period of single-phase production. It was observed that not taking rock deformation into account will lead to over estimation of production, whereas ignoring the effect of pore confinement would underestimate the production forecast. In an example field study based on Eagle Ford reservoir, an increase of around eight percent in cumulative oil production was achieved when the effect of rock deformation and confinement was included in the compositional model compared to the case where only the rock deformation was included. On the other hand, if only pore confinement effect was included in the simulation runs, four percent of increase was achieved.