Application of Strain-Induced Permeability Model in a Coupled Geomechanics-Reservoir Simulator

Abstract

Abstract A fully coupled geomechanics-reservoir model is developed to simulate the directional changes in permeability due to fluid injection and production in a reservoir. The model is implemented numerically by fully coupling a geomechanics model with a single-phase reservoir flow model using the finite element method. A strain-induced permeability model is developed based on the analysis of the grain fabric of intact and sheared oil sand specimens using a thin section imaging method. It can quantify the changes in permeability when material experiences shear deformation. In addition, the directions of the principal values of permeability are not restricted to some arbitrary axes, but governed by the induced strains. Thus, the effects of stress path and stress level are implicitly considered through effective stress-strain constitutive laws. The transient pressure response of a water injection test in a horizontal well is analyzed. Parametric studies are also conducted to investigate the effects of permeability, deformability and initial stress conditions on the injection pressure. It is found that the changes in permeability resulting from dilations of the oil sands cannot be captured using the conventional permeability model as a function of volumetric strain because the volumetric strain is small. However, the strain-induced permeability model can accurately reflect the directional increase in permeability during water injection. It is shown that the induced pore pressure is relatively insensitive to the deformation modulus of the reservoir, as compared to the permeability. The initial stress condition dominates the propensity of hydraulic fracturing. Introduction Geomechanics plays a key role in accounting for rock deformations due to pore pressure and temperature changes resulting from fluid injection and production in a thermal reservoir. During fluid injection and production, absolute permeability at any given location may change in response to localized changes in stress within the rock pore system owing to changes in reservoir pressure. Pore pressure changes can, in turn, influence the effective reservoir stress (overburden pressure minus pore pressure) which can alter the pore geometry of the reservoir rock; especially the shape and dimension of the pore and the pore throats(1–7). The geomechanical behaviour of porous media has become increasingly important in deformable and fractured reservoirs. In current geomechanics-reservoir coupled simulators, the permeability of the rock is assumed to be transversely or orthogonally isotropic(8,9). In other words, the direction of flow is aligned with the pressure gradient. This simplifying assumption is not valid in many cases. For example, the permeability of fractured rock is substantially dependent on microfractures. Therefore, the dominating orientation of the fractures can make the direction of flow different from that of the pressure gradient(10). Another example of permeability anisotropy is demonstrated in thermal recovery processes, such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD). In these thermal recovery processes, shear dilation deformation takes place in local areas due to the increase of pore pressure, thereby enhancing permeability in these areas(11,12). Clearly, an understanding of permeability anisotropy is important. However, in the petroleum literature, the permeability change of a reservoir formation subjected to deformation changes is usually determined as a function of volumetric strain or porosity, which relates to the mean or minimum effective stress.