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 finite element method. A strain-induced permeability model is developed based on the analysis of grain fabric of intact and sheared oil sand specimens using 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, and governed by the induced strains. Thus, the effects of stress paths 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 condition 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.
Geomechanics plays a key role to account for rock deformations due to pore pressure and temperature changes resulting from fluid injection and production in a thermal reservoir. During the 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, specially the shape and dimension of the pore and the pore throats1–7.
The geomechanical behavior of porous media has become increasingly important in deformable and fractured reservoirs. In the current geomechanicsreservoir coupled simulators, the permeability of the rock is assumed to be isotropic, transversely or orthogonally isotropic8–9. 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 gradient10. Another example with permeability anisotropy is demonstrated in thermal recovery processes, such as cyclic steam stimulation and steam assisted gravity drainage. 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 areas11–12. Clearly, an understanding of permeability anisotropy is important.