Modeling of geomechanics in naturally fractured reservoirs

Conventional modeling of fractured reservoirs treats fracture-system permeability and porosity as static (or pressure-dependent) data. Recent attempts at coupling geomechanics focused on the permeability but used crude empirical relations and treated the fluid flow as single porosity. This study takes advantage of the joint-mechanics theory to develop general, rigorous coupling between the fluid-flow equation and deformation of fractured media. Both porosity and permeability coupling are considered. The geomechanical part uses the equivalent-continuum approach, considering both rock- and fracture-deformation properties. Multiple sets of fractures with any dip and strike angle can be defined. The stiffness of fractures varies with the effective stress according to a law typical for joints. The main novelty of this work is that the geomechanics solution is decomposed into matrix and fracture parts and used to compute their dynamic porosity and permeability separately. This approach rigorously captures the effect of fractured-media deformation on the dual-porosity-flow part of the coupled system and allows the permeability and porosity variations to be based on measurable joint properties. Generally, fracture deformations produce changes of the permeability tensor in both magnitude and orientation, which in turn influences reservoir flow and compaction behavior. The main issue studied was the variation in the permeability of the fracture system. The examples show that fracture deformation has a significant effect on productivity or injectivity and that anisotropy of the permeability tensor develops from deformation. The results provide an initiative for implementing the case of full-tensor permeability.