Fast and efficient methodology to convert fractured reservoir images into a dual-porosity model

Both characterization and dynamic simulation of naturally-fractured reservoirs benefited by major advances in the recent years. However, the reservoir engineer remains faced with the difficulty of parameterizing the dual-porosity model used to represent such reservoirs. In particular, the equivalent fracture permeabilities and the equivalent matrix block dimensions of such a model cannot be easily derived from the observation of the complex images of natural fracture networks. This paper describes an original and systematic methodology to compute these equivalent parameters. Results of its implementation with a specific software demonstrate its validity and efficiency to deal with field situations A tensor of equivalent fracture permeability is derived from single-phase steady-state flow computations on the actual fracture network using a 3D resistor network method and specific boundary conditions. The equivalent block dimensions in each layer are derived from the fast identification of a geometrical function based on capillary imbibition. The methodology was validated against reference fine-grid simulations with a conventional reservoir simulator. Then, a complex outcrop image of a sandstone formation was processed for demonstration purposes. This innovative tool enables the reservoir engineer to build a dual-porosity model which bestly fits the hydraulic behavior of the actual fractured medium.