DUAL-POROSITY BEHAVIOR OF NATURALLY FRACTURED RESERVOIRS

A dual-porosity model based on the modified formulation by Barenblatt et al. has been presented for the simulation of naturally fractured reservoirs. It is shown that neglecting terms in the flow governing equations may not be justified for some particular physical circumstances. The analytical solution of the proposed dual-porosity model for a finite naturally fractured reservoir subjected to a constant outer boundary pressure is obtained using the Hankel transform technique while taking into account the transient flow in the matrix blocks. Both solution accuracy and efficiency are achieved utilizing an optimized algorithm when solving the inherent Bessel functions. This research indicates that the transient fluid pressure profiles in naturally fractured reservoirs are critically controlled by the permeability ratio between matrix and fractures, and by the compressibilities of fluid, fractures and solid grains. The fluid pressure change is substantially delayed if the permeability ratio becomes increasingly smaller. The dual-porosity behaviour is most obvious when the compressibility of the fractures decreases relative to the increases of compressibility of the solid grains.