Fluid flow simulation in discrete fractures for estimation of production potential of fractured basement reservoirs

An innovative approach is presented to simulate multiphase fluid flow in naturally fractured reservoirs and estimate oil recovery under different driving mechanisms. The first step of this approach includes an inversion algorithm for optimisation of fracture properties by reducing the difference between the simulated pressure and well test data. A gradient based inversion technique, which integrates forward simulation of fluid flow (single phase), is used to run the optimisation scheme. In second step of the approach, the two phase flow in interconnected fractures is simulated by taking into account of viscous, gravity and capillary forces. In view of this laboratory experiments are conducted on a core samples with single fracture at different orientations to measure relative permeability and capillary pressure curves. In the thesis, the derivation of multiphase fluid flow equations in a poroelastic framework as well as discretisation of the two phase flow equations using finite element technique in a 3D space are presented. In third step, the multiphase flow simulation is validated by history matching the oil drainage tests proposed by Fahad and Rahman (2013). These experiments were carried out on glass bead models in unsteady state conditions using single and multi-fracture systems at different orientations and intersections. In final step, the up scaled permeability and other reservoir data are used in simulation of multiphase fluid flow in a typical fractured basement reservoir. The results of inversion of well test data show that as the difference between the simulated pressure data and well test data narrows there is gradual shift/ change in permeability, in particular near the wellbore. This change in permeability is directional, meaning that the change in permeability is a true representation fracture flow properties, therefore fracture geometry, aperture, connectivity and orientation and that this change in magnitude and direction could not have been observed had the flow through discrete fracture not possible to simulate. Laboratory measurements show that the two phase relative permeability curve of a fractured porous media is not linear function of saturation. Furthermore, the multiphase flow simulation in discrete fractures is used in this thesis to upscale relative permeability curve to field scale and predict production potential and pressure drawdown. Results show a good agreement between the estimated and the production history data