Abstract
A fully coupled two-phase fluid flow and geomechanical model has been used to investigate the impact of injection fluid flow and geomechanics on reservoir pressure, effective stresses and strain, vertical displacements, viscous fingering instability, and viscous dissipation during the displacement of a viscous oil by water in a heterogeneous fractured porous medium. Porosity and permeability in the matrix and fracture have been considered as functions of generated strain. Elastic modulus has been considered as a function of updated porosity in the matrix and fracture. These dynamic variations will improve the accuracy in the predictions of its associated hydrodynamic behavior. The coupled model was validated with the existing works. From the present work, it can be critically concluded that the pressure, effective stress and strains, vertical displacement, viscous fingering instability, and viscous dissipation are highly dependent on (a) the fracture aperture, the orientation of fracture (dip), and arrangement of fracture; (b) involved geomechanical load; (c) production pressure, and (d) Biot-Willis coefficient. The numerical models have been examined both in the existence and absence of fractures and geomechanical impact. The Biot-Willis coefficient sensitivity was found on the pressure, water saturation profiles, effective stress, and strain from the numerical results. Viscous fingering instabilities like splitting, shielding, and spreading are observed explicitly in the fractured reservoir. Maximum viscous dissipation occurred in the heterogeneous medium when geomechanics was considered. The breakthrough of injected water was observed earlier in the reservoir with a geomechanical load scenario and the maximum viscous dissipation. The fracture and its orientation affect the viscous fingering instability phenomena and viscous dissipation in a porous medium with fractures after the addition of geomechanical loads. The numerical model extended to the multiple fracture scenarios on the same scale and further scaled up to 200 m by 200 m with different fracture orientations. In the upscaled model, fracture orientations varied from 45 degrees to 135 degrees with the x-axis, fracture lengths ranged from 5 m to 21.2 m, and with diverse fracture aperture and its arrangements. It has been found the fracture orientations 45 degrees and 60 degrees are improving the transportation of injected fluid via the smooth passage, and 120 degrees and 135 degrees are limiting the injecting fluid flow towards the production well. From the numerical results, it was found that viscous fingering instability is more sensitive to the fracture aperture and the complexity of its arrangement. Finally, it was concluded that the number of fractures and their arrangements in the reservoir flow behavior critically influences the model results. Thus, the developed numerical model with variable rock properties can be used to predict the flow behavior. Furthermore, its associated variations in the rock matrix and fractures during the two-phase flows in a reservoir improve reservoir behavior prediction and reduce the uncertainty.