Geomechanical effects of natural fractures on fluid flow in a pre-salt field

The discovery of carbonate reservoirs in the Brazilian pre-salt field has raised several engineering challenges. These reservoirs are naturally fractured and much stiffer than conventional reservoirs. Thus, the study of fluid flow through natural fractures has received significant attention from the petroleum industry because the production capacity of these fields is associated with the hydraulic behavior of such fractures. However, pressure changes induced by the oil recovery alter the fracture aperture. In turn, changes in the fracture aperture affect the fluid flow inside the fracture channels, increasing or reducing the production capacity of the reservoir. This work investigates the hydromechanical effect of natural fractures on the reservoir behavior at the production unit Tupi pilot of the Brazilian pre-salt. The enhanced dual-porosity/dual permeability model (EDPDP) is adopted to simulate more realistically the hydromechanical behavior of fractured carbonate rock formation. This approach updates the stiffness and permeability tensors considering the fracture orientation and the stress-induced aperture changes. The shape factor is also improved to represent multi-block domains formed by several multiscale fracture sets with different orientations, apertures, and spacing. The hydromechanical formulation of EDPDP implemented in an in-house framework GeMA (Geo Modeling Analysis) is adopted to study the hydromechanical effect of fractures with multiple lengths on the Tupi pilot. The numerical results demonstrate that the complex fracture network is responsible for fluid migration through a preferential pathway. A parametric analysis of the main parameters that affect reservoir behavior was carried out. The parametric study shows higher pore pressure dissipation for smaller dip angles. Then, horizontal fractures are more sensitive to vertical displacements. In addition, smaller spacing and larger fracture aperture enhance permeability, increasing pore pressure dissipation and mechanical deformation. Finally, numerical results were compared against field measurements showing excellent agreement, demonstrating the applicability of the EDPDP model to simulate naturally fractured reservoirs.