Modeling Coupled Fracture-Matrix Fluid Flow in Geomechanically Simulated Fracture Networks

Summary In conventional reservoir simulations, gridblock permeabilities are frequently assigned values larger than those observed in core measurements to obtain reasonable history matches. Even then, accuracy with regard to some aspects of the performance such as water or gas cuts, breakthrough times, and sweep efficiencies may be inadequate. In some cases, this could be caused by the presence of substantial flow through natural fractures unaccounted for in the simulation. In this paper, we present a numerical investigation into the effects of coupled fracture-matrix fluid flow on equivalent permeability. A fracture-mechanics-based crack-growth simulator, rather than a purely stochastic method, was used to generate fracture networks with realistic clustering, spacing, and fracture lengths dependent on Young's modulus, the subcritical crack index, the bed thickness, and the tectonic strain. Coupled fracture-matrix fluid-flow simulations of the resulting fracture patterns were performed with a finite-difference simulator to obtain equivalent permeabilities that can be used in a coarse-scale flow simulation. The effects of diagenetic cements completely filling smaller aperture fractures and partially filling larger aperture fractures were also studied. Fractures were represented in finite-difference simulations both explicitly as grid cells and implicitly using nonneighbor connections (NNCs) between grid cells. The results indicate that even though fracture permeability is highly sensitive to fracture aperture, the computed equivalent permeabilities are more sensitive to fracture patterns and connectivity. Introduction High-permeability fracture networks in a matrix system can create high-conductivity channels for the flow of fluids through a reservoir, producing larger flow rates and, therefore, larger apparent permeabilities. The presence of fractures can also cause early breakthrough of the displacing fluid and lead to poorer sweep efficiencies in displacement processes. A better understanding of reservoir performance in such cases may be obtained by including the details of the fluid flow in fractures in a coupled fracture-matrix reservoir flow model. It is very difficult to directly measure interwell fracture-network geometry in sufficient detail to model its effect on reservoir behavior. Thus, most modeling approaches have been statistical, using data from outcrop and wellbore observations to determine distributions of fracture attributes such as fracture length, spacing, and aperture to randomly populate a field. In this paper, we use a mechanistic approach to generate the fracture patterns. Attributes of the fracture network depend on the applied boundary conditions and material properties.