Controls on Matrix Block Size in Fractured Reservoirs and Flow Implications: A Modeling Perspective
An important aspect of fractured reservoir recovery is not just the permeability of the fracture system but also the ratio of fracture surface area to matrix volume. The drainage of fluids from matrix to fracture is easier when the fluid has shorter distances to travel. The matrix block size distribution depends on fracture length, spacing and orientation. A numerical fracture mechanics model is used to generate various fracture networks as a function of loading history and initial stress anisotropy. Boundary conditions are chosen to generate both single set fracture systems and interconnected, multi-set networks. In addition to loading conditions, fracture pattern results are strongly influenced by mechanical layer thickness (all examples constitute strata-bound fractures), mechanical properties of the rock (particularly the subcritical index), and initial flaw populations from which the fractures grow. Matrix block sizes are assessed for each pattern by calculating fracture surface area to reservoir volume ratios and maximum drainage distance from matrix to fracture. Finally, flow performance of each fracture pattern is assessed by computing effective single-phase permeability values and two-phase drainage curves using fine-scale finite difference simulations. Results are computed for high and low capillary pressure contrast between matrix and fracture. Two-phase calculations are presented for both primary recovery and waterflood cases. Preliminary results highlight the importance of fracture connectivity (single set versus multi-set fracture networks), well placement (whether directly connected to fracture system or not), and capillary pressure effects.