Implementing stress-sensitivity in naturally fractured reservoir flow simulation can be achieved through the use of “multipliers” that serve to modify, for example, fracture network pore volume as a function of changing reservoir pressure and fracture network transmissibility as a function of changing pore volume. We have used parametric, stress-sensitive, discrete fracture network modeling, combined with a stiffness scaling rule as determined from hydromechanical laboratory testing of single natural fractures, to develop simple predictive relationships for estimating multiplier magnitudes. For a wide range of fracture network intensities and aperture size distributions we observe that, to first order, pore volume- and transmissibility-multipliers are surprisingly predictable from basic knowledge of supplementary reservoir stress and geometric fracture properties information. Single-producer flow simulation box models are subsequently employed to illustrate the impact of varying multiplier magnitudes on incremental oil recovery, relative to an “incompressible fracture network” base case condition.

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