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.
Predicting Pore Volume and Transmissibility Multipliers for Simulating Geomechanical Effects in Naturally Fractured Reservoirs Using Stress-sensitive Discrete Fracture Network Modeling
Crawford, Brian, Homburg, Janelle, Fernandez-Ibanez, F., Myers, R. D., and B. Gao. "Predicting Pore Volume and Transmissibility Multipliers for Simulating Geomechanical Effects in Naturally Fractured Reservoirs Using Stress-sensitive Discrete Fracture Network Modeling." Paper presented at the 2nd International Discrete Fracture Network Engineering Conference, Seattle, Washington, USA, June 2018.
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