Fluid flow in fractured reservoirs is highly sensitive to the change of effective stress during fluid injection or production. Permeability, capillary pressure and relative permeability of rock fractures to oil and water directly impact hydrocarbon recovery. However, these parameters are difficult to measure in the lab as a function of effective stress. Available laboratory measurements are typically limited to a single-phase fracture permeability measurement under different stress, which is not sufficient to predict fracture relative permeability and capillary pressure vs stress.

We develop an approach to simulate stress effect on two-phase fracture-flow properties. This approach uses fracture aperture distribution based on micro-CT data and aspect ratio distribution of fracture voids from laboratory-measured stress-displacement measurements. Using these input data and using the network approach, we simulate the stress effect on fracture permeability, relative permeability and fracture capillarity. Simulation results are compared with available laboratory data for fracture permeability.

Our numerical approach allows quick computation of the stress effect on two-phase fluid-flow properties of fractured rock. The approach is consistent with the law of physics and driven by available input data. Rock curves, produced by our model can be used as input parameters for reservoir simulators.


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