A common method of modeling naturally fractured reservoirs is a dual porosity approach that uses two identical grids superimposed on each other. Porosity in one grid represents pore space within matrix rock. In the other it represents fracture space between blocks of matrix rock. Fluid transfer rates between corresponding fracture and matrix grid nodes due to capillary pressure and gravity effects are determined from the results of independent simulations that model displacement of fluids in the matrix by fluids from the fracture. This paper presents details of a technique for averaging results of these independent simulations when multiple displacement processes are expected in the reservoir. Motivation came from the need to model a naturally fractured field in which water was first injected below the oil zone in a peripheral waterflood. At the end of the waterflood, gas was injected at the top of the oil zone as the second part of a double displacement process. Fluids in the matrix rock were expected to be displaced by fluids from the fracture network with the following processes: water displacing oil, oil displacing water, and gas displacing oil and water.
展开▼
