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The presence of vugs in a naturally fractured reservoir can be a significant source of reserves. These vugs can be connected to the fracture system or be isolated in matrix material which constitutes a triple porosity system. The modeling of the displacement of oil from the vugs can not be made with conventional dual porosity reservoir simulators since triple porosity system "isolated vugs" are not part of the formulation. The simulation of oil production from triple porosity reservoirs requires the development of composite porosity, composite relative permeabilities and composite capillary pressure relationships. These composite curves can be generated from properly designed laboratory experiments on representative cores or by history matching fine grid single porosity simulations. Kossack, et al1 discussed this for water-oil systems. Since the displacement of oil from vugs by gas involves very different mechanisms from water-oil systems and is very complex, the simulation of this process must be studied separately. This paper describes a numerical scale-up technique to provide the composite properties and curves to be used in gas-oil displacements in triple porosity systems. Displacements in dual and triple porosity gas-oil systems are dependent on the magnitude of gravity and viscous forces, capillary pressure in the matrix rock, composition of the injection gas, and rate of component diffusion in the porous media. Fine grid single porosity simulations are made with a compositional simulator to determine the rate of oil recovery from the fractures, matrix rock, and vugs. These results are then matched with dual porosity compositional simulations, which create the composite matrix properties. These composite properties can then be used in full field dual porosity simulations of fractured and vuggy reservoirs to correctly predict the oil recovery. The process described can be applied to any triple porosity reservoir where gas is invading the fracture-matrix system. |
