Abstract

Upscaling is often applied to generate practical simulation models from highly detailed geocellular descriptions. Upscaling of reservoir properties is critical to translate parameters measured from laboratory samples into values representative of the much larger grid blocks used in field simulators.

In this paper an upscaling methodology for naturally fractured reservoir simulation is developed and the effect of dominant forces on upscaling parameters is considered. Dominant forces which affect the fluid flow in naturally fractured reservoir are capillary force, gravity force and viscosity force. According to force dominancy, three different scenarios are proposed. In each scenario synthetic fine grid model represents actual fracture distribution. And upscaling parameters of each equivalent dual medium model are determined by matching the results of the fine grid model simulation.

In the first scenario viscose force is dominant. After running simulations the results of single porosity and dual permeability models are perfectly matched. So there is no need to tune the dual permeability model. In the second scenario in which capillary force is dominant, dual permeability and single porosity models showgood match. The results could be improved by tuning fracture porosity, fracture permeability and shape factor. Fracture porosity reduction and permeability reduction increases the pressure and water breakthrough time while decreases the oil production. In the third scenario in which gravity force is dominant the matching parameter is fracture porosity. Reduction of fracture porosity increases pressure and water cut while decreases oil and gas production.

To investigate the accuracy of the upscaling method, following validity tests are implemented; flow rate test, well location, saturation function, viscosity ratio and block height.

Comparing the results show that in this reservoir, dual permeability model matched better with the fine grid model than dual porosity model.

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