The effects of rock structural properties on porosity and permeability may be considered as generally well known, being particularly critical when modeling tight sands and limestones. Nevertheless, such effects have been slow to find their way into reservoir simulators. These effects are frequently even more important for fractured horizons where 10-20 porosity per cent changes, and/or several orders of magnitude change in permeability, can be observed under changing reservoir stress conditions. Rocks with weak tensile properties are particularly vulnerable to stress change. These include diatomite, chalks, and overpressured Gulf Coast shales.
Less well known is the dependence of relative permeability on stress. Moreover, the effects of relative permeability and capillary pressure in the fractures themselves need to be accounted for.
Production in naturally fractured reservoirs is limited by the exchange rates of oil and gas between matrix blocks and fractures. Naturally fractured simulators which use the conventional dual porosity formulation fail to resolve gradients in the matrix blocks unless some type of sub-gridding (subdomains) is used. This lack of resolution at the matrix/fracture interface leads to significant errors in production rates when modeling oil recovery from fractured reservoirs.