Two-phase flow interporosity effects on pressure transient test response in naturally fractured reservoirs

Complexities related to multi-phase flow in naturally fractured reservoirs have been somewhat addressed in numerical models used for performance prediction purposes. This paper examines the concept of the two-phase (oil and water) flow in analytical modeling of pressure transient response in naturally fractured reservoirs. Under the condition of the two phase flow in both the matrix rock and the fractures, the capillary pressure and the relative permeability characteristic associated with prevailing saturation conditions are integrated into the pressure transient models. Characteristic shape of the transition portion of pressure response curve, for naturally fractured reservoirs, is influenced by the specific assumptions made about the nature of matrix-to-fracture flow. The analytical solution presented here describes the effect of two-phase interporosity on the transition portion of the pressure response. The interporosity parameter is modified to incorporate the contribution of the relative permeability and capillary pressure effects associated with countercurrent flow. Our studies show that without proper consideration of two-phase flow, and the saturation conditions, the estimated values for interporosity coefficient, estimation of the shape factor and block sizes are subject to errors. With independent measurements from cores and well logs, to ascertain the wettability and fluid saturation conditions in both fractures and matrix rock, the proposed model allows improved estimation of the interporosity flow parameter, shape factor and block sizes for history matching purposes.