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• W2023380418 abstract "Summary This paper presents a theoretical framework of gas cap effects in naturally fractured reservoirs. General pressure solutions are derived for both pseudo-steady state and unsteady state matrix-fracture interporosity flow. Deviation from the fracture or fracture-matrix response occurs as the gas cap effect is felt. Anomalous slope changes, during the transition period, depends entirely on the contrast between the fracture anisotropy parameter 1 and matrix-fracture interporosity parameter, and between the total gas cap storage capacitance w1 and oil zone matrix storage w. A composite double porosity response is observed for w1 less w1c and 1.0 less less 100.0. A triple porosity response is observed for greater and 140 less less 1.0e05. Introduction Estimation of reservoir and wellbore parameters in naturally fractured reservoirs using pressure transient tests has been the subject of many publications during the last quarter of a century. A plausible model to describe naturally fractured reservoirs is a composite system consisting of tight matrix rock blocks separated by fractures. The fractures, high in permeability and low fluid storativity, are assumed to be permeability and low fluid storativity, are assumed to be continuous throughout the formation, and act as the path of the reservoir fluid toward the production well. Due to their high hydraulic conductivity, the fracture pressure responds rapidly to any pertubation in the reservoir. The matrix, low in permeability and high in fluid storativity, is assumed to provide pressure support to the fractures. Because of their low permeability, matrix blocks exhibit a delayed response to any reservoir pertubations. The concept of a double porosity was first introduced by Barenblatt, et al. They assumed that the flow of fluid from matrix to the fissure occurs under a pseudo-steady state condition. Warren and Root used the Barrenblatt et al's dual porosity concept to model the wellbore pressure response of a naturally fractured reservoir. They pressure response of a naturally fractured reservoir. They assumed that the secondary porosity is contained within an orthogonal, equally spaced system of continuous and uniform fractures. They described the pressure response by two main parameters, w and, which relate the two porosity systems. Fluid capacitance coefficient, w, relates the porosity systems. Fluid capacitance coefficient, w, relates the fracture storativity to the total storativity. Interporisity flow parameter, represents the permeability contrast of the two media. For the pseudo-steady state condition the semi-log plot of pressure response versus time produces a characteristic S-shaped transition segment with a point of inflection. Kazemi, in his work, used a layered system composed of thin but highly conductive layers to represent the fracture network, alternating with thicker but lower conductivity layers to represent the matrix system, and assumed the matrix-fracture interporisity flow occurs under the unsteady state flow regime." @default.
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• W2023380418 date "1997-03-01" @default.
• W2023380418 modified "2023-09-23" @default.
• W2023380418 title "Gas-Cap Effects in Pressure Transient Response of Naturally Fractured Reservoirs" @default.
• W2023380418 doi "https://doi.org/10.2118/20565-pa" @default.
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