The storage capacity ratio, ω, measures the flow capacitance of the secondary porosity and the interporosity flow parameter, λ, is related to the heterogeneity scale of the system. Currently, both parameters λ and ω are obtained from well test data by using the conventional semilog analysis, type-curve matching or the TDS Technique. Warren and Root showed how the parameter ω can be obtained from semilog plots. However, no accurate equation is proposed in the literature for calculating fracture porosity.

This paper presents an equation for the estimation of the λ parameter using semilog plots. A new equation for calculating the storage capacity ratio and fracture porosity from the pressure derivative is presented. The equations are applicable to both pressure buildup and pressure drawdown tests. The interpretation of these pressure tests follows closely the classification of naturally fractured reservoirs into four types, as suggested by Nelson1 .

The paper also discusses new procedures for interpreting pressure transient tests for three common cases: (a) the pressure test is too short to observe the early-time radial flow straight line and only the first straight line is observed, (b) the pressure test is long enough to observe the late-time radial flow straight line, but the first straight line is not observed due to inner boundary effects, such as wellbore storage and formation damage, and (c) Neither straight line is observed for the same reasons, but the trough on the pressure derivative is well defined. Analytical equations are derived in all three cases for calculating permeability, skin, storage capacity ratio and interporosity flow coefficient, without using type curve matching.

In naturally fractured reservoirs, the matrix pore volume, therefore the matrix porosity is reduced as a result of large reservoir pressure drop due to oil production. This large pressure drop causes the fracture pore volume, therefore fracture porosity, to increase. This behavior is observed particularly in reservoir where matrix porosity is much greater than fracture porosity. Fractures in reservoirs are more vertically than horizontally oriented, and the stress axis on the formation is also essentially vertical. Under these conditions, when the reservoir pressure drops, the fractures do not suffer from the stress caused by the drop. Using these principles, a new method is introduced for calculating fracture porosity from the storage capacity ratio, without assuming the total matrix compressibility is equal to the total fracture compressibility.

Several numerical examples are presented for illustration purposes.

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