Naturally fractured reservoirs (NFRs) account for a significant amount of the world conventional reserves but suffer from low recovery factors. Multiple techniques are, often in combination, used to detect the presence and extent of fractures in a reservoir. Of particular interest to this work is the use of dual-porosity model for analysis of well test data in order to identify and interpret the behaviour of fluid flow in NFR. This model, originally developed by Warren & Root (1963), has since been the industry standard for modelling NFRs and interpreting well-test data from NFRs. However, several studies have shown that the dual-porosity responses expected for naturally fractured reservoirs are not always observed where the wellbore intersect fractures, even for heavily and well-connected fractured network reservoirs. Our research aims to examine the reservoir features that cause the dual-porosity response to absent in some naturally fractured reservoirs and to be present in others. We demonstrate when dual porosity models are valid for well-test interpretation and can capture the key reservoirs features that characterise flow behaviours in NFRs. These features include the effect of fracture skin, network connectivity, and network size. The findings allow us to interpret well-tests in NFR more reliably.


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