Fractures often influence production in hydrocarbon reservoirs, yet the pressure transients observed in the wells might not show the conventional well-test signatures. In this case, the effect of fractures on production would be misinterpreted or even completely missed. The heterogeneous nature of fractured reservoirs makes them difficult to characterize and develop. In addition, the location of a producer within the fracture network also affects the pressure response; however, conventional well-test analysis assumes that the producer is located in symmetrical fracture networks. In this paper we investigate the effects of variations in fracture conductivity and location of the producer in the fracture network on the pressure-transient responses. To overcome the limitations of the dual-porosity (DP) model, this study uses a discrete fracture/matrix (DFM) modeling technique and an unstructured-grid reservoir simulator to generate pressure transients in all analyzed fracture networks. Our rigorous and systematic geoengineering work flow enables us to correlate the pressure transients to the known geological features of the simulated reservoir model. We observed that the simulated pressure transients vary significantly depending on the location of the producer in the fracture network and the properties of the fractures that the producer intercepts. Our findings enable us to interpret some unconventional features of intersecting fractures with variable conductivity. We observed that the behavior of two intersecting fractures, in which the well asymmetrically intercepts a finite-conductivity fracture, can be similar to that of a well intercepting a fracture in a connected fracture network with uniform fracture conductivity. Furthermore, a well intercepting a finite-conductivity fracture in naturally fractured reservoirs (NFRs) with both finite- and infinite-conductivity fractures would yield a DP response (V-shape) that might otherwise be absent if the fracture network is assumed to have uniform conductivity.

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Geological reservoirs can be extensively fractured but the well-test signatures observed in the wells may not show a pressure transient response that is representative of naturally fractured reservoirs (NFRs): for example, one that indicates two distinct pore systems (i.e. the mobile fractures and immobile matrix). Yet, the production behaviour may still be influenced by these fractures. To improve the exploitation of hydrocarbons from NFRs, we therefore need to improve our understanding of fluid-flow behaviour in fractures.

Multiple techniques are used to detect the presence and extent of fractures in a reservoir. Of particular interest to this work is the analysis of well-test data in order to interpret the flow behaviour in an NFR. An important concept for interpreting well-test data from an NFR is the theory of dual-porosity model. However, several studies pointed out that the dual-porosity model may not be appropriate for interpreting well tests from all fractured reservoirs.

This paper therefore uses geological well-testing insights to explore the limitations of the characteristic flow behaviour inherent to the dual-porosity model in interpreting well-test data from Type II and III NFRs of Nelson's classification. To achieve this, we apply a geoengineering workflow with discrete fracture matrix (DFM) modelling techniques and unstructured-grid reservoir simulations to generate synthetic pressure transient data in both idealized fracture geometries and real fracture networks mapped in an outcrop of the Jandaira Formation. We also present key reservoir features that account for the classic V-shape pressure derivative response in NFRs. These include effects of fracture skin, a very tight matrix permeability and wells intersecting a minor, unconnected fracture close to a large fracture or fracture network. Our findings apply to both connected and disconnected fracture networks.@en

A geological well testing model containing fractures and matrix was built to match an observed complex well test response in a reservoir that was known to be fractured. The resulting match of a well intersecting minor fractures near a major fracture was considered a good match in consideration of alternative geological scenarios. This match leads to a better understanding of the key reservoir features to reliably support development decisions

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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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Geological well testing is a valuable tool that allows us to improve understanding of pressure transient behaviour in a fractured reservoir. However, not all wells in a fractured reservoir will show pressure transients that are expected for NFRs. Our findings demonstrate that high resolution models with proper grid refinement around the wells and fractures are required to model pressure transient behaviour adequately and produce a physically meaningful wellbore response for a fractured reservoir. The key concept for interpreting well test data from fractured reservoirs is the dual-porosity model. This model, originally developed by Warren and Root (1963) has been the industry standard for modelling NFRs and interpreting well-test data from NFRs for more than 50 years. Although there are a number of factors impacting the exact shape of the pressure transients, our results suggest that observing the classical “V-shape” in the pressure derivative, as expected from a dual-porosity model may be an exception, rather than a rule in NFR, even for well-connected fracture networks. Our work quantifies when and why the assumptions inherent to the dual-porosity model break down when interpreting well-test data from NFR. @en