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.

No abstract

Summary 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.

Fractures often influence production behaviour in hydrocarbon reservoirs, yet the pressure transients observed in the wells may not show the conventional well-test signatures. In this case, the effect of fractures on production would be misinterperted or even completely missed. Fracture networks are commonly multi-scale and properties including aperture (or conductivity), length, connectivity and distribution vary greatly within a reservoir. The heterogeneous nature of fractured reservoirs make them very difficult to characterise and develop. In addition, the location of a producer within the fracture network also control flow rates and affect the pressure response; however, conventional well-test analysis assumes that the producer is located in symmetrical fracture networks. To improve our understanding of fracture flow behaviour from well-test data, and in order to better characterise the impact of fractures on reservoir performance, we investigate the effect of variations in fracture conductivity and location of the producer in the fracture network on the pressure transient responses. Naturally fractured reservoirs (NFR) with well-connected fracture networks are traditionally simulated using the Dual-Porosity (DP) model. However, several studies have shown that the classic DP response (V-shape) corresponding to the DP model is an exceptional behaviour applicable only to certain reservoir geology and does not apply to all NFR. To overcome the limitations of the characteristic flow behaviour inherent to this model, we employ Discrete Fracture Matrix (DFM) modelling technique and an unstructured-grid reservoir simulator to generate synthetic pressure transients in all fracture networks that we analysed. Our rigorous and systematic geoengineering workflow enables us to correlate the pressure transients to the known geological features of the simulated reservoir model. We observed that depending on the location of the producer in the fracture network and the properties of the fractures that the producer intercepts, the synthetic pressure transients vary significantly. We therefore use these insights to quantify the impact of variation in fracture conductivity and producer location on fracture flow behaviour and systematically present interpretations to these behaviours. Our findings enable us to interpret some unconventional features of intersecting fractures with variable conductivity. We observed that the behaviour of two intersecting fractures where 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 NFR with both finite- and infinite-conductivity fractures would yield a dual-porosity response that may otherwise be absent if the fracture network is assumed to have uniform conductivity.

No abstract