Transcripción del resumen del autor Dual-porosity and dual-permeability models for naturally fractured reservoirs assume that the fractures in the reservoir are connected with each other and uniformly distributed. However, in some cases, the reservoir characteristics exhibit a discrete-fracture system, which means that the fractures might be unconnected and their distribution is not uniform. In this paper, a new computational model is developed to compute the transient-pressure behaviour for reservoirs with a discrete-fracture system. This computational model is based on Laplace transforms. The fluid flow in the fracture system and reservoir are computed separately, and flux and pressure equivalent conditions in Laplace space are applied in the fracture wall to couple the fluid flow in both systems. The results suggest that the pressure response in a reservoir with a discrete-fracture system has three flow regions: fluid flow near the wellbore, fracture-dominated fluid flow, and fluid flow in the matrix away from the fracture. The distance between the fracture and the well, fracture parameters (fracture conductivity and non-Darcy effects), and fracture distribution are the main factors affecting the pressure response. In some particular situations, the fracture-dominated fluid-flow region in the pressure-derivative curve may present two valleys, which has been observed in some field cases (Clarkson 2009). The transient-pressure behaviour of a discrete-fracture system is also compared with that for a composite model. It is suggested that in these two scenarios, the early- and middle-time transient-pressure behaviour may be similar and latetime behaviours are quite different. The model provides a tool for identifying the fracture pattern in a specific reservoir.

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