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Flow behavior in a dual fracture network
A model that incorporates a pseudo-random process controlled by mechanical rules of fracturing is used to generate 3D orthogonal joint networks in tabular stratified aquifers. The results presented here assume that two sets of fractures, each with different conductivities, coexist. This is the case in many aquifers or petroleum reservoirs that contain sets of fractures with distinct hydraulic properties related to each direction of fracturing. Constant rate pump-tests from partially penetrating wells are simulated in synthetic networks. The transient head response is analyzed using the type curve approach and plots, as a function of time, of pressure propagation in the synthetic network are shown. The hydrodynamic response can result in a pressure transient that is similar to a dual-porosity behavior, even though such an assumption was not made a priori. We show in this paper that this dual porosity like flow behavior is, in fact, related to the major role of the network connectivity, especially around the well, and to the aperture contrast between the different families of fractures that especially affects the earlier hydrodynamic response. Flow characteristics that may be interpreted as a dual porosity flow behavior are thus related to a lateral heterogeneity (large fracture or small fault). Accordingly, when a dual porosity model matches well test data, the resulting reservoir parameters can be erroneous because of the model assumptions basis that are not necessarily verified. Finally, it is shown both on simulated data and well test data that such confusion in the interpretation of the flow behavior can easily occur. Well test data from a single well must therefore be used cautiously to assess the flow properties of fractured reservoirs with lateral heterogeneities such as large fractures or small faults.