The use of pressure derivatives in well test interpretation by reservoir engineers is commonplace since the publication on this subject by D. Bourdet et al.1  in 1989. This paper examines the relationships between well test pressure derivatives and the nature of the fracture networks within the testing region through numerous well test simulations in synthetic fracture networks.

The main parameters studied are fracture intensity and fracture size distributions. Other factors such as anisotropy, existence of faults, and matrix fracture permeability contrasts are also discussed. Numerical simulations demonstrated that where fractures are the major conduits in a reservoir, the derivatives of a pressure transient well test are a good indication of the nature of the underlying fracture networks.

For a realistic prediction of the behavior of a naturally fractured reservoir, the geologists are usually charged with characterising the fracture network based on information available from geology, geophysics, petrophysics and other measurements performed in drilled wells. This study has shown that well test and production data, normally under reservoir engineer's possession, may provide further clues about the nature of the fracture network within a reservoir, and help in extrapolating fracture data from individual wells to between wells, and ultimately within the whole reservoir.

A case study is also briefly described in this paper.

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