Prefrac pressure diagnostics, including fracture-injection/falloff sequences, have been used for several years to estimate initial reservoir pressure and transmissibility in unconventional reservoirs. Prior to performing pressure diagnostics, initial or average reservoir pressure is almost always unknown, and many times the purpose of a pressure diagnostic is to determine initial reservoir pressure. As shown by several authors, when a pressure diagnostic falloff exhibits bilinear, linear, or radial flow, the initial or average reservoir pressure can be determined from special plots using straight-line analysis methods. However, correctly identifying the flow regimes during a pressure falloff is often very difficult, and the tendency is to incorrectly apply straight-line analysis methods to data on a specialized plot that often does not correspond to a bilinear, linear, or radial flow regime. In many cases, bilinear, linear, or radial flow will not be observed in any of the falloff data, and valid estimates of initial reservoir pressure and transmissibility cannot be determined using straight-line methods.
This paper presents a new type curve analysis method that removes the limitations of conventional after-closure straight- line analysis of pressure diagnostics. Like conventional well test analysis, the new method fits observed pressure data to analytical type curves, and type curve match points are used to determine initial reservoir pressure, transmissibility, fracture half-length, fracture conductivity, and fracture damage. Type curve analysis has proved especially useful for post-frac evaluation of stimulation effectiveness, and has also proved useful in shale reservoirs where it is often difficult to determine if a dilated fracture or fracture network close completely, with no conductivity or retained residual width. Understanding dilation/contraction properties of a shale fracture network can provide important guidance for fracture treatment design and optimization. Type curve analysis has also reduced the amount of shut-in time required to obtain a quantitative estimate of reservoir and fracture properties albeit with increasing uncertainty as shut-in time decreases.