We have observed that pressure transient data gathered in most naturally fractured reservoirs tend not to exhibit the well-known characteristic behavior, including pressure derivative, of the Warren and Root (1963) dual-porosity reservoir model. In reality, there are a rich variety of flow regimes dependent on the fracture distribution, spatial intensity and fracture conductivity. A semi-analytical solution for pressure transient behavior of fractured reservoirs has recently been presented that can be used to model the pressure response of formations with an arbitrary fracture distribution, density, and conductivity. The fractured system can be distributed discretely or continuously (network) with conductivities ranging from very low to infinite. Using the semi-analytical solution for fractured reservoirs, we perform a sensitivity analysis to identify which reservoir and geological parameters can be estimated from pressure transient test data collected from single or multiple well locations.

We employ principal component analysis to explore the model parameterization as a pre-screening step. The global sensitivity analysis (GSA) methodology is then employed to determine how the uncertainty of each parameter influences the uncertainty in the output from the reservoir model. This methodology avoids the need to apply a linearized model. Our results indicate that near-wellbore region fracture conductivities have the largest contribution to the total variance of the ensemble of output pressure responses whether the well intersects fractures or not. While this is an intuitive result, GSA indicates that this parameter may be estimated independently from other geomodeling parameters unlike interpretations based on the dual-porosity pressure transient solutions. This study describes how GSA is used to design a pressure transient well test for uncertain reservoir parameters.