Evaluation of Naturally Fractured Reservoir Characteristics Utilizing Well Testing Analysis: A Case Study Ellenberger Oil Field

Abstract

Naturally fractured reservoirs differ significantly from conventional reservoirs due to the presence of fractures that promote fluid flow and reservoir connectivity. This study used dual-porosity and dual-permeability models to analyze well data from the Ellenberger field in Texas, USA. Dual-porosity systems simplify the complexities of fractured reservoirs with natural gaps, including fractures, and caverns, , by dividing them into two basic systems - a fluid-conducting network and a storage matrix. The conductive network enhances fluid transport, while both media serve as effective fluid storage. The models developed are characterized by marked variations in their conceptual assumptions regarding the fluid flow mechanism across the matrix. The current models are based on matrix blocks of regular shapes, for instance cylinders, cubes, and spheres, and suppose that fluid exchange between the matrix and fractures arises under pseudo-steady state or unsteady conditions. In the present oil field, well tests, such as pressure buildup and drawdown, based on diffusion equations, have been performed to characterize naturally fractured reservoirs. A mathematical model was developed based on well pressure data during production, with shut-in periods analyzed to evaluate reservoir behavior accurately. The results showed that the fractures in this field classify it as Type I, where fractures play a vital role in providing porosity and permeability to the reservoir, as well as wide drainage zones per well and rapid production decline rate.