Publications

When rock properties and operational problems limit electric log and core data, it is possible to determine important reservoir characteristics using well test data. This paper describes a technique to identify vugs from pressure buildup data. The subject reservoir is an under-saturated carbonate dominated by vugs and karsts. The authors analyzed 80 hours of pressure buildup following 100 hours of pressure drawdown. It was observed that pressure derivative behavior cannot be adequately described using current naturally fractured reservoir (NFR) dual and triple porosity models. This is because some pressure derivatives are obscured by reservoir boundaries and the matrix-to-fracture fluid transfer does not behave as expected in a multiple porosity reservoir. In this heterogeneous reservoir, we believe this corresponds to the number of matrix inter-porosity flow parameters, and hence degree of reservoir heterogeneity. If we force the data using dual porosity or triple porosity models, the error is high (>15 percent), because the pressure derivative cannot adequately respond to all the transition periods. Combined analytical and numerical methods were utilized to address this problem. Firstly, the reservoir parameters (w, l and k) were estimated from the dual porosity analytical solution. Next, a numerical triple porosity model was defined to represent the reservoir. Initial reservoir parameters were established from analytical results. History matching procedures were performed to compare DST data with the calculated bottom-hole pressure. When these agree, reservoir flow capacity and storage capacity can be determined for fracture, matrix and vug respectively. Results demonstrated that vug volumes should not be ignored in a triple porosity system. Determining reservoir parameters using well test data in carbonates (especially for very thick, very permeable reservoirs) employing current analytical models can result in estimated permeabilitysignificantly different from the actual. The technique described herein results in improved permeability estimates by quantifying vugs (or karsts) from well test data when analytical dual porosity or triple porosity models are unable to handle all matrix-to-fracture inter-porosity flow due to reservoir heterogeneity.