Characterization of Bitumen Bearing Carbonate Rocks

Several countries, including Canada, contain sizeable bitumen resources in highly fractured carbonate rocks. Any possible recovery of bitumen from these reservoirs will be highly dependent on proper understanding of the rock and fluid properties and how they vary in the reservoir. These carbonates are extremely heterogeneous, and as a result proper reservoir characterization is challenging. In this study, a combined approach of x-ray computer tomography and low field NMR were applied on two full diameter native-state cores. CT imaging provides 3-D density and porosity, and maps a detailed distribution of the fracture network and primary, secondary or karst (breccia) porosity, as it varies for different rock types and locations. NMR spectra were acquired along the length of each core, in order to provide water and bitumen saturation predictions, and information about the fluid’s locations in the rock. By combining the CT and NMR results, additional information regarding the fluid saturations and oil viscosity can also be identified. This study demonstrates how the application of CT and NMR technology can be used simultaneously for improved reservoir characterization in complex bitumen-carbonate systems. These techniques could also be extended to interpreting logging tool data acquired in such formations. INTRODUCTION Considerable worldwide oil resources are located in carbonate reservoirs. These formations pose unique challenges to oil recovery, due to factors such as partial/full oil wetting and heterogeneity of pore structures. In Canada, the focus in recent years has shifted to the development of the high density and viscosity bitumen that is found mainly in the oil sands of northern Alberta. Approximately 71 billion m3, or 26% of the total bitumen resource base, is located in carbonate reservoirs [1]. These carbonates are difficult to exploit due to their complex geology, and are characterized by heterogeneous porous media exhibiting low primary recovery, rapid pressure decline and significant production challenges [2]. The in-place oil viscosity is also exceedingly high, on the order of millions of mPas (cP) at reservoir temperature. The screening of any potential EOR technique first requires a good understanding of how the fluid and rock properties vary in the reservoir. In this study, a combination of x-ray CT scanning and low field nuclear magnetic resonance (NMR) are used to characterize the rock properties and the fluid saturations/distributions in two samples of carbonate from northern Alberta. NMR and density measurements are common in both special core analysis and in logging tool runs, so the successful application of these techniques to bitumen carbonate reservoir characterization can be very useful for future field development.