Bitumen is too viscous to be produced by conventional recovery methods and significant amounts are too deep to be recovered by mining, necessitating enhanced in-situ oil recovery techniques. The majority of operating and planned in-situ bitumen projects employ thermal techniques to lower the bitumen's viscosity, allowing it to be produced. The viscosity characteristics of the bitumen consequently have a significant effect on production rates and recovery. Bitumen viscosity and chemical composition variation with depth within a single reservoir column has been reported for many heavy oil and oil sand reservoirs in the Western Canadian Sedimentary Basin and elsewhere in the world.
This study investigates, through reservoir simulation, the effects of viscosity variation with depth on the SAGD process and the resulting produced oil characteristics. Oil characteristics, including chemical component and viscosity profiles were built into a variety of reservoir simulation models. The simulation results indicate that the produced oil viscosity and component concentration vary as the steam chamber develops. The trend of the produced oil characteristics is related to the original in-situ profiles of and the reservoir flow barriers. In conjunction with oil rate, surface heave, or other available data, the produced oil characteristics may be used to suggest steam chamber development and the presence of barriers or baffles. The presented approach has potential to become a useful technique for SAGD steam chamber growth monitoring and production optimization.
Oil viscosity and compositional gradients, both areal and vertical have been observed in various fields worldwide1. Differences in physical properties and chemical composition of oil are more significant in heavy oil and oil sands reservoirs2. Recently, more attentions has been paid to heavy oil and oil sands reservoirs in the Western Canadian Sedimentary Basin, where 172.7 billion barrels of bitumen and heavy oil are to be recovered3, mostly through thermal processes, such as CSS (cyclic steam stimulation) and SAGD (steam assisted gravity drainage). Erno et al. found that the viscosity increases towards the bottom of the reservoir for Clearwater B, McMurray, and Wabiskaw formations at Caribou Lake, and Waseca formation at Pikes Peak with up to an order of magnitude difference in the Clearwater B formation. It was suggested that the viscosity variation may affect the performance of CSS, the proposed recovery process for those reservoirs, and should be considered in reservoir characterization and modeling4. Chan et al.5 reported vertical variations of certain chemical compounds in a McMurray Formation corehole in the Athabasca area (re-plotted in Figure 1). They showed that the ratio of diasterane to regular sterane increases from the top to the bottom of the reservoir. Based on the observed baseline of chemical compound distribution, a field application was demonstrated that used the chemical compound concentration from the produced sample to diagnose the CSS performance5.