| Abstract |
The understanding of the properties of two-phase flow in fractured rocks is central to the prediction of geothermal reservoir performance. In this study, we suggest an alternative approach to describe the two-phase relative permeability behavior in rough-walled fractures based on the two-phase flow structures. This approach lumps the microscale physical mechanism (viscous and capillary forces) into an apparent observable parameter, channel tortuosity, which was found to dominate the reduction of the relative permeabilities from the values that would be expected based on the X-curve. Three artificial fractures, smooth-walled, homogeneously rough-walled and randomly rough-walled fractures, were studied to represent distinct surface geometry and heterogeneity. The experimental results from these three fractures could be described successfully by the proposed model. Furthermore, we found that the magnitude of the channel tortuosity increases when the heterogeneity of the fracture surface increases. Although only three simplified fractures were studied and the relationship between the flow-based heterogeneity and the channel tortuosity is not fully developed yet, we were able to derive an empirical, tortuous channel model generalized from all channel tortuosities from these three fractures. This model can represent the current experimental data and as well as observations from earlier studies with good agreement. |