Solvent-based processes are often used as potential recovery agents in bitumen systems, with and without the addition of heat to the solvent. Solvents can sometimes be applied as a liquid phase, during SAGD start-up operations or processes aimed at developing injectivity into the oil. Light hydrocarbon liquids are traditionally tested for this application. Solvent injection may also occur in a vapour state and its objective is to reduce oil viscosity and improve mobility of bitumen under low temperatures Ͻ100°C. In general, hydrocarbon solvents such as propane are often used for this application. The objective of this study is to conduct CT-based measurement of static mixing of bitumen and both liquid and vapour phase solvents, and to quantify some of the time-dependent changes that occur during solvent mixing with bitumen.Diffusion experiments have been conducted with propane and DME (vapour phase) and with propane, DME, pentane and toluene (liquid phase) solvent systems. Solvents are mixed with medium viscosity Peace River bitumen and high viscosity Grosmont bitumen. The Tests are run under constant pressure and temperature, and Computer-Assisted Tomography (CT) is used to monitor mass transfer of solvent into oil as a function of time. The outcome of this study is measurements of mass transfer rates of solvent into oil, and the degree of oil phase swelling during the tests.During solvent injection processes in the field, the rate of mixing is a key parameter that will help in deciding which solvent is optimal for different processes. This study focuses on the rate of solvent mixing with oil. In vapour phase solvent systems, the analysis of the CT images allows for an understanding of the impact of oil phase swelling on the effective rate of penetration of solvent into oil. Overall, the test data provided in this work demonstrates that DME mixes into oil faster than other solvents, and leads to more swelling in a vapour solvent-bitumen system. The analysis of CT data provides an understanding of concentration-dependent diffusion coefficients and limitations from predicting mass transfer using constant coefficients in liquid and vapour solvent systems.

In thermal enhanced oil recovery process, the clay shale formations above the oil sands reservoirs may be subjected to high pressures up to 10MPa and high temperatures up to 300°C. The responses of the clay shale are very critical for designing or operations of thermal recovery processes. Maintaining wellbore and caprock integrities prevents incidents such as borehole collapse and leakage through caprock. Thermally induced deformation and fracturing in shale impacts on wellbore and caprock integrities. Most previous investigations focused on the mechanical properties of the clay shale. However, limited experimental work has been conducted to investigate the thermal response of clay shale under thermal operation conditions.In this research, the thermal response of clay shale under different confining pressure conditions is investigated. Laboratory confined and unconfined tests were conducted on Colorado Shale cores which were retrieved from the overburden shale formation above the oil sands reservoirs in Cold Lake area, Alberta, Canada. The shale cores were heated at different heating rates and were subjected to different pressure conditions. The thermally induced deformation and fracturing responses in shale have been captured by X-ray computed tomography scanning (CT scan). The results show that under slow heating rates the shale sample maintains its integrity but display irreversible contraction after cooling to room temperature. Under high heating rates, the samples lose their integrity.