The Steam Assisted Gravity Drainage (SAGD) is the in situ technology of choice in the Athabasca deposit which is the single largest oil sands resource in Alberta. All operating companies are facing challenges in their SAGD operations. One of the most challenging issues in oil sands thermal in situ operations are reservoirs with challenging features such as thin reservoirs, reservoirs with top water/gas and bottom water thief zones, and reservoirs with higher initial water saturation (Law et al. 2003a, 2003b, 2003c, Gates et al. 2007). At this point, there are no published studies on the impact of high initial water saturation on the performance of SAGD in the McMurray Formation. To address this, the research documented in this thesis investigates the performance of SAGD in water-rich oil sands reservoirs by using thermal reservoir simulation. The research also explored the improvement of operating strategy in water rich oil sands reservoirs by using gas co-injection with steam. The results show that the higher the initial water saturation of the reservoir, the better the steam conformance along the SAGD well pair, the faster the steam chamber growth, and the higher is the injectivity into the reservoir. However, if the initial water saturation is sufficiently high, the oil production rate drops due to lower content of oil in the reservoir. Two operating strategies were tested to determine if the steam-to-oil ratio of SAGD in a relatively high initial water saturation McMurray Formation oil sands reservoir could be improved. In first strategy, gas is co-injected with steam and in the second strategy, a gas slug is injected into the reservoir prior to SAGD operation. The simulations results reveal that NCG co-injection does not improve the performance of the recovery process.