STEAM-CO2 RECOVERY PROCESSES FOR BOTTOM WATER OIL-RESERVOIRS

Based on Pujol and Boberg's scaling criteria, a series of experiments on steam-CO2 injection strategies was conducted in a high temperature, high pressure scaled model to evaluate oil recovery processes for bot tom water reservoirs. The scaled model simulated one-eighth of a five- spot pattern for a Cold Lake oil sand deposit of 12.8 m thickness unde rlaid by a 2.2 m bottom water zone. In addition to steam-CO2 continuou s injection and CO2 followed by steam injection (CO2-steam sequential injection) were evaluated. The results indicate that the co-injection of a gas with steam accelerates and improves oil recovery rates, as co mpared to steam-only injection, during the initial stage of the proces s. The steam-CO2 continuous injection resulted in a better performance (76% final recovery and 0.5 maximum oil-to-steam ratio) than that fro m steam alone (53% final recovery and 0.24 maximum oil-to-steam ratio) . The final oil recovery from the steam-CO2 continuous injection was a bout the same as that from CO2-steam sequential injection (76% versus 75%, respectively). However, the rate of recovery and oil-to-steam rat ios from the steam-CO2 continuous injection were higher than those fro m the CO2-steam sequential injection (maximum oil-to-steam ratios were 0.5 and 0.32 respectively). On the basis of pore volumes injected, st eam-only injection resulted in a dramatic improvement in oil recovery (53% final recovery) as compared to hot water-CO2-injection (27% final recovery). When compared on the basis of energy injected, performance of the steam-only and hot water-CO2 process were comparable (economic factors may tilt the benefits to the hot water-CO2 process). Soaking the reservoir with carbon dioxide prior to steam injection reduced ste am injectivity due to blocking of the bottom water zone with a high vi scosity oil.