Steam-C0 Recovery Processes For Bottom Water Oil Reservoirs

Abstract

Abstract 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 bottom 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 underlaid by a 2.2 m bottom water zone. In addition to steam-CO2 continuous injection, CO2 soak prior to steam injection, hot water-CO2 injection and CO2 followed by steam injection (CO2steam sequential injection) were evaluated. The results indicate that the co-injection of a gas with steam accelerates and improves oil recovery rates, as compared to steam-only injection, during the initial stage of the process. The steam-CO2 continuous injection resulted in a better performance (76% final recovery and 0.5 maximum oil-to-steam ratio) than that from steam alone (53% final recovery and 0.24 maximum oil-to-steam ratio). The final oil recovery from the steam-CO2 continuous injection was about the same as that from CO2, steam sequential injection (76% versus 75%. respectively). However, the rate of recovery and oil-to-steam ratios from the steam CO2 continuous injection were higher than those from the CO2 steam: sequential injection (maximum oil-to-steam ratios were 0.5 and 0.32, respectively). On the basis of pore volumes injected, steam-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 processes 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 steam injectivity due to blocking of the bottom water zone with a high viscosity oil. Introduction The design of an effective oil recovery process for bottom water reservoirs depends on oil sands to bottom water thickness ratio, permeabilities and oil saturation as well as on the injection/production strategies used. For favorable reservoir parameters, the bottom water zone can be beneficial in the recovery of high viscosity oil since it provides initial injectivity of hot fluids into the reservoir. Steam injection has been successful in bottom water reservoirs where the water zone volume is small relative ti the oil sands volume (1), injection of gas (3,4) and polymers(5) have been suggested in the literature. To thermally reduce the viscosity of Cold Lake bitumen to 200 mPa.s (200 cP), it is necessary to increase the temperature to 120 °C. A reduction in bitumen viscosity could also be accomplished by contacting the bitumen with suitable gases such as CO2 machine or propane, either alone or in combination. For example, the reduction of bitumen viscosity to 200 mPa.s could be achieved at 85 °C by dissolving CO 2 in bitumen at 3 MPa. The solubility of CO2 in r=reservoir fluids also results in oil swelling, vapourization of oil and interfacial tension effects. All of these are beneficial in the recovery of Bitumen from oil sands.