The most widespread thermal EOR method relies on steam injection. Steam is employed to warm up the reservoir, increase oil mobility and in turn enhance heavy oil recovery. In steam injection processes, recovery of oil is limited by steam channeling due to reservoir heterogeneities. Early breakthrough implies large consumption of steam and incomplete reservoir drainage. A low cost viable option to minimize heat loss consists in generating steam foam in situ. Foam will reduce steam mobility, increase its apparent viscosity and reduce steam channeling. Foam should form and flow in reservoir swept regions containing residual oil saturation. For a field application, where the residual oil saturation may vary from 0 to 30% depending on the recovery method applied, any effect of the oil on foam stability becomes a crucial matter. The scope of this work is to design an appropriate foaming surfactant solution in reservoir representative conditions of 250°C. We study the impact of crude oil on its foaming properties.
Previous publications demonstrate that formulation viscosity as well as foamability and foam stability are key parameters to optimize steam mobility reduction in model porous media. It is also well known that measuring foam properties at 200°C in presence of heavy crude oil is an experimental challenge. Injecting heavy oil in common equipment is often problematic, due to its high viscosity and low flowability. Our methodology is based on the use of high pressure/high temperature set-ups, such as sapphire view cell to measure foam stability, capillary rheometer to measure formulation viscosity and high temperature sandpack experiments to measure gas mobility reduction in model porous media. We also present a new high pressure/high temperature screening tool based on disposable containers to evaluate foaming properties in presence of heavy crude oil.
We have shown in previous work that long chain surfactants present high foam forming ability at 200°C. We build on our knowledge to demonstrate foam existence at 250°C. This study highlights the performance of new foaming formulations at this temperature. Our development effort has been concentrated on building a novel experimental setup and also providing data to evaluate the impact of heavy crude oil on foaming performances. Based on our experimental results, we demonstrate that foam stability in presence of crude oil can be improved by surfactant synergetic associations.
Overall, this work offers new insights to design efficient steam foaming formulations up to 250°C, in particular in presence of heavy crude oil. This novel approach helps in developing more efficient steam foam EOR solutions and in optimizing steam injection processes.
In western Canada, there are significant amounts of oil sands reserves that have little or no cap rock with a top water zone (Alturiki et al 2011); because of huge heat loss, conventional SAGD process is uneconomical when it is directly applied in this type of reserves.
In this study, it is proposed that high temperature polymer can be injected into the bottom of the top water zone to establish a stable high viscosity layer in order to prevent steam from leaking to the top water zone. Lab tests were first conducted to screen the polymers. In order to select a proper polymer which was able to have stable viscosity under high temperature, viscosities of different polymers at different temperatures were measured; and concentration of the selected polymer was optimized. Then numerical simulations were performed to evaluate the feasibility of using the selected polymer to improve SAGD performance in oil sands with top water. The numerical simulation model was based on Athabasca oil sands reservoir. In this formation, the top water zone was around 94 meters, while the reservoir thickness was about 30 meters. The vertical permeability was 50 mD and 1,400 mD for the top water zone and the oil zone, respectively. And the porosity was 10% for the top water zone and 30% for the oil zone. The effect of the polymer injection strategy including the polymer injection parameters, such as polymer slug size, injection rate, injection time and well distance on the performance of SAGD process was studied.
The numerical simulation results suggested that, polymer injection was able to block the heat from leaking to the top water zone. With polymer injection, the cSOR can be reduced from 8.5 m3/m3 to 4.8 m3/m3, while for the case without top water, the cSOR was 3.8 m3/m3. This indicates that polymer injection is technically feasible to improve SAGD performance in oil sands with top water.
Cuthiell, D. (Alberta Research Council) | Kissel, G. (Alberta Research Council) | Jackson, C. (Alberta Research Council) | Frauenfeld, T. (Alberta Research Council) | Fisher, D. (Alberta Research Council) | Rispler, K. (Alberta Research Council)