Impact of Oil on Steam Foam Formulations at 250°C
- Amandine Cuenca (Solvay) | Emie Lacombe (Solvay) | Max Chabert (Solvay) | Mikel Morvan (Solvay) | Eric Delamaide (IFP Technologies Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE EOR Conference at Oil and Gas West Asia, 21-23 March, Muscat, Oman
- Publication Date
- Document Type
- Conference Paper
- 2016. Society of Petroleum Engineers
- 2 Well completion, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.4.6 Thermal Methods, 5.3.4 Reduction of Residual Oil Saturation, 2.5 Hydraulic Fracturing
- Foam, EOR, Surfactant, Steam, Oil
- 1 in the last 30 days
- 261 since 2007
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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.
|File Size||3 MB||Number of Pages||19|