Foams are used for mobility control or blocking and diversion of injected fluids in oil recovery by gas or solvent injection. The combined effects of gas or solvent composition, the presence of crude oil, and wettability on foam flow resistance or gas mobility reduction by foam in porous media were investigated. Experiments were carried out at Rainbow Keg River conditions (85 ° C, 17.3 MPa) with a commercial surfactant formulated for hydrocarbon miscible flooding at high salinity (Chaser GR- 1080). Foam floods were performed in clean and in asphaltenetreated Indiana limestone cores containing Rainbow Keg River crude oil and injection water, using two miscible (propane and a field solvent mixture) and an immiscible (methane) solvent.
Hydrocarbon solvent-foam effectiveness, asssessed by the level of gas or solvent mobility reduction by foam, is strongly influenced by solvent composition. Methane-foam Mobility Reduction Factors (MRFs) up to 74 were measured, while the solvent mixture-foam generated slightly lower MRFs up to 52. Propane-foam was comparatively ineffective with MRFs up to only six. Propane-foam effectiveness was increased significantly at lower pressure, independently of a phase change from liquid to gaseous propane. The presence of crude oil at a saturation of approximately 15% reduced the effectiveness of methane-foam. However, methane-foam displaced oil gradually, leading to improved foam performance. Oil did not affect the solvent mixture- foam or propane-foam substantially, because both solvents were miscible with the oil and rapidly displaced the oil. Foam performance was unaffected by wettability, because the surfactant reversed the wettability of the asphaltene-treated solid from intermediately wet to water-wet. Chaser GR-1080 adsorbed moderately (at approximately 0.25 mg/g) in clean and in asphaltene- treated Indiana limestone cores.
Canada's improved oil production is dominated heavily by hydrocarbon miscible flooding, mostly in carbonate pools(1). Gravity override and viscous instabilities, caused by the low density and viscosity of the injected fluids, often result in poor sweep efficiency and early gas breakthrough. Foams can significantly increase the effective viscosity of a gas phase, thus decreasing gas mobility, or, if effective foam viscosity is sufficiently high, block preferential flow channels.
While foams generated with nitrogen, steam, or CO2 have been extensively studied, limited laboratory(2–8) and field(5,6,9) data are available on hydrocarbon solvent-foams. The properties of solvent- foams may be different from those of nitrogen-, CO2-, or steam-foams for several reasons:
Depending on reservoir conditions, a miscible solvent may be gaseous, liquid, or supercritical, and may approach a light oil phase in properties. Oil can affect foam performance strongly (and usually negatively).
Solvent composition varies depending on the application, and compositional effects on foam behaviour have to be accounted for.
Foam properties are determined by interfacial and thin film properties which are affected by solvent composition.
These properties are not well understood or easily measured for systems containing light hydrocarbons at high temperature and pressure.
This work is an investigation into the effects of solvent composition, wettability, and oil on foam performance at reservoir conditions typical for a solvent-flooded pool in Alberta.