Effect of oil saturation on foam propagation in Snorre reservoir core

A series of foam floods was conducted in Snorre reservoir core at 90°C and 300 bar, at different oil saturations. The rate of foam propagation decreased and the time required to reach the maximum attainable apparent foam viscosity increased strongly with oil saturation. Apparent foam viscosity decreased steeply at a “critical” oil saturation of 13% to 15%. Extremely high apparent foam viscosities, up to 1000 cP, were generated at miscible gas flood residual oil saturation (13%). Above the critical oil saturation, strong foams with apparent viscosities of about 200 cP were still formed, compared to apparent gas viscosities in the absence of surfactant of 0.5 to 0.7 cP. The effect of gas composition (Snorre field gas, methane, nitrogen) on foam performance was minor. Significant residual gas mobility reduction was observed during gas injection into the foam-filled core.