A systematic CT scan aided laboratory study of N2 foam in Bentheimer sandstone cores is reported. The aim of the study was to investigate whether foam can improve oil recovery from clastic reservoirs subject to immiscible gas flooding. Foam was generated in-situ in water-flooded sandstone cores by co-injecting gas and surfactant solution at fixed foam quality. It was stabilized using two surfactants, namely C14-16 alpha olefin sulfonate (AOS) and mixtures of AOS and a polymeric fluorocarbon (FC) esther. Effects of surfactant concentration, injection direction, surfactant pre-flush and core length on foam behavior were examined in detail. Stable foams were obtained in the presence of waterflood residual oil. It was found that foam strength (mobility reduction factor) increases with surfactant concentration. Foam development and, correspondingly, oil recovery without surfactant pre-flush were delayed compared to the case with pre-flush. Gravity stable foam injection caused a quick increase of foam strength and an incremental oil recovery almost twice that for unstable flow conditions. Core floods reveled that the incremental oil recovery by foam was as much as 23±2% of the oil initially in place after injection of 4.0 PV of foam (equals to injection of 0.36 PV of surfactant solution) compared with water flooding. Incremental oil recovery was only 5.0±0.5% for gas flooding at the same injection conditions. It appears that oil production by foam flooding occurs due to the following main mechanisms: (1) residual oil saturation to gas flooding is lower than to water flooding, (2) formation of an oil bank in the first few injected pore volumes, which coincides with a large increase of capillary number and (3) transport of dispersed oil by the flowing foam lamellae, leading to long tail production at a fairly constant capillary number. Observations of this study support the concept that foam is potentially an efficient EOR method.

You can access this article if you purchase or spend a download.