No abstract

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 coinjecting gas and surfactant solution at fixed foam quality. It was stabilized using two surfactants, namely, C14–16 α-olefin sulfonate (AOS) and mixtures of AOS and a polymeric fluorocarbon (FC) ester. The effects of surfactant concentration, injection direction, surfactant preflush, 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 preflush were delayed compared to the case with preflush. Gravity-stable foam injection caused a rapid increase in foam strength and an incremental oil recovery almost twice that for unstable flow conditions. Core floods revealed that the incremental oil recovery by foam was as much as (23 ± 2)% of the oil initially in place after injection of 4.0 pore volumes (PV) of foam (equal to the injection of 0.36 PV of surfactant solution). Incremental oil recovery was only (5.0 ± 0.5)% for gas flooding under the same injection conditions. It appears that oil production by foam flooding occurs by the following main mechanisms: (1) residual oil saturation to foam flooding is lower than that to water flooding; (2) formation of an oil bank in the first few injected pore volumes, coinciding with a large increase of capillary number; and (3) a long tail production due to the transport of tiny oil droplets within the flowing foam at a fairly constant capillary number. The observations of this study support the concept that foam is potentially an efficient enhanced oil recovery (EOR) method.

Summary A detailed laboratory study of nitrogen-foam propagation in natural sandstones in the absence of oil is reported. The goal of this study was to elucidate further the mechanisms of foam mobility control. The C14–16 alpha-olefin sulfonate (AOS) surfactant was selected to stabilize foam. X-ray computed-tomography (CT) images were taken during foam propagation to map liquid saturation over time. Effects of surfactant concentration and of total injection velocity were examined in detail because these are key parameters for controlling foam strength and foam propagation under field conditions. The experiments revealed that foam mobility decreases in two steps: During initial forward foam propagation, foam mobility decreases by an order of magnitude compared with water mobility; during a secondary backward liquid desaturation, it decreases further by one to two orders of magnitude for sufficiently high surfactant concentrations. The steady-state mobility-reduction factor (MRF) increases considerably with both surfactant concentration and total injection velocity. A hysteresis was observed for a cycle of increasing/decreasing surfactant concentration or total injection velocity. The observed effects could be interpreted mechanistically in terms of surfactant adsorption and foam rheology. Implications for field application of foam for immiscible and miscible gas enhanced oil recovery (EOR) are discussed.