Foam assisted low interfacial tension enhanced oil recovery
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Alkali-Surfactant-Polymer (ASP) or Surfactant-Polymer (SP) flooding are attractive chemical enhanced oil recovery (EOR) methods. However, some reservoir conditions are not favorable for the use of polymers or their use would not be economically attractive due to low permeability, high salinity, or some other unfavorable factors. In such conditions, gas can be an alternative to polymer for improving displacement efficiency in chemical-EOR processes. The co-injection or alternate injection of gas and chemical slug results in the formation of foam. Foam reduces the relative permeability of injected chemical solutions that form microemulsion at ultra-low interfacial tension (IFT) conditions and generates sufficient viscous pressure gradient to drive the foamed chemical slug. We have named this technique of foam assisted enhanced oil recovery as Alkali/Surfactant/Gas (ASG) process. The concept of ASG flooding as an enhanced oil recovery technique is relatively new, with very little experimental and theoretical work available on the subject. This dissertation presents a systematic study of ASG process and its potential as an EOR method. We performed a series of high performance surfactant-gas tertiary recovery corefloods on different core samples, under different rock, fluid, and process conditions. In each coreflood, foamed chemical slug was chased by foamed chemical drive. The level of mobility control in corefloods was evaluated on the basis of pressure, oil recovery, and effluent data. Several promising surfactants, with dual properties of foaming and emulsification, were identified and used in the coreflood experiments. We observed a strong synergic effect of foam and ultra-low IFT conditions on oil recovery in ASG corefloods. Oil recoveries in ASG corefloods compared reasonably well with oil recoveries in ASP corefloods, when both were conducted under similar conditions. We found that the negative salinity gradient concept, generally applied to chemical floods, compliments ASG process by increasing foam strength in displacing fluids (slug and drive). A characteristic increase in foam strength was observed, in nearly all ASG corefloods conducted in this study, as the salinity first changed from Type II(+) to Type III environment and then from Type III to Type II(-) environment. We performed foaming and gas-microemulsion flow experiments to study foam stability in different microemulsion environments encountered in chemical flooding. Results showed that foam in oil/water microemulsion (Type II(-)) is the most stable, followed by foam in Type III microemulsion. Foam stability is extremely poor (or non-existent) in water/oil microemulsion (Type II (+)). We investigated the effects of permeability, gas and liquid injection rates (injection foam quality), chemical slug size, and surfactant type on ASG process. The level of mobility control in ASG process increased with the increase in permeability; high permeability ASG corefloods resulting in higher oil recovery due to stronger foam propagation than low permeability corefloods. The displacement efficiency was found to decrease with the increase in injection foam quality. We studied the effect of pressure on ASG process by conducting corefloods at an elevated pressure of 400 psi. Pressure affects ASG process by influencing factors that control foam stability, surfactant phase behavior, and rock-fluid interactions. High solubility of carbon dioxide (CO₂) in the aqueous phase and accompanying alkali consumption by carbonic acid, which is formed when dissolved CO₂ reacts with water, reduces the displacement efficiency of the process. Due to their low solubility and less reactivity in aqueous phase, Nitrogen (N₂) forms stronger foam than CO₂. Finally, we implemented a simple model for foam flow in low-IFT microemulsion environment. The model takes into account the effect of solubilized oil on gas mobility in the presence of foam in low-IFT microemulsion environment.