This paper presents experimental and simulated results from two vertical core floods. The core floods consisted of injecting equilibrium gas and separator gas from the top of the core after water flooding from the bottom, respectively.
The results show that an oil bank was formed in both experiments. When separator gas was injected, oil was also recovered by vaporization.
Compositional analysis of the produced fluids during separator gas injection shows that considerable amounts of intermediate components were produced as condensate after gas breakthrough. Significant end effects were observed in the final water saturation profiles due to capillary hold-up. Analysis of the final oil saturation in the core indicates a significant gradient due to vaporization, and greater than that modeled by the compositional simulator based on an equation of state.
Water injection into sandstone oil reservoirs may achieve high sweep efficiencies. However, considerable quantities of oil will still remain in a reservoir at the end of a successful water flood, with typically more than 50% of the original oil in place. This residual oil is a target for gas flooding after water flooding, termed here as tertiary gas injection.
Gas injection may recover additional oil because of lower residual oil saturation after gas flooding, typically 5% to 30%. During gas flooding, the oil saturation is reduced due to convective flow and mass exchange between oil and gas.
Besides improving microscopic sweep efficiency, tertiary gas injection may reach regions of a reservoir not swept by water, for example "attic oil." The situation is, however, more often one in which the sweep efficiency is low for tertiary gas injection, a general problem associated with injecting gas. Some means of controlling gas mobility may therefore be aimed at, such as gravity stable gas injection or water alternating gas injection.
During tertiary gas injection, large quantities of mobile water are present in the porous medium, causing a long period of water production prior to the arrival of the oil bank at the producers.
Tertiary gas injection introduces conditions for three phase flow. In parts of the reservoir, three phases may be flowing simultaneously, or oil and gas may flow through paths of water saturations different from connate. This implies that the process may be situated in the three phase space at positions different from those where the relative permeabilities are usually measured. Correlations have been introduced in order to estimate oil relative permeability in the three phase mode from measured two phase data to be applied in reservoir simulators. The correlations are introduced because these quantities are not easily accessible experimentally.
High water saturations in the porous medium nay also influence the mass exchange between gas and oil, and thus modify the process efficiency in an unfavorable way.