Energy Geoscience (Jan 2024)
Displacement characteristics of CO2 flooding in extra-high water-cut reservoirs
Abstract
Carbon dioxide (CO2) flooding is a widely applied recovery method during the tertiary recovery of oil and gas. A high water saturation condition in reservoirs could induce a ‘water shielding’ phenomenon after the injection of CO2. This would prevent contact between the injected gas and the residual oil, restricting the development of the miscible zone. A micro-visual experiment of dead-end models, used to observe the effect of a film of water on the miscibility process, indicates that CO2 can penetrate the water film and come into contact with the residual oil, although the mixing is significantly delayed. However, the dissolution loss of CO2 at high water-cut conditions is not negligible. The oil-water partition coefficient, defined as the ratio of CO2 solubility in an oil-brine/two-phase system, keeps constant for specific reservoir conditions and changes little with an injection gas. The NMR device shows that when CO2 flooding follows water flooding, the residual oil decreases—not only in medium and large pores but also in small and micro pores. At levels of higher water saturation, CO2 displacement is characterized initially by a low oil production rate and high water-cut. After the CO2 breakthrough, the water-cut decreases sharply and the oil production rate increases gradually. The response time of CO2 flooding at high water-cut reservoirs is typically delayed and prolonged. These results were confirmed in a pilot test for CO2 flooding at the P1-1 well group of the Pucheng Oilfield. Observations from this pilot study also suggest that a larger injection gas pore volume available for CO2 injection is required to offset the dissolution loss in high water saturation conditions.
