Abstract
Techniques have been developed to experimentally and numerically evaluate fluid injectivity and oil recovery of water-alternating-CO2 processes in tight oil formations. Experimentally, core samples collected from tight formations are utilized to conduct a series of water-alternating-CO2 flooding experiments with different water-alternating-CO2 ratios and slug sizes. The corresponding oil production, pressure drop, gas production and water production are examined throughout the experiments. Subsequently, numerical simulations are performed to history-match the experimental measurements and conduct sensitivity analysis on operational parameters (i.e., water-alternating-CO2 ratio, cycle time, and slug size) as well. Compared to waterflooding, fluid injectivity is found to be significantly improved by injecting CO2 during the water-alternating-CO2 processes in tight formations. There exists a good agreement between the experimental measurements and simulated results, indicating that the mechanisms governing water-alternating-CO2 processes in tight oil formations have been well incorporated. It is shown from sensitivity analysis that fluid injectivity is strongly dependent on slug size, water-alternating-CO2 ratio, and cycle time.
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