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In this paper, the immiscible water-alternating-CO 2 flooding process at the LH11-1 oilfield, offshore Guangdong Province, was firstly evaluated using full-field reservoir simulation models. Based on a 3D geological model and oil production history, 16 scenarios of water-alternating-CO 2 injection operations with different water alternating gas (WAG) ratios and slug sizes, as well as continuous CO 2 injection (Con-CO 2 ) and primary depletion production (No-CO 2 ) scenarios, have been simulated spanning 20 years. The results represent a significant improvement in oil recovery by CO 2 WAG over both Con-CO 2 and No-CO 2 scenarios. The WAG ratio and slug size of water affect the efficiency of oil recovery and CO 2 injection. The optimum operations are those with WAG ratios lower than 1:2, which have the higher ultimate oil recovery factor of 24%. Although WAG reduced the CO 2 injection volume, the CO 2 storage efficiency is still high, more than 84% of the injected CO 2 was sequestered in the reservoir. Results indicate that the immiscible water-alternating-CO 2 processes can be optimized to improve significantly the performance of pressure maintenance and oil recovery in offshore reef heavy-oil reservoirs significantly. The simulation results suggest that the LH11-1 field is a good candidate site for immiscible CO 2 enhanced oil recovery and storage for the Guangdong carbon capture, utilization and storage (GDCCUS) project.

Simulation of Immiscible Water-Alternating-CO2 Flooding in the Liuhua Oilfield Offshore Guangdong, China