Two Enhanced Oil Recovery (EOR) methods were analyzed for producing hydrocarbons from a newly discovered JLG field using analogous information from a reservoir of similar geologic characteristics as those in southern part of Trinidad. Continuous CO2 injection and water alternating gas (WAG) were modelled after primary recovery using CMG-GEM. The feasibility of these processes were determined using the overall cumulative production and CO2 storage capacities. Injection time for each EOR strategy was simulated for a ten-year period. The comparisons were done using various hydrocarbon pore volumes (HCPV), injection times, WAG cycles and WAG ratios to analyze the production curves and the amount of sequestered CO2.

The results showed that reservoir had an 18.2% recovery factor (OOIP was 29,750 MSTB) from primary production. From the models developed, immiscible continuous CO2 injection was the most feasible EOR process coupled with sequestered. This model produced the highest incremental oil recovery of 26.3%, which corresponded to a cumulative oil production of 13,286 MSTB (44.66% recovery). A total of 284.11 MMSCF (14992.6 metric tons) of CO2 (16% storage) was also stored. Hence, an immiscible continuous injection process can be more economically feasible since it requires a smaller volume of CO2 and produces a greater volume of hydrocarbons for similar type fields. This is further supported by the feasibility analysis, which showed that the continuous CO2 immiscible injection process would produce a net present value (NPV) of US$ 355M, with an internal rate of return (IRR) of 83.9%.

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