The ‘JEB’ oilfield has been in operation since 1992 with 24 oil producing Wells, 8 water injection Wells and no gas injection. From inception, the field was producing at the rate of 27 MSTB/D. The gas produced was 34,333.7 SCF/D which was being flared but later supplied to the Nigeria Liquefied Natural Gas (NLNG) for export. The field had very weak aquifer support and therefore had been water-flooded from early days of its production. With high water cut, it was necessary to find ways of reducing water production and increasing oil production. The study involved field data gathering, history matching of the field data and prediction of future production. Production rates from the different production schemes were simulated for fourteen years. The cumulative oil production of gas injection, water alternating gas (WAG) injection and gas alternating water (GAW) injection schemes were 4.28 MMMSTB, 3.29 MMMSTB and 3.15 MMMSTB respectively representing an incremental recovery of 38%, 6%, and 1%. The cumulative water production of gas injection, WAG injection and GAW injection were 2.65 MMMSTB, 6.52 MMMSTB and 6.90 MMMSTB respectively, which represent 64%, 10% and 5% reduction in produced water. The economic analysis showed gas injection as the best alternative injection scheme for the field with internal rate of return (IRR) of 19.26 %, while the IRR of WAG and GAW injection schemes were 12.09 % and 11.22 % respectively. Also, at 15% discount rate, the gas injection scheme had the best result with a Profitability Index (PI) greater than 1, a positive Net Present Value (NPV) while all other injection schemes had negative NPV and PI was less than one. The possibility of changing a field from water injection to gas injection has been explored, hence, before embarking on any enhanced oil recovery scheme, other alternatives should be evaluated.

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