Many deep-water Gulf of Mexico discoveries of the past five years are older Tertiary reservoirs including Atlantis, Tahiti, Neptune, K-2, Thunder Horse, Shenzi, Great White, Trident, St Malo, Jack and Cascade. These middle Miocene to Paleocene reservoirs are characterized by high pressure and temperature, and low natural reservoir drive energy (due to compaction and cementation). In contrast, previous production experience in younger, Pleistocene through upper Miocene, reservoirs exhibit high primary oil recovery due to significant rock compressibility and aquifer influx. The requirement for water injection to supplement reservoir drive energy, improve oil rate, and maintain oil production rates is of primary consideration in development planning for the new, ultra-deep Gulf of Mexico discoveries. Unfortunately, there is limited production experience to use as guidance.

The purpose of this study is to provide a risk-based estimate of the incremental oil from water flooding for these types of reservoirs. A parametric simulation study was performed using experimental design to calculate incremental recovery from water-flooding in ultra-deep Tertiary reservoirs in the Gulf of Mexico. Experimental design matrices were generated for both primary and water flood scenarios, based on the selected uncertainty parameters. Proxy equations for both primary and water flood oil recovery were generated from the simulation results. Statistical Monte-Carlo simulation was run using the proxy equations. By comparing the simulation results for ten year production, water-flooding case yields a recovery factor about 20 per cent higher than no-injection case based on P50 estimate.

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