A simulation case study is described which illustrates the application of polymer flooding to an offshore heavy-oil reservoir within the Niger Delta. This shallow depth offshore reservoir has excellent reservoir quality (up to 39% porosity and 6D in good sands). It has 3 different panels, laminations in sand sequences and contains biodegraded fluid of varying fluid viscosities (2 to 16cp under reservoir conditions). Bubble point is close to reservoir pressure necessitating injection form start of field life to maintain reservoir pressure.

The paper begins by a brief discussion of the mechanics of polymer flooding and its simulation methodology: the effect of water salinity, choke shear degradation and thermal degradation on injectant mixture viscosity is determined from detailed Laboratory studies. Other simulation input parameters like permeability reduction related to adsorption and residual resistance factor are also estimated per facies. All data are implemented as lookup tables in the Polymer option of an available commercial simulator. High injectivity potential (unconsolidated sand dilatance regime) is simulated to ensure that as much polymer as required was injected in High BHP regime without fracturing the reservoir cap rock.

Several full field scale sensitivities were run in an experimental design approach in an effort to optimize the injection strategy and flood pattern for both a water injection case and then the polymer flood case. All producers and injectors are either horizontal wells or deviated wells. The polymer flood effect is recognized and analysed: Best case incremental oil recovery was 7% with earlier polymer injection allowing for greatest incremental recovery. Significant Plateau extension and delayed water breakthrough were noted.

The results show that polymer flooding is economically justified for this field. This paper also discusses how adequate pre-project preparation and pilot-testing brings added value during the life-cycle of Heavy-Oil fields

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