The acquisition and interpretation of cased hole saturation logs is crucial to the effective execution of field development plans and maintaining a top notch well and reservoir management. However cased hole saturation logs in mature field developments characterized by low salinity formation water, saturated hydrocarbon liquids and gas condensates can unfortunately be beset with significant levels of non-uniqueness making it quite difficult to evaluate fluid types and establish clear fluid contacts. In such situations, real-time fluid sampling becomes the only way to properly delineate fluid phases. This paper showcases field experiences in the F7800 reservoir of the mature Oben field development and the structured approach applied in resolving such non-uniqueness in the planning and positioning of crestal oil producers.
Though the F7800 was initially undersaturated, well performances of the most crestal producer (well shut-in due to high GOR) and very sparse historical reservoir pressure data indicated the presence of a secondary gas cap due to pressure depletion way below the bubble point. As the downdip wells began to water out from aquifer influx, there arose a need to explore updip development opportunities. In the first identified opportunity, existing cased hole saturation logs acquired in an offset well indicated gas at the same level of the planned new development target interval. This interpretation threatened to erase the opportunity for further oil development.
In another structurally higher development opportunity, a time-lapse C-O log (taken three years apart) in the same well indicated fluid depletion down to residual oil saturation despite the fact that the perforation had been squeezed off for close to 20 years. Besides the interval was the most crestal in the structure and other downdip wells were producing dry oil. In both cases, the cased hole saturation log was at variance with the well established reservoir structure and the performance of development wells and inferred significantly less reserves. Consequently, reservoir pressures and fluid sampling/analyses were necessary to establish fluid types and contacts. The result was a 45ft upwards shift in the previously estimated fluid contact which allowed the placement of two updip development wells with a total net oil production in excess of 1500 bopd from the two updip developments. This paper will highlight the application of real-time fluid sampling technologies by a Niger Delta Operator to safeguard overall project value.