Locating the Remaining Oil in a Re-Saturated Gas Cap Reservoir in a Brown Field – A Case Study of a Niger Delta Reservoir

Abstract Identifying new opportunities in matured fields for further development is a crucial asset management scope that requires data integration, from seismic to production. Estimation of in-place volume has been considered a critical foundation in checking if there is an additional opportunity or not. However, another fundamental factor previously not regarded as crucial is the Pressure-volume-temperature (PVT) relationship at late time pressures. Apart from the study of retrograde condensate fluid behaviour below dew point pressure, more focus should be given to the impact of pressure on gas cap shrinkage in high-shrinkage oil reservoirs. This paper highlights the importance of understanding the latter in identifying new opportunities in matured fields. An integrated petroleum engineering studies was carried out on a B1000 reservoir in X-field. The reservoir is dominantly composed of shoreface sands incised by distributary channels. There are over 30 wells drilled through the pay region, out of which ten wells have logged gas. The original GOC was established by three of the early wells drilled in the reservoir. The reservoir exhibits High-shrinkage oil properties and has an average gas-cap column of 45ftss. Production performance and water-cut performance indicate that the energy mechanism is predominantly aquifer-driven. Using commercial numerical simulator, the reservoir was initialized, history matched and further calibrated with available Open hole and carbon-oxygen (CO) logs. An integrated review of static and dynamic well data indicated that after 47 years of production, the gas cap was observed to shrink by more than 10ft. This was corroborated by the dynamic modelling and simulation results, which indicated a shrinkage of the gas-cap at current estimated reservoir pressure. New wells drilled at the crest of the structure to target gas for gas cap blowdown were observed to log a shallower GOC than the initial GOC. This was also corroborated by well test results on a completed gas-cap blowdown well. The well was recently completed across the original gas column. Fluid sample taken from the well during well test indicated a light brown colour, oil sample with API gravity of 40.8. The integrated studies conducted on the reservoir included seismic interpretation, field structural framework modelling, detailed environment of deposition (EOD), Facies modelling, cluster analysis, high-resolution gridding, and static modelling, well and reservoir reviews, PVT modelling, material balance analysis, dynamic modelling, and simulation with cloud-based and parallel computing, which led to the identification of further field development opportunity. This opportunity will add incremental oil of 2.0 MMstb in addition to ca 1.5 MMstb potential recovery from the gas-cap well, which now produces ca. 900bopd and 1.4 MMscf/d of gas. The importance of understanding the impact of very strong water-drive on GOC movement in non-segregated gas-cap drive for high-shrinkage oil reservoirs has been demonstrated in this work.