Characterizing the Retrograde Behaviour of Gas Condensate in Selected Niger Delta Reservoirs

Abstract Gas condensate reservoir fluid has a very complex hydrocarbon phase behaviour. In this study, retrograde gas condensate fluid in Niger Delta reservoirs was re-characterized. This was done through generation and re-definition of fluid properties for different gas condensate reservoir. To reduce the uncertainties and issues associated with recovery predictions, reserve estimation and multiphase flow, gas condensate were re-characterized into five different categories: near-critical, rich, mid-rich, lean and extremely lean condensates, with their respective phase diagrams. 250 reservoir samples were taken from over 120 fields in the Niger Delta region. Samples were all validated and restored to their respective reservoir conditions for a minimum of 24 hours with constant agitation so as to achieve homogeneity prior to the experiment. The experiments involved in the re-characterization include direct flash, gravimetric density, constant compositional expansion, and compositional analysis. Findings from experiments revealed that the gas-oil ratio (GOR) of a gas condensate ranges from 4780 to 401,490 SCF/STB, API gravity: 36–54 oAPI, reservoir density: 0.5170-0.1702 g/cm3, liquid dropout: 0.21–51.09, C7+ mol% <12.5, and stock-tank liquid density: 0.7604-0.8571. Findings from this research show that some fluid properties in the Niger Delta region exhibit significant deviations from values established by other researchers. Investigations also revealed that near-critical condensates are rare, while mid-gas condensates are predominant in the Niger Delta region. The re-characterization of gas condensate fluids in the Niger Delta region presents numerous advantages, such as enhanced understanding of gas condensate fluid behaviour, optimized reserve estimation, maximized economic recovery, improved facility design and field management.