Complex phase behaviours related to gas injection in reservoir fluids

Abstract

Enhanced oil recovery (EOR) involves several techniques, including the injection of gas (such as natural gas, nitrogen, or CO2) into the reservoir to increase its pressure, thereby displacing oil from one or more injection wells to production wells. For this process to be effective, it is essential that the injected gas and the oil reach a homogeneous state. Particularly, the First-Contact Minimum Miscibility Pressure (FC-MMP) offers a reliable (and safe) initial estimate for the pressure at which the EOR process should be conducted. In this work, an efficient algorithm is developed that allows computing complete pressure(P)-alpha diagrams (alpha: percentage of injected gas) at a fixed temperature using traditional cubic equations of state (EoS), including complex cases with three-phase regions. This algorithm is used to study both the qualitative and quantitative behaviour of the P-alpha diagrams and to analyse how FC-MMP changes with the injection of different gases or gas mixtures. Various reservoir fluids from the literature (with and without asphaltenes and with varying levels of CO2 and methane) are evaluated. In one section, three injection gases are used: CO2, N2, and a synthetic natural gas mixture, comparing their effects on the P-alpha diagrams. Then, the impact of interaction parameters on phase equilibrium and FC-MMP is analysed, and the role of asphaltene precipitation is discussed. The study concludes with a quantitative comparison between the FC-MMP calculated here and the Multiple-Contact MMP (MC-MMP) reported for the same fluids. Additionally, the problem of whether asphaltenes precipitation should be considered or ignored in the determination of the FC-MMP is analysed and discussed, with different perspectives for conventional and non-conventional shale type reservoirs.