An evaluation on mechanisms of miscibility development in acid gas injection for volatile oil reservoirs

Abstract

Produced gas containing the acid gas reinjection is one of the effective enhanced oil recovery methods, not only saving costs of disposing acid gases and zero discharge of greenhouse gases but also supporting reservoir pressure. The subsurface fluid from the Carboniferous carbonate reservoir in the southern margin of the Pre-Caspian basin in Central Asia has low density, low viscosity, high concentrations of H2S (15%) and CO2 (4%), high solution gas/oil ratio. The reservoir is lack of fresh water because of being far away onshore. Pilot test has already been implemented for the acid gas reinjection. Firstly, in our work a scheme of crude oil composition grouping with 15 compositions was presented on the basis of bottomhole sampling from DSTs of four wells. After matching PVT physical experiments including viscosity, density and gas/oil ratio and pressure–temperature (P–T) phase diagram by tuning critical properties of highly uncertain heavy components, the compositional model with phase behavior was built under meeting accuracy of phase fitting, which was used to evaluate mechanism of miscibility development in the acid gas injection process. Then using a cell-to-cell simulation method, vaporizing and/or condensing gas drive mechanisms were investigated for mixtures consisting of various proportions of CH4, CO2 and H2S in the gas injection process. Moreover, effects of gas compositions on miscible mechanisms have also been determined. With the aid of pressure-composition diagrams and pseudoternary diagrams generated from the Equation of State (EoS), pressures of First Contact Miscibility (FCM) and Multiple Contact Miscibility (MCM) for various gases mixing with the reservoir oil sample under reservoir temperature were calculated. Simulation results show that pressures of FCM are higher than those of MCM, and CO2 and H2S are able to reduce the miscible pressure. At the same time, H2S is stronger. As the CH4 content increases, both pressures of FCM and MCM are higher. But incremental values of MCM decrease. In addition, calculated envelopes of pseudoternary diagrams for mixtures of CH4, CO2 and H2S gases of varying composition with acid gas injection have features of bell shape, hourglass shape and triangle shape, which can be used to identify vaporizing and/or condensing gas drives. Finally, comparison of the real produced gas and the one deprived of its C3+ was performed to determine types of miscibility and calculate pressures of FCM and MCM. This study provides a theoretical guideline for selection of injection gas to improve miscibility and oil recovery.

Experimental and modeling studies of density and viscosity behavior of a live fluid due to CO2injection at reservoir condition

“…The addition of CO 2 to the RLO has been found to reduce the viscosity of the resulting mixture. This effect is well known and followed the trend observed in other systems involving hydrocarbons and gases [46,[68][69]. In these experiments, the effects of temperature, pressure, and CO 2 addition on the viscosity were evaluated.…”

“…The design and development of these processes require detailed knowledge of thermodynamic and transport properties of reservoir fluids. For instance, for reservoir simulation, it is essential to predict the viscosity of each phase as a function of temperature and pressure to model the fluid flow [1][2][3][4][5][6][7]. Oil recovery is predominantly influenced by the capillary number, which characterizes the ratio of viscous forces to surface or interfacial tension forces [8,9].…”

The effect of impurity on miscible CO2displacement mechanism

“…From the thermodynamics view, the pseudoternary diagram has the advantage of capturing the essence of miscible development. Consequently, the vaporizing and condensing gas drive processes represented in pseudoternary diagrams are simulated using a cell-to-cell method (Luo et al, 2019b). Figure 14 shows simulated pseudoternary diagrams for pure CO 2 displacing the Kash oil at the reservoir temperature of 109°C.…”

Hydrogen sulphide

“…Economically, disposing of both together saves costs compared with storing them individually. They can be both used in enhanced oil recovery (EOR) operations and their injection could be used to maintain reservoir pressures [77]. Additionally, and perhaps significantly, research has shown that the EOR injection of the acid gas mixture has a delayed breakthrough at the producing well compared to a CO₂ EOR injection alone [78].…”