Abstract
Injection of a soluble gas like CO2 into an oil reservoir reduces the interfacial tension and oil viscosity and contributes to oil swelling, which together, in turn, enhance the oil mobility and relative permeability. In this work an experimental phase equilibrium setup for the recombination of live oil (stock-tank oil and first-stage separator gas) and measurement of the corresponding phase behaviors of CO2/live oil mixtures is described. In the recombination process, the vapor-to-oil molar ratio was adjusted until the composition of the original reservoir fluid was obtained. The average of the absolute error (AAE) in composition was about 0.77% and 1.09% for the two reservoir fluids under test (named here wells A#22 and A#33, respectively). The optimum vapor-to-oil molar ratio for zero deviation in the methane composition in the live oil (recombined) was about 0.42 for both wells. In addition, the PVTi simulator was used to reproduce the live oil (by combining the first-stage separator gas and the stock-tank oil) and also to predict the recombined oil characteristics at the reservoirs’ saturation pressure and bottom hole temperature. On the other hand, the PVTpro simulator was used to investigate the oil swelling rate and establish the relationship between saturation pressure and the injected CO2 mass fraction. The average of the absolute relative error (AARE) between experimental and predicted saturation pressures was 7.78% for well A#22 and 5.38% for well A#33.
Highlights
Tertiary or enhanced oil recovery processes are associated with the injection of a specific type of fluid or fluids into a reservoir
The experimental setup has been successfully tested in two sets of recombination tests followed by swelling tests for various CO2 mass fractions
The CO2/live oil system was studied at the reservoir bottom hole temperature and at high pressure ranges starting at the reservoir saturation pressures of two United Arab Emirates oil reservoirs (A#22 and A#33)
Summary
Tertiary or enhanced oil recovery processes are associated with the injection of a specific type of fluid or fluids into a reservoir. The fluid injection supplements the natural energy left over in the reservoir and displaces the un-recovered oil. The increased interaction between the injected fluid and the in-place oil results in alterations in rock and fluid properties. Fluid injection and eventual interaction bring about changes like a lowering in interfacial tension, oil swelling, oil viscosity reduction, wettability modification, and sometimes favorable phase behavior conditions. These changes are mainly attributed to physics and chemical interaction between the two fluids and to the fluid injection rate and pressure [1]. The many advantages of CO2 injection over those of water and nitrogen injection are summarized in [2]
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