No abstract

An experimental technique is developed to measure the interfacial tensions of the crude oil + reservoir brine + CO 2 systems at pressures from (0.1 to 31.4) MPa and two temperatures (27 and 58) °C using the axisymmetric drop shape analysis (ADSA) technique for the pendant drop case. The measured dynamic interfacial tension is gradually reduced to an equilibrium value. For both the reservoir brine + CO 2 system and the crude oil + CO 2 system, the equilibrium interfacial tension decreases as the pressure increases, whereas it increases as the temperature increases. For the reservoir brine + CO 2 system, the interfacial tension data are not available at P g 12.238 MPa and 58 °C because the pendant brine drop cannot be formed in the CO 2 phase. However, for the crude oil + CO 2 system, the equilibrium interfacial tension remains almost constant at P g 8.879 MPa and 27 °C or at P g 13.362 MPa and 58 °C. Under the same conditions, nevertheless, the equilibrium interfacial tension of the crude oil + reservoir brine + CO 2 system is reduced in comparison with that of the crude oil + reservoir brine system. The interfacial tension reduction for the crude oil + reservoir brine + CO 2 system is larger at higher pressures.

In this paper, the mass transfer of CO 2 into a reservoir brine sample is studied experimentally at high pressures and elevated temperatures. The equilibrium concentration of CO 2 in the reservoir brine and the density of CO 2 -saturated brine are measured by saturating the brine with CO 2 . The mass-transfer rate of CO 2 into the brine is determined by monitoring the pressure decay inside a closed, visual, high-pressure PVT cell. It is found that the density of the brine with dissolved CO 2 increases linearly with CO 2 concentration. As CO 2 gradually dissolves into the brine by molecular diffusion, a concentration-induced density gradient is generated near the CO 2 -brine interface. Under the influence of gravity, this concentration-induced density gradient causes natural convection, which accelerates the mass-transfer rate of CO 2 into the brine. The modified diffusion equation with an effective diffusivity is applied to model the mass-transfer process. It is found that the determined effective diffusivities of CO 2 in the reservoir brine are almost two orders of magnitude larger than the molecular diffusivities of CO 2 in water or similar reservoir brines. The detailed experimental results show that the density-driven natural convection greatly accelerates the dissolution process of CO 2 in brine. This means that loss of CO 2 in brine can be significant in an enhanced oil recovery operation using CO 2 flooding in an oil reservoir with a bottom water aquifer. More importantly, the accelerated mass transfer due to the density-driven natural convection significantly increases the geological sequestration rate of CO 2 in deep saline formations.

No abstract

No abstract

R e p r o d u c e d with p e r m issio n o f th e co p y r ig h t o w n e r . F u rth er rep ro d u ctio n p roh ib ited w ith o u t p e r m issio n .

No abstract

In this paper, oil recovery and permeability reduction of a tight sandstone reservoir in immiscible and miscible CO2 flooding processes are experimentally studied. First, a series of saturation tests are conducted to determine the onset pressure of asphaltene precipitation from a light crude oil−CO2 system. Second, the vanishing interfacial tension (VIT) technique is applied to determine the minimum miscibility pressure (MMP) between the light crude oil and CO2. Third, a total of nine CO2 coreflood tests under immiscible and miscible conditions are performed through the so-called dry, secondary, and tertiary oil recovery processes, respectively. It is found that the onset pressure of asphaltene precipitation is much lower than the MMP. In the CO2 secondary oil recovery process, the coreflood test data show that, when the injection pressure is between the onset pressure of asphaltene precipitation and the MMP, the oil recovery factor is higher but the oil effective permeability reduction is larger at a higher injection pressure in the immiscible CO2 flooding. They both reach almost constant maximum values in the miscible CO2 flooding (P ≥ MMP). It is also found that, in three different miscible CO2 oil recovery processes, the CO2 tertiary flooding process gives the lowest oil recovery factor but the largest oil effective permeability reduction. This is attributed to the most severe codeposition of asphaltenes and metal carbonates. However, the CO2 dry or secondary flooding process has a significantly higher oil recovery factor but a much smaller oil effective permeability reduction due to asphaltene deposition alone in the former process or codeposition of asphaltenes and metal carbonates in the latter process.