Summary In this paper, techniques have been developed to examine the enhanced swelling effect and viscosity reduction of CO2-saturated heavy oil with the addition of either solvent C3H8 or solvent n-C4H10. Experimentally, pressure/volume/temperature (PVT) tests are conducted to measure the saturation pressure, swelling factor, and viscosity of the C3H8/heavy-oil system, the C3H8/CO2/heavy-oil system, and the n-C4H10/CO2/heavy-oil system, respectively, in the overall temperature range of 280.45 to 391.55 K. It has been found that an increased swelling effect of heavy oil is obtained by adding the gas solvent C3H8 or n-C4H10 into the CO2 stream. An enhanced viscosity reduction of the CO2/heavy-oil system is also achieved in the presence of either C3H8 or n-C4H10. The enhanced swelling effect and viscosity reduction caused by adding either C3H8 or n-C4H10 into the CO2 stream are particularly favorable for achieving a higher heavy-oil recovery compared with pure-CO2 processes. Theoretically, three binary-interaction-parameter (BIP) correlations in the Peng-Robinson (PR) equation of state (EOS) (PR-EOS) method have been proposed for respectively characterizing CO2/heavy-oil binaries, C3H8/heavy-oil binaries, and n-C4H10/heavy-oil binaries by treating each oil sample as a single pseudocomponent with its molecular weight (MW) and specific gravity (SG). The BIP correlations (together with the PR-EOS) can be used to predict the saturation pressures and swelling factors of the C3H8/CO2/heavy-oil system and the n-C4H10/CO2/heavy-oil system with a generally good accuracy.

A generalized methodology has been developed and successfully applied to determine diffusion coefficient of alkane solvent–CO2–heavy oil systems with consideration of swelling effect. Theoretically, a one-dimensional and one-way mass transfer model incorporating the volume translated Peng–Robinson equation of state (PR EOS) has been developed to describe the mass transfer from alkane solvent–CO2 mixture to heavy oil, which accounts for the oil swelling effect resulted from gas dissolution. The heavy oil sample has been characterized as three pseudocomponents, while the binary interaction parameter (BIP) correlations are tuned with the experimentally measured saturation pressures. Both apparent diffusion coefficients for gas mixtures and individual diffusion coefficient of each component of a mixture are determined once the discrepancy between the measured and calculated dynamic swelling factors of heavy oil has been minimized. The volume translated PR EOS with the three characterized pseudocomponents and the tuned BIP correlations is able to accurately predict the phase behavior of alkane solvent–CO2–heavy oil systems. Compared to the apparent diffusion coefficient, better agreements between the measured and calculated dynamic swelling factors have been obtained by use of the individual diffusion coefficients. Addition of C3H8 into CO2 stream is found to not only diffuse faster into heavy oil than CO2 but also contribute to a larger degree of oil swelling, leading to a faster and enhanced swelling effect of C3H8–CO2–heavy oil system in comparison with the CO2–heavy oil system.

Summary Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy-oil reservoirs for pressure maintenance and improving oil recovery. Experimentally, a 3D physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two well configurations have been designed to examine their effects on heavy-oil recovery. The corresponding initial oil saturation, oil-production rate, water cut, oil recovery, and residual-oil-saturation (ROS) distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water/CO2 ratio). The incremental oil recoveries of 12.4 and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governing water-alternating-CO2 processes have been numerically simulated and matched. It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and oil recovery in thin heavy-oil reservoirs. Although well configuration imposes a dominant impact on oil recovery, the water-alternating-gas (WAG) ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios 1 and 2, respectively.

In this paper, techniques have been developed to examine the enhanced swelling effect and viscosity reduction of CO2-saturated heavy oil with addition of rich solvent C3H8. Experimentally, PVT tests are conducted to measure the saturation pressure, swelling factor and viscosity of the C3H8-heavy oil system and C3H8-CO2-heavy oil system, respectively. It has been found that an increased swelling effect of heavy oil is obtained by adding rich solvent C3H8 into CO2 stream. An enhanced viscosity reduction of the CO2-heavy oil system is also achieved in the presence of rich solvents such as C3H8. Theoretically, two binary interaction parameter (BIP) correlations in Peng-Robinson equation of state (PR-EOS) have been proposed for respectively characterizing CO2-heavy oil systems and C3H8-heavy oil systems by treating each oil sample as a single pseudocomponent with its molecular weight and specific gravity. The BIP correlations together with the PR-EOS can be used to predict the saturation pressures and swelling factors of the C3H8-CO2-heavy oil systems with a good accuracy. Also, in comparison to other mixing rules, the Lobe’s mixing rule is found to be more appropriate for quantifying viscosity reduction of the heavy oil with dissolution of CO2 and/or C3H8.

The agglomeration of hydrate particles is one of the main causes of hydrate accumulation or bedding in oil and gas pipelines. The unconverted water droplets in the system play a crucial role in hydrate particle agglomeration. In this study, a novel technique was developed to directly measure the interaction forces between cyclopentane hydrate particles with a water bridge between them using a micromechanical force apparatus. On the basis of the developed method, the interaction forces at different temperatures and water bridge volumes and the effects of mineral oil were experimentally studied. At a low subcooling level of 1.7 °C, the contact areas and adhesion forces between the hydrate particles and water droplets increased with the increase in the water droplet volume. For the case of a higher subcooling level of 6.2 °C, rapid hydrate formation between the bridging water droplets prevented the hydrate particles from being effectively wetted, resulting in a small contact area. There was no clear relationship between the contact area/adhesion force and the water droplet volume. The hydrates formed on the water bridge could dramatically strengthen the adhesion force, while the addition of mineral oil in cyclopentane could retard the water droplets from converting into hydrates, consequently decreasing the adhesion force. The measured adhesion forces between the hydrate particles and water droplets may provide further insight into the hydrate agglomeration process.