Search Results (8)

Cyclic Solvent Injection (CSI), one of the most promising solvent-based enhanced oil recovery (EOR) methods, has attracted the oil industry’s interest due to its energy efficiency, produced oil quality, and environmental suitability. Previous studies revealed that foamy oil flow is considered as one of the main mechanisms of the CSI process. However, due to the presence of complex high-permeable channels known as wormholes in Post-Cold Heavy Oil Production with Sands (Post-CHOPS) reservoirs, understanding the effect of each operational parameter on the performance of the CSI process in these reservoirs requires a pore-scale investigation of different wormhole configurations. Therefore, in this project, a comprehensive microfluidic experimental investigation into the effect of symmetrical and asymmetrical wormholes during the CSI process has been conducted. A total of 11 tests were designed, considering four different microfluidic systems with various wormhole configurations. Various operational parameters, including solvent type, pressure depletion rate, and the number of cycles, were considered to assess their effects on foamy oil behavior in post-CHOPS reservoirs in the presence of wormholes. The finding revealed that the wormhole configuration plays a crucial role in controlling the oil production behavior. While the presence of the wormhole in a symmetrical design could positively improve oil production, it would restrict oil production in an asymmetrical design. To address this challenge, we used the solvent mixture containing 30% propane that outperformed CO₂, overcame the impact of the asymmetrical wormhole, and increased the total recovery factor by 14% under a 12 kPa/min pressure depletion rate compared to utilizing pure CO₂. Moreover, the results showed that applying a lower pressure depletion rate at 4 kPa/min could recover a slightly higher amount of oil, approximately 2%, during the first cycle compared to tests conducted under higher pressure depletion rates. However, in later cycles, a higher pressure depletion rate at 12 kPa/min significantly improved foamy oil flow quality and, subsequently, heavy oil recovery. The interesting finding, as observed, is the gap difference between the total recovery factor at the end of the cycle and the recovery factor after the first cycle, which increases noticeably with higher pressure depletion rate, increasing from 9.5% under 4 kPa/min to 16% under 12 kPa/min. Full article

The thermal development in heavy oil reservoirs with edge and bottom water is poor, while gas huff-n-puff development shows a high recovery and strong adaptability. The formation of foamy oil during gas huff-n-puff is one of the reasons for the high recovery. In order to determine the factors affecting the foamy oil flow during gas huff-n-puff, experiments using a one-dimensional sandpack were conducted. The influences of drawdown pressure and cycle number were analyzed. The formation conditions of foamy oil were preliminarily clarified, and the enhanced oil recovery (EOR) mechanism of foamy oil was revealed. The experimental results show that the drawdown pressure and cycle number are two important factors affecting the formation of foamy oil. Foamy oil flow is prone to forming under a moderate drawdown pressure of 0.5–0.75 MPa, and being too small or too large is unfavorable. Foamy oil is more likely to form in the first two cycles, and it becomes increasingly challenging with the increase in the cycle number. These two factors reflect two necessary conditions for the formation of foamy oil during gas huff-n-puff: one is allowing the oil and gas to flow adequately to provide the shear and mixing for the generation of micro-bubbles, and the other is that the oil content should not be too small to avoid the inability to disperse and stabilize bubbles. The formation of foamy oil, on the one hand, increases the volume of the oil phase, and on the other hand, it reduces the mobility of the gas phase and slows down the pressure decline rate in the core, thereby enhancing the driving force for oil displacement. So, under the influence of the foamy oil, the gas production volume in a cycle declined by about 26%, and the average oil recovery increased by 4.5–6.9%. Full article

This study systematically investigates the formation mechanism and development characteristics of the “foamy oil” phenomenon during pressure depletion development of high-viscosity crude oil through a combination of physical experiments and numerical simulations. Using Venezuelan foamy oil as the research subject, an innovative heterogeneous pore-etched glass model was constructed to simulate the pressure depletion process, revealing for the first time that bubble growth predominantly occurs during the migration stage. Experimental results demonstrate that heavy components significantly delay degassing by stabilizing gas–liquid interfaces, while the continuous gas–liquid diffusion effect explains the unique development characteristics of foamy oil—high oil recovery and delayed phase transition—from a microscopic perspective. A multi-scale coupling analysis method was established: molecular-scale simulations were employed to model component diffusion behavior. By improving the traditional Volume of Fluid (VOF) method and introducing diffusion coefficients, a synergistic model integrating a single momentum equation and fluid volume fraction was developed to quantitatively characterize the dynamic evolution of bubbles. Simulation results indicate significant differences in dominant controlling factors: oil phase viscosity has the greatest influence (accounting for ~50%), followed by gas component content (~35%), and interfacial tension the least (~15%). Based on multi-factor coupling analysis, an empirical formula for bubble growth incorporating diffusion coefficients was proposed, elucidating the intrinsic mechanism by which heavy components induce unique development effects through interfacial stabilization, viscous inhibition, and dynamic diffusion. This research breaks through the limitations of traditional production dynamic analysis, establishing a theoretical model for foamy oil development from the perspective of molecular-phase behavior combined with flow characteristics. It not only provides a rational explanation for the “high oil production, low gas production” phenomenon but also offers theoretical support for optimizing extraction processes (e.g., gas component regulation, viscosity control) through quantified parameter weightings. The findings hold significant scientific value for advancing heavy oil recovery theory and guiding efficient foamy oil development. Future work will extend to studying multiphase flow coupling mechanisms in porous media, laying a theoretical foundation for intelligent control technology development. Full article

This study examines the microfluidic characterization of foamy oil flow dynamics in heterogeneous porous media. A total of 12 microfluidic CSI experiments were conducted using reservoir-on-the-chip platforms. In addition, detailed PVT analysis was performed to characterise the heavy oil/solvent systems. Moreover, a numerical model constructed with CMG software package (2021.10) has been validated against the experimental findings in this study. A clear-cut visualization study provided by microfluidic systems revealed that factors including solvent type, pressure depletion rate, and reservoir parameters have a significant impact on foamy oil flow extension. It was found that a solvent containing a higher CO₂ content demonstrated more effective performance compared with other solvent compositions, owing to its capability to reduce viscosity, enhance swelling, and offer more gas molecules due to its superior solubility. Additionally, a high pressure-depletion rate amplifies the driving force for bubble nucleation, as well as reducing the amount of time available for bubble coalescence. In addition, lower reservoir porosity impedes bubble movement and delays coalescence, thus extending the foamy oil flow. Furthermore, with the aid of a robust image analysis technique, it was discovered that utilizing 100% CO₂ as a solvent resulted in a 17% increase in oil recovery over using 50% CO₂ and 50% CH₄. Furthermore, a 6% increase in oil recovery was achieved by applying a fast pressure depletion rate as opposed to a slow pressure depletion rate. Moreover, the numerical model constructed was found to be accurate in adjusting heavy oil recovery with an average relative error of 7.7%. Full article

In this paper, experimental and numerical studies were conducted to differentiate solvent exsolution and liberation processes from different heavy oil–solvent systems in bulk phases and porous media. Experimentally, two series of constant-composition-expansion (CCE) tests in a PVT cell and differential fluid production (DFP) tests in a sandpacked model were performed and compared in the heavy oil–CO₂, heavy oil–CH₄, and heavy oil–C₃H₈ systems. The experimental results showed that the solvent exsolution from each heavy oil–solvent system in the porous media occurred at a higher pressure. The measured bubble-nucleation pressures (P_n) of the heavy oil–CO₂ system, heavy oil–CH₄ system, and heavy oil–C₃H₈ system in the porous media were 0.24 MPa, 0.90 MPa, and 0.02 MPa higher than those in the bulk phases, respectively. In addition, the nucleation of CH₄ bubbles was found to be more instantaneous than that of CO₂ or C₃H₈ bubbles. Numerically, a robust kinetic reaction model in the commercial CMG-STARS module was utilized to simulate the gas exsolution and liberation processes of the CCE and DFP tests. The respective reaction frequency factors for gas exsolution (rff_e) and liberation (rff_l) were obtained in the numerical simulations. Higher values of rff_e were found for the tests in the porous media in comparison with those in the bulk phases, suggesting that the presence of the porous media facilitated the gas exsolution. The magnitudes of rff_e for the three different heavy oil–solvent systems followed the order of CO₂ > CH₄ > C₃H₈ in the bulk phases and CH₄ > CO₂ > C₃H₈ in the porous media. Hence, CO₂ was exsolved from the heavy oil most readily in the bulk phases, whereas CH₄ was exsolved from the heavy oil most easily in the porous media. Among the three solvents, CH₄ was also found most difficult to be liberated from the heavy oil in the DFP test with the lowest rff_l of 0.00019 min⁻¹. This study indicates that foamy-oil evolution processes in the heavy oil reservoirs are rather different from those observed from the bulk-phase tests, such as the PVT tests. Full article

Thermal recovery technology is generally suitable for shallow lays due to the higher thermal loss for the deep heavy-oil reservoirs. Non-thermal recovery technologies, such as the non-condensate gas injection technology, are not limited by the reservoir depth and could be extensively applied for the heavy-oil reservoir. Many experimental studies and field applications of non-condensate gas injection have been conducted in heavy-oil reservoirs. The injected non-condensate gas could achieve dynamic miscibility with heavy oil through multiple contacts, which has a significant viscosity-reduction effect under the reservoir conditions. In addition, the equipment involved in the gas injection operation is simple. There are many kinds of non-condensate gases, and common types of gases include N₂ and CO₂ due to abundant gas sources and lower prices. Moreover, CO₂ is a greenhouse gas and the injection of CO₂ into the reservoir would have environmental benefits. The non-thermodynamic method is to inject N₂ and CO₂ separately to produce heavy oil based on the mechanism of the volume expansion of crude oil to form elastic flooding and reduce crude oil viscosity and foamy oil flow. Steam injection recovery of the thermodynamics method has the disadvantages of large wellbore heat loss and inter-well steam channeling. The addition of N₂, CO₂, and other non-condensate gases to the steam could greatly improve the thermophysical properties of the injected fluid, and lead to higher expansion performance. After being injected into the reservoir, the viscosity of heavy oil could be effectively reduced, the seepage characteristics of heavy oil would be improved, and the reservoir development effect could be improved. Non-condensate gas injection stimulation technology can not only effectively improve oil recovery, but also help to achieve carbon neutrality, which has a very broad application prospect in the future oil recovery, energy utilization, environmental improvement, and other aspects. Full article

In this paper, gas pressure cycling (GPC) and solvent-assisted gas pressure cycling (SA-GPC) were developed as two new and effective enhanced oil recovery (EOR) processes. Eight coreflood tests were conducted by using a 2-D rectangular sandpacked physical model with a one or two-well configuration. More specifically, two cyclic solvent injection (CSI), three GPC, and three SA-GPC tests were conducted after the primary production, whose pressure was declined in steps from P_i = 3.0 MPa to P_f = 0.2 MPa. It was found that the CSI tests had poor performances because of the known CSI technical shortcomings and an additional technical issue of solvent trapping found in this study. Quick heavy oil viscosity regainment resulted in the solvent-trapping zone. In contrast, C₃H₈-GPC test at a pressure depletion step size of ∆P_EOR = 0.5 MPa and C₃H₈-SA-CO₂-GPC test at ∆P_EOR = 1.0 MPa had the highest total heavy oil recovery factors (RFs) of 41.9% and 36.6% of the original oil-in-place (OOIP) among the two respective series of GPC and SA-GPC tests. The better performances of these two tests than C₃H₈- or CO₂-CSI test were attributed to the effective displacement of the foamy oil toward the producer in the two-well configuration. Thus the back-and-forth movements of the foamy oil in CSI test in the one-well configuration were eliminated in these GPC and SA-GPC tests. Furthermore, C₃H₈-GPC test outperformed C₃H₈-SA-CO₂-GPC test in terms of the heavy oil RF and cumulative gas-oil ratio (cGOR) because of the formation of stronger foamy-oil flow and the absence of CO₂, which reduced the solubility of C₃H₈ in the heavy oil in the latter test. In summary, different solvent-based EOR processes were ranked based on the heavy oil RFs as follows: C₃H₈-GPC > C₃H₈-SA-CO₂-GPC > CO₂-GPC > C₃H₈-CSI > CO₂-CSI. Full article

The flow characteristics of dissolved gas driven processes in some heavy oil reservoirs, such as low gas–oil ratio and higher oil recovery rate than expected, are quite different from conventional oil production processes. Foamy oil is considered one of the main reasons behind such a production phenomenon. In this paper, the factors affecting the performance of foamy oil recovery were experimentally investigated in a sandpack medium with the assistance of computed tomography (CT) technology to help further the understanding of the mechanism. Five different experiments were applied and the results showed that (1) the linear pressure drop production model had a similar oil recovery to that of the step-down mode; (2) increasing the depletion rate could be more favorable to the oil recovery rate; (3) under a constant gas–oil ratio, raising the temperature had little impact on oil recovery, but showed obvious impact on the production curve; and (4) with higher permeability, there were more residual oil at the end of the displacement process. Lastly, a dry gas huff and puff experiment was conducted and the decreased oil saturation was observed in the inlet section, while no obvious effect was remarked in the outlet region of the medium. Full article