https://orcid.org/0000-0002-2652-879X
Figures
Abstract
The flow mechanism of CO2 flooding serves as the theoretical foundation for examining the synergic integration of oil recovery and CO2 storage. Immiscible CO2 flooding has attracted considerable research attention due to its simplicity and cost-efficiency. However, minimal studies are available regarding the flow characteristics and EOR mechanism of immiscible CO2 flooding in in-situ temperature-pressure coupling conditions at the pore scale. Therefore, this study employed a modified high-temperature, high-pressure microfluidic system to simulate the in-situ CO2 and water injection processes in a combined temperature-pressure environment and analyze the multiphase flow characteristics in the pores. The injection rate, displacement pressure difference, displacement efficiency, and residual oil distribution were quantitatively analyzed at different pressures. The results indicated higher residual oil clustering after water flooding at the same injection rate. CO2 flooding significantly reduced residual oil clustering and enhanced the oil flooding effect. The multiphase flow dynamics, type of remaining oil in different injection conditions, and flow characteristics of immiscible CO2 flooding were determined. A higher confining pressure interrupted the CO2 flow, which destabilized the displacement front increased the recovery efficiency by 12.9%. Furthermore, a higher injection rate and displacement pressure increased the recovery efficiency by 24.9% and 6.1%, respectively.
Citation: Li T, Wang S, Li J, Dong K, Wen Z (2025) Experimental study of pore-scale flow mechanism of immiscible CO2 flooding under in-situ temperature-pressure coupling conditions. PLoS ONE 20(4): e0321527. https://doi.org/10.1371/journal.pone.0321527
Editor: Khalil Abdelrazek Khalil,, University of Sharjah, UNITED ARAB EMIRATES
Received: August 2, 2024; Accepted: March 7, 2025; Published: April 1, 2025
Copyright: © 2025 Li et al. This is an open access article distributed under the terms of the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original author and source are credited.
Data Availability: All relevant data are within the paper and its Supporting Information files.
Funding: National Key Research and Development Program of China under grant (2022YFE0206700). Authors Li Tingting, Wang Suling, Li Jinbo and Dong Kangxing are key researchers of National Key Research and Development Program of China under grant.
Competing interests: The authors have declared that no competing interests exist.
Introduction
The excessive utilization of energy sources such as oil, coal, and natural gas has increased the global CO2 levels, which has intensified the greenhouse effect [1,2] and led to glacier melting, lower agricultural output, and frequent climate disasters [3]. Therefore, reducing the atmospheric CO2 levels is crucial for alleviating the greenhouse effect. Of the available carbon capture, utilization, and storage (CCUS) technologies, CO2 flooding is considered safe and effective for enhancing oil recovery and reducing CO2 emissions [4,5]. Injecting liquid or supercritical CO2 into reservoir oil fields for crude oil displacement enhances the oil recovery rate and enables CO2 sequestration, offering dual advantages [6–14]. Most CO2 flooding methods used globally for enhancing oil recovery adopt miscible flooding technology. However, this method is less effective in China due to the reservoir depths and heavy components of crude oil. Therefore, near-miscible and non-miscible flooding have gradually been applied in domestic oilfields to increase oil production [15]. Non-miscible flooding has become an attractive alternative for oil recovery due to advantages such as lower required injection pressure, cost-efficiency, and higher operational feasibility [16,17].
Hamza, A. et al. examined the influence of various factors on the efficacy of CO2 displacement and recovery in sandstone and carbonate reservoirs at the nanoscale level, focusing on evaluating pilot CO2 sequestration in the field [18]. They also conducted geological feature studies in an oilfield demonstration area to analyze residual oil distribution and gas migration after CO2 flooding, establishing an optimized evaluation method for CO2 flooding sequestration [19]. Li et al. conducted core-flooding experiments to quantitatively characterize the efficacy of CO2 injection in enhancing oil recovery and sequestration [20]. Since CO2 and crude oil molecule diffusion, the nanopore effect, and adsorption affect CO2 storage and transport during CO2 flooding, it is crucial to consider the influence of the multiphase medium at the pore scale [21]. Therefore, understanding the microscale flow mechanisms of CO2 flooding is essential for developing reservoir scale and field applications. Andrew, M. et al. scanned reservoir environments via X-ray microtomography to quantify the captured residual CO2 after activation and reuse [22]. Abdulla Alhosani et al. introduced in-situ CO2 injection into three-phase miscible flooding to examine the oil recovery mechanism, pore occupancy rate, and interfacial areas [23]. However, when CO2 is continuously injected as a fluid into the reservoir pores, capillary resistance causes it to flow through larger holes, preventing crude oil displacement in smaller and microscopic pores, consequently affecting the oil recovery rate [24–26]. Macroscopic core-flooding experiments and reservoir-scale studies cannot directly visualize the fluid flow in the porous medium. Therefore, experimental microscopic visualization techniques are employed to analyze the fluid flow at the pore scale and the CO2 flooding flow mechanisms [27–30]. This technique describes the near-real dynamic process of oil displacement at the pore scale to analyze its fluid flow mechanism [31]. However, conventional microfluidic devices are generally unable to withstand the harsh conditions in high-temperature and high-pressure reservoirs [32]. Therefore, the temperature and pressure of the experimental system are optimized to ensure appropriate in-situ thermal and pressure conditions [33]. Despite extensive research on fluid flow during CO2 flooding, minimal studies are available regarding the mechanism behind in-situ CO2 flow in microscopic pores in reservoir environments. Therefore, it is essential to investigate the mechanism behind the pore scale flow during immiscible CO2 displacement in an in-situ reservoir environment in combined temperature and pressure conditions. Image J gray scale analysis was performed to assess the CO2 injection rate, displacement pressure difference, and CO2 flooding oil recovery at different confining pressures to quantitatively analyze the influence of these factors on residual oil distribution. This method prevents the errors caused by microflow measurements and facilitates the real-time calculation of multiphase fluid dynamics. The results establish a theoretical foundation for developing enhanced immiscible CO2 flooding oil recovery technology.
Experimental
2.1. Material preparation
Sandstone samples were collected from a coring well in a reservoir in the Yanchang Oilfield. The reservoir temperature in the selected section was 80°C and the formation pressure was 15 MPa. Micrometer CT scanning was used to obtain 3D images of the sandstone (Fig 1), which were imported into Avizo for binarization to extract the pore structure of the core and select a suitable pore structure cut surface (Fig 2). The representative area of the cut surface (Fig 3) was etched out the pore structure on optical glass. Table 1 shows the basic parameters of the glass etching chip (Fig 4).
The experimental simulation oil was prepared using the natural gas composition sourced from the field, the original gas-oil ratio, a CO2 purity of 99.99%, and a crude oil and CO2 MMP of 17.8 MPa. The properties are shown in Table 2.
2.2. Experimental apparatus
Fig 5 shows the high-temperature, high-pressure microscopic visualization experimental system. It mainly comprised three parts: the high-pressure pump circuit system, the visualization observation system, and the high-temperature, high-pressure reaction chamber. The high-pressure pump circuit system consisted of micro-caliber high-pressure pipelines and an ISCO100DX high-pressure piston pump (Fig 6). The piston pump had a capacity of 100 mL, showing a maximum pressure of 68.95 MPa and a pressure accuracy of 0.5% FS. It was capable of precisely maintaining a constant micro-flow rate, pressure, and programming. Simple settings were used to facilitate linear or stepwise system pressure changes. The confining-pressure tracking pump was used to adjust the confining pressure of the glass-etched chip to prevent excessive pressure differences between the interior and exterior, possibly damaging the chip. This pump was also employed to facilitate miscible and immiscible CO2 displacement by regulating the exit pressure of the chip. The Nikon Ti-E series microscopic platform and the microscopic model were used for system visualization. The microscopic platform presented a maximum resolution of 0.83 µm, enabling clear observation of the oil and CO2 flow processes in the glass-etched chip. The high-temperature, high-pressure reaction chamber consisted of a high-pressure reactor (Fig 7) and a temperature control system. To ensure the normal operation of the microscopic visualization window, a maximum working pressure and temperature of 25 MPa and 120°C were used for the experimental high-temperature, high-pressure microscopic visualization system. This satisfied the operational safety and stability requirements of the maximum pressure and temperature conditions of 13 MPa and 80°C in this paper. Fig 8 shows a schematic diagram of the system.
2.3. Experimental procedure
- (1) The glass-etched chip was placed in the microscopic visualization model gripper, vacuum-treated, and heated to 80°C.
- (2) The initial enclosure pressure was set to 8 MPa, after which the chip was saturated with (Fig 9).
- (3) CO2 was injected into the chip at a constant flow rate until no oil was produced at the outlet.
- (4) The multiphase flow process was recorded using a visual observation system. The model was cleaned, and steps 1 to 3 were repeated for oil repelling experiments using different parameters.
- (5) Adobe Photoshop was used to process the images captured during the experiments.
Table 3 shows the experimental protocol for the high-temperature, high-pressure microscopic visualization.
Results and discussion
Microscopic visualization experiments were conducted to analyze the flow characteristics and residual oil distribution of pore-scale multiphase flow in immiscible conditions, varying displacement pressure differences, injection velocities, and confining pressures, consequently elucidating the flow mechanism underlying CO2 displacement in complex pore structures. The four primary objectives of the high-temperature, high-pressure microscopic visualization experiments included the following: (1) The experimental microscopic visualization system was used to obtain the qualitative data of the pore-scale multiphase flow (oil and CO2) characteristics and CO2 recovery efficiency. (2) The ODE of CO2 injection and microscopic CO2-oil mechanism were investigated. (3) Image analysis technology was used to obtain the quantitative micro-data while the factors influencing EOR was evaluated. (4) The influence of the CO2 force action in the pores on the flow characteristics and the EOR mechanism was analyzed.
3.1. Immiscible CO 2 injection experiments
When CO2 entered the crude oil-filled glass-etched chip, both the capillary force in the pore and the injection hydrodynamic force are displacement forces. However, when CO2 flooding occurs, oil is displaced by CO2 in the bellow and moves forward, so capillary force must be overcome. Therefore, capillary force is usually the resistance to CO2 displacement (Fig 10). The upper and lower CO2-oil contact surfaces were exposed to driving and capillary forces and buoyancy. The front contact surface was subjected to driving and capillary forces, while the CO2 was affected by the force within the pore (Fig 11).
The driving force was generated by the pressure difference between the CO2 and crude oil, which was the same as that between the inlet and outlet of the glass-etched chip [34]. The driving force was calculated using Equation 1 as follows:
where denotes the driving force (N),
signifies the non-wetting phase pressure (non-wetting phase is CO2) (MPa),
represents the wetting phase pressure (wetting phase is oil) (MPa),
denotes the CO2 radius (mm), and
is the CO2 thickness (mm).
The pressure discontinuity at the CO2-oil interface caused by surface tension produced a pressure difference in accordance with Young’s Laplace’s law:
where S- is the interface curvature. Due to the circular entry of CO2 into the pore, the interface curvature is;
is defined by the interfacial tension (N/mm).
The final driving force formula was obtained using Equations 1 and 2:
CO2 was subjected to capillary pressure in the pores to generate capillary force, which acted on the CO2 contact surface, and was calculated as:
where denotes the capillary force (N), Lrepresents the arc length of the contact surface between the CO2 and the oil (mm), and θsignifies the contact angle of the CO2-oil in the glass-etched chip (°).
In addition, due to the difference in density between CO2 and crude oil, CO2 will be subjected to buoyancy force, and its own gravity is less than the buoyancy force, so that the CO2-oil interface moves upward, and the direction of buoyancy is always upward. The size of its buoyancy force is calculated as follows:
The microscopic visualization CO2 flooding experiment was conducted at a pressure of 8 MPa, a temperature of 80°C, and an injection speed of 2 ul/min. As shown in Fig 12, the resultant force acting on the upper contact surface of CO2-Oil is greater than that on the lower contact surface. So, the CO2 displayed a more rapid upward move than in other directions, with the formation of a dominant flow channel above the chip after 2 min. Due to the low viscosity of CO2, it flows relatively quickly and preferentially enters larger pore channels with smaller capillary forces, resulting in a fingering phenomenon. The subsequent force on the front CO2-oil contact surface exceeded that on the lower contact surface, resulting in the formation of beneficial flow channels in the central region of the chip after 3.5 min. During the continuous injection of CO2, the driving force continuously overcomes the capillary forces in smaller pore channels. At 6 min, the chip displayed distinct upper, middle, and lower flow channels. Finally, front merging occurred near the exit at 8 min, resulting in a collective breach of the right-side exit, with a recovery rate of 81.5%.
3.1.1. Different injection rates.
The temperature and pressure were 80°C and 8 MPa, and CO2 was injected at the injection speed of 0.5 ul/min. The oil displacement process is shown in Fig 13 (due to lighting problems, the chip presented different colors, but the experimental results were not affected). CO2 progressed in clusters of small bubbles and began to advance towards the macropore channels in the upper, middle, and lower directions as the displacement time increased. The small CO2 bubble clusters were separated when encountering a bifurcated channel. Most of them migrated forward into the macroporous channels. The capillary force in the narrow pore channel presented resistance, requiring the CO2 displacement force to exceed the capillary force to facilitate movement. Smaller CO2 bubbles were trapped in the narrow pores by crude oil, resulting in distinct CO2 flow stratification. Due to insufficient driving, smaller CO2 bubbles can be trapped within narrow pores by the surrounding crude oil. A higher CO2 injection quantity caused gradual CO2 accumulation in the narrow pores, increasing the volume and facilitating steady forward movement. This resulted in multiple oil-CO2-oil and CO2-oil-CO2 displacement phenomena.
At an injection speed of 0.5 ul/min, the residual oil at corners and dead corners in the pores was challenging to utilize and existed as island residual oil (Fig 14). Although the driving increased at an injection rate of 1 ul/min (Fig 15), but it is not enough to overcome the resistance in dead corners and turns. It was insufficient to overcome the capillary force at dead corners and corners, resulting in the crude oil in these areas being unusable (Fig 16).
At an injection rate of 2 ul/min, the CO2 formed large bubbles and flowed continuously in the pores. The subsequent driving was sufficient to overcome the capillary force at dead corners and corners, causing partial, more effective residual oil displacement (Fig 17). This was because the capillary force generated more significant CO2 flow resistance when the CO2 entered the narrow pores during displacement. Therefore, a more substantial driving was necessary to promote unrestricted CO2 flow. This enabled the dispersion of the CO2 bubble clusters in different flow channels and into smaller pore channels, consequently increasing the sweep range and recovery rate. Adobe Photoshop was used to preprocess the final image, while the Image J software was used to analyze the gray values of the image. The residual oil was converted into red pixels, while the pigment points of the oil phase were extracted and calculated (Fig 18). Additionally, the oil pigment area was extracted in conjunction with saturated oil (Fig 19). The recovery efficiency was determined at different injection rates (Fig 20).
3.1.2. Different displacement confining pressures.
The CO2 displacement experiment was conducted at an injection rate of 2 ul/min, a displacement pressure difference of 1 MPa, and a confining pressure of 13 MPa, while the recovery curves were recorded at different time (Fig 21). As shown in Fig 22, a higher confining pressure increased the CO2 pressure in the chip and significant amounts of banded residual oil adhered to both sides of the pore channel, restricting the CO2 flow in the narrow pores, while the small, separated bubble clusters passed through the small pore channels. The high confining pressure acting on the glass chip hindered continuous CO2 flow, causing unstable CO2 displacement front fluctuations. This is because under the action of large confining pressure, due to the extremely low interfacial tension of CO2, it passes through the crude oil in the pore channel, resulting in a flow effect similar to the gas channeling effect. Consequently, the recovery curves displayed displacement fluctuations (Fig 21).
Therefore, the confining pressure can be increased to improve the CO2 density, reduce the influence of buoyancy, expand the CO2 sweep area, and increase the recovery efficiency by 94.4%.
3.1.3. Displacement pressure differences.
The temperature and pressure were 80°C, 8 MPa, the displacement pressure difference was 0.5 MPa, and the CO2 injection rate was 2 ul/min. As shown in Fig 23, the CO2 was mainly concentrated in the large pore channel during crude oil displacement, with only a small quantity entering the small pore channel, resulting in a limited displacement area. Minimal CO2 accumulation and a decline in the flow rate was evident. When the CO2 encountered small pores during the flow process, it separated into smaller volumes and continued to flow forward, subsequently amalgamating again in large pores to propel the oil forward. A lower displacement pressure difference reduced the CO2 flow displacement force. The capillary force impeded CO2 migration in the small pore channel, restricting its entry. Therefore, at a low displacement pressure difference, the oil displacement efficacy of the CO2 entering the large pore channel surpassed that of the small pore channel.
As shown in Fig 24, a displacement pressure difference of 1 MPa significantly increased the CO2 displacement area, accumulation volume, flow velocity, oil displacement efficacy, ability to overcome capillary forces, and the recovery efficiency by 6.1% (Fig 25).
Water injection experiments
The microvisual water flooding and CO2 flooding microfluidic experiments were conducted at a pressure of 13 MPa, a temperature of 80°C, and an injection speed of 2 ul/min. Both capillary and injection hydrodynamic forces are forms of displacement forces. However, since the water viscosity was substantially higher than that of CO2, it was necessary to overcome the viscous force when the water entered the pore channel. This reduced the displacement force of the water relative to CO2, complicating crude oil movement in the pore throat (Fig 26). Therefore, CO2 was more suitable for oil displacement. Most of the residual oil captured after water flooding was present in the pore channel as clusters (Fig 27). Adobe Photoshop was used for final image preprocessing, while the Image J software was used to determine the gray values, as shown in Figs 28 and 29. The residual oil was represented by red pixels, while the remainder was denoted by white pixels. Additionally, the water and CO2 flooding oil recovery rates were calculated (Fig 30).
Conclusion
This study improves the microscopic visualization flow system, enhancing the working temperature and pressure and increasing data recovery recording capacity. The multiphase flow characteristics, oil-CO2 transport, and CO2 displacement efficacy are analyzed via CO2 displacement experiments at different pore scales.
- (1) The equipment used for microscopic flow system visualization is enhanced, while the optimized working temperature and pressure reach 120°C and 25 MPa, respectively. The glass-etched chip is heated and pressurized to experimental conditions using a high-pressure containment kettle and temperature control system.
- (2) The CO2 is affected by buoyancy and capillary force during immiscible CO2 flooding, restricting access to the crude oil in small pores, corners, and dead corners. This results in a cut-off phenomenon, a reduced sweep area, and limited oil recovery.
- (3) The immiscible CO2 flooding experiment reveals differences in the multiphase flow characteristics between CO2 and water flooding. The pore size, injection velocity, displacement pressure difference, and confining pressure affect the multiphase flow process. The complex flow characteristics of these multiphase flows affect residual oil distribution, formation, and sweep area, ultimately revealing the pore-scale CO2 flooding flow mechanism.
- (4) Since the water viscosity far exceeds that of CO2 during water flooding, it is necessary to overcome the viscous force when water enters the pore channel. This reduces displacement force of the water relative to CO2, complicating crude oil movement in the pore throat. Consequently, the recovery rate is 11.5% lower than that of CO2 flooding. A higher CO2 injection speed increases the displacement force, enhancing the capacity to overcome the capillary force. This allows the CO2 to enter smaller pore channels and increases the sweep range, while enhancing the recovery rate by 24.9%. Adequately increasing the displacement pressure difference improves the CO2 flow capacity and oil displacement efficacy, while enhancing the recovery rate by 6.1%. A higher confining pressure causes a significant quantity of banded residual oil to adhere to both sides of the pore channel, resulting in the cut-off flow phenomenon. Therefore, appropriately increasing the confining pressure improves the CO2 density, reduces the influence of buoyancy, expands the CO2 sweep area, and increases the recovery rate by 12.9%.
- (5) This study examines the pore-scale flow mechanism of immiscible CO2 flooding and recommends the reasonable design of parameters for CO2 immiscible injection in Chinese reservoirs to improve oil recovery. It also offers theoretical guidelines for future research on the integration of CO2 storage and utilization.
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