Research on the Phase Behavior of Multi-Component Thermal-Fluid-Heavy Oil Systems

Abstract

Multi-component thermal luid technology optimizes development effects and has a strong adaptability, providing a new choice for the efficient development of heavy oil reservoirs. However, due to the significant differences between the phase behavior of multi-component thermal-fluid-heavy oil systems and conventional systems, and the lack of targeted and large-scale research, key issues such as the phase behavior of these systems are unclear. This research studies the phase behavior and influencing factors of emulsions and foamy oil in a multi-component thermal-fluid-heavy oil system through high-temperature and high-pressure PVT experiments, revealing the characteristics of the system’s special phase behavior. In the heavy oil emulsion system, the water content directly affects changes in the system’s phase state. The higher the temperature, the larger the phase transition point, and the two are positively correlated. As the stirring speed increases, the phase transition point first increases and then decreases. The amount of dissolved gas is negatively correlated with the size of the phase transition point, and dissolution can form foamy oil. In the heavy oil–foamy oil system, the dissolution capacity of CO₂ is greater than that of multi-component gases, which is greater than that of N₂. A high water content and high temperature are not conducive to the dissolution of multi-component gases. While an increase in stirring speed is beneficial for the dissolution of gases, there are limitations to its enhancement ability. Therefore, the development of multi-component thermal fluids should avoid the phase transition point of emulsions and promote the dissolution of multi-component gases.

1. Introduction

Improving oil recovery is a key focus of the petroleum industry. For heavy oil, the phase behavior of multi-component thermal fluids with crude oil systems is not merely a simple three-phase behavior of oil, gas, and water, but rather exhibits a strong self-emulsifying tendency, capable of forming stable emulsions and foamy oil. Although both laboratory and field observations can detect pseudo-single-phase emulsion and foamy oil systems with multi-component thermal fluids with crude oil, research on their formation mechanisms, stability, and influencing factors is still qualitative. There is an urgent need to conduct research on the phase behavior of multi-component thermal fluids with crude oil systems under high-temperature and high-pressure conditions to reveal the formation mechanisms of special phase systems.

In the development process of the multiphase flow of heavy oil, different development methods have significant impacts on phase changes. In water–oil systems, the interaction between water molecules and oil molecules promotes the emulsification of oil, forming a stable emulsion. In gas–oil systems, under certain conditions, gas molecules can dissolve in oil, leading to the formation of foamy oil. The existence of these special phases is a key factor in studying the phase behavior characteristics and control factors of multiphase thermal fluids and heavy oil systems [1,2,3].

Moreover, some researchers have conducted extensive research on the changes in emulsion and dissolution needed to form emulsions and foamy oil, and phase behavior under different conditions. Lu et al. (2022) observed the process of forming foamy oil through gas injection micro-visual experiments, measured the bubble point pressure of crude oil, and studied the seepage characteristics and foamy oil displacement law of gas dissolution forming foamy oil [4]. Wang et al. (2023) studied the impact and mechanism of water content, crude oil composition, and other factors on emulsification through indoor experiments combined with molecular simulations of MS [5]. Chen et al. (2023) used a microfluidic test system and a laser particle size analyzer to study the micro properties of an emulsion system after reaching phase equilibrium [6]. Huang et al. (2023) studied the impact of shear rate, dispersed phase volume fraction, continuous phase viscosity, and droplet size on the rheological properties of heavy oil water-in-oil emulsions through single-factor experiments [7]. Sheng et al. (2023) studied the impacts of pressure and the decompression rate of dissolved CO₂ on foam characteristics through decompression experiments, comprehensively considering the solubility of CO₂ and the characteristics of the oil–water interface [8]. The stability of the foam decreased with an increase in pressure, first increased and then decreased with an increase in the decompression rate, and the interfacial elasticity had a greater impact on stability than viscosity. Di et al. (2023) combined fracture low-permeability core oil displacement experiments and micro-oil displacement experiments to study the impacts of different factors on the oil displacement effect of CO₂ foam [9].

Overall, the current research discussion on heavy oil emulsion systems largely relies on the assistance of chemical solvents, while there is a relative lack of systematic analyses on the emulsification phase changes in heavy oil under the influence of water and other physical actions. For heavy oil–foamy oil systems, researchers mainly focus on its role and changes during the displacement process, while research on its contribution to viscosity reduction and efficiency enhancement in heavy oil is relatively insufficient. Moreover, further studies based on emulsion systems of foamy oil are even rarer. Therefore, building upon the existing research outcomes from oil–water and oil–gas systems, an in-depth study was conducted on the phase behavior of emulsions and foamy oil generated from heavy oil under the action of multi-component thermal fluids. A comprehensive analysis of the impacts of various factors on their phase behavior was performed.

2. Experimental Section

2.1. Experimental Apparatus

The conventional PVT (Pressure–Volume–Temperature) testing system was upgraded and transformed. A high-temperature sealing structure based on metal sealing was designed, using the elasticity of metal to achieve high-temperature sealing, thereby increasing the upper limit of the PVT testing temperature from 150 °C to 250 °C. This fully meets the phase behavior research needs of multi-component thermal fluid technology, as shown in Figure 1.

We designed a concentric magnetic coupling rotor to address the interference between high-pressure sealing and axial rotation. It can direct measurements of viscosity within the PVT cell within a range from 1 to 100,000 mPa·s. Additionally, an elastic impeller was developed to reduce the PVT cell’s dead volume to 0.5 mL.

This design overcomes the challenges of high-pressure operations and rotational movements, allowing for precise viscosity measurements across a wide range. The use of an elastic impeller minimizes the dead volume in the PVT cell, enhancing the accuracy and efficiency of PVT analysis, which is particularly beneficial for studying multi-component thermal fluid systems (Figure 2).

Moreover, a high-definition CCD camera was utilized to conduct real-time observations of special phase states, such as emulsions and foamy oil, that formed in the multi-component thermal-fluid-heavy oil system.

2.2. Experimental Materials

We selected the heavy oil samples from the X block of the Xinjiang oilfield for the experiment, with typical viscosities chosen for ordinary heavy oil, extra-heavy oil, and ultra-heavy oil, respectively.

The test method was employed to experimentally measure the components of the three types of heavy oil [10], as shown in Table 1.

2.3. Experimental Steps

The experimental process is shown in Figure 3. The experimental process was as follows:

• (1). The equipment was connected according to the standard experimental procedures and the system was checked for airtightness and safety to prevent any leakage.

• (2). After treatment, the heavy oil was injected, which was viscosity-reduced in a temperature-controlled chamber, into the PVT experimental apparatus.

• (3). At the predetermined experimental temperature, the required amount of hot water and the dissolved gas–oil ratio were injected into the PVT experimental apparatus, as per the experimental requirements.

• (4). The built-in concentric magnetic coupling rotor of the PVT was utilized to mix the fluids, thereby accelerating the experimental process.

• (5). Data such as viscosity and saturation pressure were recorded and corresponding calculations and processing were carried out based on the data and images returned by the PVT experimental equipment once the mixture achieved a pseudo-single-phase fluid state.

3. Results and Discussion

3.1. Emulsion Formation Patterns

In the development of multi-component thermal-fluid-heavy oil systems, the high viscosity of heavy oil is attributed to its inherently high contents of resins and asphaltenes. During the production of heavy oil, the natural surfactants present within the oil tend to form water-in-oil (W/O) emulsions when they come into contact with water. This phenomenon significantly increases the viscosity of water-containing heavy oil [11,12]. On the one hand, this enhances the difficulty of the extraction process. On the other hand, it also leads to an increase in extraction costs and energy consumption. Therefore, it is essential to study the emulsification transition point of heavy oil to evaluate its emulsification behavior and analyze the impact of multi-component gases in the thermal fluid on the viscosity of the emulsion.

3.1.1. Water Content

Under conditions of a constant pressure at 5 MPa and a stirring speed of 300 r/min, the relationship between viscosity and water content at three different temperatures was measured. This study investigates the formation of emulsions at various water contents and their corresponding phase transition points.

When the water content in the emulsion is relatively low, water exists as the dispersed phase and oil as the continuous phase [13]. With large intervals between water molecules, there are fewer opportunities for friction and collision between particles, resulting in minimal interaction. The viscosity of the crude oil gradually increases with an increase in water content, forming a water-in-oil (W/O) type emulsion [14]. It can be seen from Figure 4 that, when the water content increases to a certain extent at a temperature of 40 °C, and when the water content is raised from 40% to 50%, the number of water droplets in the oil phase increases sharply. The increased collision and relative sliding between droplets, combined with the action of interphase surface energy, lead to a sudden rise in viscosity, with the viscosity at a 50% water content increasing by 61.50% compared to that at a 40% water content. When the water content reaches a critical value, the W/O emulsion reaches its limit, with the viscosity being 3.35 times its original value. This point also becomes the phase transition point. When the water content exceeds the critical value, the droplets in the crude oil will deform, triggering a phase transition of the fluid. During this process, the oil phase transitions from the continuous phase to the dispersed phase, while the water phase changes from the dispersed phase to the continuous phase, resulting in the formation of an oil-in-water (O/W) type emulsion. This leads to a significant reduction in the crude oil viscosity. At 40 °C, when the water content is increased to 70%, the viscosity drops sharply from 8132 mPa·s to 3134 mPa·s, a decrease of 62.29%.

Before reaching the phase transition point, a W/O-type emulsion is formed. As the water content increases, the viscosity of the fluid continues to rise, reaching a peak at the transition point. After surpassing this transition point, an O/W-type emulsion is formed, and the viscosity of the fluid decreases. However, the viscosity reduction effect is primarily dominated by temperature. Therefore, when using multi-component thermal fluids to reduce viscosity, the proportion of water in the components must be controlled to avoid being near the transition point. This could increase the fluid’s viscosity and hinder the flow and development of heavy oil.

3.1.2. Temperature

The heavy oil emulsion system is maintained under a constant pressure of 5 MPa and a stirring speed of 300 r/min to observe the variation in the emulsion phase transition point at four different temperatures (30 °C, 50 °C, 80 °C, and 100 °C), as shown in Figure 5. This study examines the influence of temperature on the phase transition and viscosity of the emulsion.

The experimental results indicate that the emulsification phase transition point of the heavy oil emulsion increases with a rise in temperature. As the temperature rises from 30 °C to 100 °C, the transition point shifts from a water content of 50% to 70%. The phase transition point of the emulsion increases with the experimental temperature, which means that the stability of the emulsion is enhanced, and the phase transition only occurs under conditions of a sufficiently high water content [15]. In low-temperature environments, heavy oil exhibits a high viscosity and low fluidity. This leads to an increased mechanical resistance during the emulsification process, even with enhanced stirring, making it difficult for water molecules to be encapsulated by the oil phase. It is hard to form a stable oil–water emulsion system, resulting in a significant reduction in the emulsification transition point. However, as the temperature rises, the viscosity of the heavy oil decreases. Among them, the effect of the active ingredients is enhanced, such as that of resins and asphaltenes, which are interfacial active substances. This significantly improves their interfacial activity. The adsorption of these interfacial active substances at the oil–water interface promotes more interaction between heavy oil and water molecules, enhancing the oil’s encapsulation ability towards water, thus causing a delay in the emulsification transition point [16].

Although the phase transition point of the emulsion moves towards a higher water content with an increase in temperature, making the phase transition of the emulsion more difficult, the viscosity of the heavy oil emulsion decreases significantly. At a water content of 50%, when the temperature rises from 30 °C to 100 °C, the viscosity drops by 97%. The effect of temperature on the viscosity of the heavy oil emulsion is very significant and can effectively reduce its viscosity, but as the temperature continues to rise, the viscosity-reducing effect brought about by the increase in temperature will gradually weaken.

3.1.3. Stirring Rate

At a temperature of 50 °C, the impacts of different stirring rates on the phase transition and viscosity of the heavy oil emulsion are observed (Figure 6). These stirring rates include 300 r/min, 600 r/min, 800 r/min, 1000 r/min, and 1200 r/min.

The results indicate that, as the stirring rate increases, the phase transition point of the heavy oil emulsion first increases and then decreases. At a stirring rate of 300 r/min, the emulsification phase transition point of the heavy oil is at a water content of 50%. As the stirring rate increases to 800 r/min, the emulsification phase transition point increases to a water content of 65%, forming a more stable water-in-oil (W/O) emulsion, with the maximum viscosity rising to 9785.25 mPa·s. However, when the stirring rate increases to 1000 r/min and 1200 r/min, the transition point drops to a water content of 55% and the viscosity significantly decreases. Lower stirring rates generally find it difficult to maintain the stability of the emulsion, which may cause a phase transition under conditions of a lower water content. However, as the rate increases, a stable oil-in-water (O/W) emulsion is formed before reaching the critical value. When the stirring rate exceeds the critical rate, the greater the rate, the more energy is added to the system. The stability of the emulsion decreases, and the phase transition occurs earlier.

The stirring rate significantly affects the stability of the emulsion. Therefore, it is necessary to determine the appropriate stirring rate to enhance the stability of the emulsion. The oil and water phases are emulsified for 10 min at an emulsification temperature of 50 °C with a water content of 50%. After thorough mixing at different stirring rates and subsequent standing, the water separation of the emulsion is observed. The experimental results show that, as the rate of emulsification increases, the water separation rate decreases (Figure 7). A greater force applied results in smaller water phase droplets that can be evenly distributed in the crude oil, thereby enhancing the stability of the crude oil emulsion and making it more difficult for the oil and water to separate [17]. The emulsion obtained at 1000 r/min shows a significant difference in its water separation process over time compared to that at 800 r/min, ith a markedly reduced water separation rate, indicating an improved stability of the crude oil emulsion. In summary, at a stirring rate of 1000 r/min, both the emulsification phase transition and the stability of the emulsion are improved, making it a more suitable stirring rate.

3.1.4. Dissolved Gas Volume

A singular heavy oil water emulsion system struggles to reduce the viscosity of heavy oil without the addition of other emulsifiers, and in most cases, it increases the viscosity. However, in a multi-component thermal-fluid-heavy oil system, multi-component gases are introduced, with CO₂ being a component that can effectively reduce the viscosity and surface tension of heavy oil [18].

When the heavy oil water emulsion is injected with multi-component gases, it can lower the viscosity of the heavy oil–water emulsion, forming an aerated heavy oil–water emulsion. Different proportions of multi-component gases are mixed with the heavy oil–water emulsion and dissolved in the PVT apparatus. The viscosity and phase transition points of the aerated heavy oil–water emulsion are measured at various temperatures, with the viscosity variation curve as a function of the water content being shown in Figure 8.

The experimental results demonstrate that the dissolution of multi-component gases reduces the phase transition point of the heavy oil emulsion, and the extent of this reduction varies with the amount of dissolved gas. When the gas–oil ratio is 5 sm³/m³ (standard cubic meters per cubic meter), the aerated heavy oil emulsion undergoes a phase transition at a water content of 50%, shifting from an aerated water-in-oil (W/O) emulsion to an aerated oil-in-water (O/W) emulsion. In contrast, at gas–oil ratios of 15 sm³/m³ and 25 sm³/m³, the aerated heavy oil emulsion achieves a phase transition at a water content of 40%. Compared to the heavy oil emulsion without dissolved multi-component gases, which only transitions at a water content of 50%, the greater the amount of dissolved multi-component gases, the earlier the phase transition of the heavy oil emulsion occurs with an increasing water content. This indicates that the dissolution of multi-component gases influences the properties of the heavy oil emulsion. On one hand, the multi-component gases cause the asphaltenes at the oil–water interface to flocculate and settle, promoting the aggregation of encapsulated water droplets and accelerating the phase transition of the emulsion. On the other hand, the CO₂ in the multi-component gases, upon dissolving in water, forms carbonic acid, effectively reducing the interfacial tension of the heavy oil emulsion. The greater the amount of aerated gas, the more carbonic acid is produced [19]. The more pronounced the reduction in interfacial tension, the earlier the phase transition [20].

The phase transition point varies with the change in the dissolved gas–oil ratio, and the effect of dissolved multi-component gases on reducing the viscosity of heavy oil emulsion is also very pronounced. Observing the crude oil discharged from the PVT apparatus, as shown in Figure 9, the color is noticeably lighter compared to untreated heavy oil. Moreover, after the pressure decay, it is found that the crude oil is dispersed with a large number of tiny bubbles. The viscosity of the crude oil is low, allowing it to flow smoothly. This indicates that the multi-component gases have been dissolved in the heavy oil emulsion to form foamy oil. This foamy oil can effectively reduce the viscosity of heavy oil and improve its mobility, helping to enhance the efficiency of heavy oil reservoir development.

3.2. Dissolution Pattern of Gas Components in Foamy Oil

3.2.1. Gas Components

Different gases exhibit varying abilities to dissolve in heavy oil. Therefore, CO₂, N₂, and a multi-component gas mixture (with a CO₂ to N₂ ratio of 1:4) are selected for the research. Under identical conditions of temperature and heavy oil, the pressure is varied to observe the solubility of different gases, as shown in Figure 10.

Increasing the pressure enhances the solubility of gases in heavy oil. Under the same conditions of pressure and temperature, the solubility follows the following order: CO₂ > multi-component gas mixture > N₂. However, the multi-component gas mixture plays a more significant role in heavy oil production, combining the high solubility of CO₂ with the good expansive and elastic properties of N₂, which can reduce the amount of gas injected during the oil displacement process [21].

To analyze the viscosity reduction capabilities of different components, viscosity experiments are conducted on single-component (N₂, CO₂)-heavy oil systems at various temperatures, as well as on multi-component thermal fluid (with a mass ratio of CO₂:N₂:H₂O = 1:4:5)-heavy oil systems, as shown in Figure 11. The results indicate that the viscosity reduction effect of multi-component thermal fluid heating is greater than that of single-component gas dissolution.

The high solubility of CO₂ provides a better viscosity reduction effect, while N₂ has a poorer mixing ability, leading to a slower rate of viscosity reduction in the system. In contrast, the multi-component thermal fluid can form a “pseudo-single-phase” emulsion system with heavy oil, rapidly reducing the system’s viscosity. At 60 °C, the viscosity of the multi-component thermal-fluid-heavy oil system is significantly reduced after the formation of foamy oil, by 1202 mPa·s, which is far superior to the viscosity reduction effects of CO₂ and N₂ dissolution. This indicates that, even if the system’s temperature drops from the initial injection temperature to the reservoir temperature, the viscosity of the multi-component thermal-fluid-heavy oil system remains much lower than that of the single-component-heavy oil system.

3.2.2. Water Content

In multi-component thermal-fluid-heavy oil systems, the composition of the multi-component thermal fluid contains a significant amount of water, which can form an emulsion under stirring. The water content of the emulsion also affects the solubility of multi-component gases.

Ordinary heavy oil and water are selected to form emulsions with water contents of 10%, 30%, and 50% by stirring (Figure 12), and an appropriate amount of multi-component gas is dissolved in the emulsion to observe the changes in the saturation pressure. The experimental results show that, at the same temperature, when the gas–oil ratio of the dissolved multi-component gas is the same, the saturation pressure increases with an increase in the water content of the crude oil. Moreover, after the gas–oil ratio of the dissolved multi-component gas increases, the difference caused by the water content of the crude oil becomes more apparent. At a water content of 10%, when the dissolved gas–oil ratio is increased from 5 sm³/m³ to 30 sm³/m³, the saturation pressure increases by 8.2 MPa. At a water content of 30%, the saturation pressure increases by 13.66 MPa; at a water content of 50%, the saturation pressure increases by 25.43 MPa. The saturation pressure increases with an increase in the dissolved gas–oil ratio, and the higher the water content of the emulsion, the greater the pressure required under the same dissolved gas–oil ratio. Therefore, the water content of the crude oil is not conducive to the dissolution of multi-component gases.

3.2.3. Temperature

Three heavy oil samples with distinct viscosities are selected to investigate the effect of temperature on gas solubility. At a constant gas–oil dissolution ratio, the pattern of saturation pressure variation across different temperatures is examined to discern the influence of temperature on the dissolution of gases within the oil matrix.

The experimental results indicate that, as the temperature increases, the solubility of multi-component gases in the heavy oil significantly decreases, as shown in Figure 13. In the case of conventional heavy oil, to achieve a gas–oil dissolution ratio of 10 sm³/m³, a pressure of 8.29 MPa is required at 60 °C. However, when the temperature rises to 180 °C, the pressure needed increases to 13.78 MPa, which is a 66.22% increase. The saturation pressure becomes noticeably higher, indicating that the dissolution of multi-component gases into heavy oil is increasingly hindered. It is concluded that an increase in temperature intensifies the thermal motion of gas molecules, and high-temperature conditions are unfavorable for the dissolution of gases in heavy oil and the formation of stable foamy oil.

Based on the temperature data, the differences in the ability of heavy oils with varying viscosities to dissolve gases are revealed, as shown in Figure 14. The higher the viscosity of the crude oil, the worse its capacity to dissolve multi-component gases. In heavy oils with a high viscosity, there are higher contents of heavy components and larger molecular species, which exhibit intermolecular van der Waals forces [22]. The attractive forces between molecules result in a relatively compact internal structure of the crude oil, providing less space for gas molecules to dissolve, thereby reducing its ability to dissolve gases.

3.2.4. Stirring Rate

Under conditions of a constant temperature, the stirring rate is continuously varied to observe the dissolution of gases in crude oil. As can be seen in Figure 15, at a constant pressure, the gas–oil ratio of dissolved gas increases gradually with an increase in the stirring rate. Similarly, the capacity to dissolve multi-component gases also strengthens with an increasing pressure. For instance, at 3 MPa, when the stirring rate is increased from 300 r/min to 1200 r/min, the dissolved gas–oil ratio increases from 3.24 sm³/m³ to 7.92 sm³/m³, with a 144% increase amplitude. At 5 MPa, the dissolved gas–oil ratio increases from 5.19 sm³/m³ to 9.53 sm³/m³. The reason for this is that, as the stirring rate increases, bubbles that are excessively deformed and ruptured become smaller, resulting in a more uniform distribution of bubbles in the medium. Consequently, the likelihood of bubbles touching each other is reduced, leading to a decrease in collisions and compression between bubbles. An appropriate stirring rate can promote the stability of the system, forming a more stable and uniform foamy oil [23]. However, after reaching a certain rate, this increased efficiency becomes significantly diminished. As the stirring rate increases, the increase in the dissolved gas–oil ratio is very slow. The inflection point is 600 r/min. At 3 MPa, when the rate is increased from 600 r/min to 1200 r/min, the dissolved gas–oil ratio only increases from 7.12 sm³/m³ to 7.92 sm³/m³, and the rate of increase in the dissolved gas–oil ratio is still slowing down, indicating that there is a limit to the ability of the stirring rate to enhance gas dissolution.

3.3. Influence of Combustion Condition Components on System Phase Behavior

When diesel is used as the fuel for a multi-component thermal fluid generator, under the optimal combustion conditions, the flue gas produced contains 68.88% N₂ and 21.62% CO₂. When natural gas is used as the fuel for this generator under the best conditions, the composition includes 69.76% N₂ and 16.55% CO₂. The difference in N₂ content is not significant. However, the key difference lies in the CO₂ content, with diesel having a 5.07% higher CO₂ content compared to natural gas. The components that mainly affect the phase behavior of heavy oil are CO₂ and water.

Under the condition that the gas-to-water ratio in the injected multi-component thermal fluid is held constant, the content of CO₂ in the gas components produced by diesel combustion is higher. Compared to the products of natural gas combustion, these components can dissolve more readily into heavy oil, effectively reducing the phase transition point and viscosity of the emulsion. This promotes the formation of foamy oil, enhancing the viscosity reduction effect and its fluidity. Therefore, the components of the flue gas derived from diesel combustion are more suitable for use as a multi-component thermal fluid.

When diesel is utilized as fuel, under the optimal combustion conditions, the ratio of CO₂ to N₂ is 1:3.5. At a pressure of 10 MPa and a temperature of 70 °C, the multi-component thermal fluid produced from ideal combustion is thoroughly mixed with heavy oil at a mass ratio of 1:1. The resulting changes in the water content and viscosity of heavy oil under different water supply volumes are shown in Figure 16. Although variations in the water supply volume affect the water temperature, the mixed temperature of water still exceeds 200 °C, and the fundamental impact on the properties of the heavy oil remains essentially unchanged. Therefore, the effect of the water supply volume is studied here using the reservoir temperature.

As the water supply increases, the proportion of water in the multi-component thermal fluid rises, which, in turn, significantly raises the water content in the multi-component thermal-fluid-heavy oil system from 35% to 45%. This leads to a rapid increase in the viscosity of the heavy oil emulsion and hinders the dissolution of gases. Although the dissolution of multi-component gases can reduce the phase transition point, the viscosity change at this time clearly indicates that the phase transition point has not been reached. Under this pressure, the system’s dissolved gas–oil ratio should not exceed 10 sm³/m³ under normal conditions. The influence of temperature further increases the phase transition point to above a water content of 45%. Under the combustion conditions of the multi-component thermal fluid generator, the amount of water supplied will directly affect the phase behavior of the mixed system, necessitating some control over the water supply. In practice, to accommodate actual production, the water content of the system can be maintained between 50% and 55%.

4. Conclusions

This study utilized an efficient PVT experimental apparatus to study the special phase behavior of emulsions and foamy oil produced after the injection of multi-component thermal fluids into heavy oil. The following conclusions were reached.

• (1). For the heavy oil water emulsion system, water content is a direct factor affecting phase changes within the system. It is necessary to control the water content to avoid being near the phase inversion point. The viscosity and phase transition of the system are also influenced by the temperature, stirring rate, and amount of dissolved multi-component gases. The dissolution of multi-component gases not only reduces viscosity, but also decreases the phase transition point as the amount of injected gas increases.

• (2). There are differences in the ease with which different gas components dissolve into heavy oil. Under the same conditions, the solubility order is CO₂ > multi-component gases > N₂, and the viscosity reduction effect order is multi-component thermal fluids > CO₂ > N₂. The water content hinders the dissolution of multi-component gases in heavy oil. Although an increase in temperature can reduce viscosity, it is not conducive to the dissolution of gases to form foamy oil.

• (3). Compared to natural gas, the product components from diesel are more suitable as fuel for multi-component thermal fluid generators. Under the optimal combustion conditions, the ratio of CO₂ to N₂ in multi-component gases is 1:3.5. Under the combustion conditions of a multi-component thermal fluid generator, the amount of water supplied will directly affect the phase behavior of the mixed system after combustion. It is necessary to control the water supply to some extent. In practice, the water content of the system can be maintained between 50% and 55%.

Author Contributions

Methodology, X.D., M.L., X.Z. and Y.H.; Software, Z.C.; Validation, X.Z.; Formal analysis, E.G. and J.L.; Investigation, B.M.; Data curation, X.D.; Writing—review & editing, X.D. and X.Z. All authors have read and agreed to the published version of the manuscript.

Data Availability Statement

The data that support the findings of this study are available from the corresponding author upon reasonable request.

Conflicts of Interest

Author Erpeng Guo was employed by the company Research Institute of Petroleum Exploration & Development, PetroChina Company Limited. The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

Footnotes

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Figures and Table

Figure 1. Appearance drawing of high-temperature sealing structure components.

Figure 2. Concentric magnetic force for the coupling of the rotor.

Figure 3. A schematic diagram of the PVT experiment.

Figure 4. Effects of different water contents on the emulsion viscosity.

Figure 5. Contrast the effects of different temperatures on the emulsion viscosity.

Figure 6. Effects of different stirring rates on the emulsion viscosity (50 °C).

Figure 7. Effects of different mixing rates on the water rate of emulsion.

Figure 8. Comparison of different transition points of dissolved gas to oil ratio (30 °C).

Figure 9. Pictures of the PVT experimental products. (a) Discharged heavy oil. (b) Emulsified heavy oil with entrained bubbles (the reflective spots in the figure are bubbles).

Figure 10. Gas dissolution degree of different components (30 °C).

Figure 11. Effects of temperature on the viscosity of different injected-fluid-heavy oil systems (15 MPa).

Figure 12. The influences of different water contents on the gas dissolution capacity.

Figure 13. Saturated pressure of a multicomponent gas at different temperatures.

Figure 13. Saturated pressure of a multicomponent gas at different temperatures.

Figure 14. Comparison of heavy oils with different viscosities.

Figure 14. Comparison of heavy oils with different viscosities.

Figure 15. Dissolved gas–oil ratios at different stirring rates (50 °C).

Figure 16. Water content and heavy oil viscosity changes under different water supply quantities.

Table 1

Oil sample component contents.

Oil Sample	50 °C Crude Oil Viscosity(mPa·s)	Saturated Hydrocarbons (%)	Aromatics (%)	Resins (%)	Asphaltenes (%)
Ordinary Heavy Oil	1523	44.71	22.14	26.32	6.83
Extra-Heavy Oil	29,876	26.23	29.67	30.12	13.98
Ultra-Heavy Oil	54,035	18.53	25.75	33.11	22.61

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