A Study on the Miscibility Mechanisms and Patterns of High CO2 Content Associated Gas Reinjection

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The experimental results demonstrated that CH 4 and N 2 reduce the solubility of associated gas in crude oil, the solubility of associated gas without CH 4 and N 2 in crude oil is 1.05 to 3.22 times that of CO 2 while their removal enables the solubility of associated gas in crude oil to surpass that of CO 2 . Both CO 2 and associated gas can cause crude oil to swell and reduce its viscosity, and the absence of CH 4 and N 2 amplifies these effects. The minimum miscibility pressure (MMP) for CO 2 flooding is 24.29 MPa, while the reservoir pressure of 21 MPa is insufficient to achieve miscible flooding. Removing CH 4 and N 2 from the associated gas can reduce the MMP by up to 48%, resulting in a 25.59% improvement in oil recovery efficiency. Physical sciences/Energy science and technology/Carbon capture and storage Physical sciences/Energy science and technology/Fossil fuels/Crude oil Figures Figure 1 Figure 2 Figure 3 Figure 4 Figure 5 Figure 6 Figure 7 Introduction In the context of the "Dual Carbon" era, carbon capture, utilization, and storage (CCUS) has become a key focus. Currently, the use of CO 2 flooding technology for oil recovery has become increasingly mature in various oilfields. During reservoir exploitation, oil wells produce both crude oil and associated gas. Due to the severe reservoir heterogeneity caused by Chinese sedimentary environments and the issue of CO 2 gas breakthrough in the later stages of development, the CO 2 content in associated gas increases sharply. This hinders the efficient utilization of CO 2 and its effective sequestration in the reservoir 1 – 3 .After the crude oil is extracted, the oil and gas enter the metering station through the oil pipeline. Following processing through a buffer tank, separator, booster pump, and other equipment, the CO 2 content in the associated gas increases further 4 – 6 . The combustion of associated gas with high CO 2 content cannot meet the required calorific value. Purifying the CO 2 through physical or chemical adsorption methods for further use increases costs, adds complexity to the process, and reduces production efficiency 7 – 9 . However, reinjecting such high-CO 2 -content associated gas directly into the reservoir for enhanced oil recovery can achieve both economic benefits and environmental compliance. The Weyburn Oilfield in Canada is the largest CO 2 flooding demonstration project to date. Since 2000, 1 million tons of CO 2 have been injected annually for enhanced oil recovery. In 2010, the oilfield began researching associated gas reinjection, and currently, the reinjected CO 2 accounts for 50% of the total injection volume 10 , 11 . In recent years, there has been a significant amount of research on associated gas reinjection 12 , Kun Su et al. 13 used numerical simulation methods to study the effect of direct associated gas reinjection in the Jilin Oilfield and found that it could further enhance oil recovery. S.L. Yang et al. 14 conducted a full-component analysis of crude oil produced at different stages and found that the proportion of each component in the produced oil before gas breakthrough was similar to that in the initial crude oil. After gas breakthrough, the proportion of light components in the produced oil gradually increased. When the CO 2 concentration in the reinjected gas was less than 25%, the component changes in the produced crude oil were not significant. Rich gas, an important component of associated gas, contributes to enhanced oil recovery 15 .The United States and Canada were among the first to conduct field trials of injecting rich gas to enhance oil recovery 16 – 18 .The former Soviet Union successfully applied the alternating water-gas injection technique in the North Sea Oilfield 19 , 20 .Venezuela once implemented the largest natural gas injection project for enhanced oil recovery in the world 21 .As early as the 1980s,CHEN et al 22 studied the impact of solvent slug size on oil recovery efficiency in rich gas miscible flooding and establishing a slug size calculation model considering multiple factors. GLASO 23 proposed a relationship equation for predicting the minimum miscibility pressure between rich gas and crude oil. SHYEH-YUNG 24 studied the impact of the components of enriched gas and injection pressure on displacement efficiency. Regarding the reinjection of enriched associated gas, Hoffman et al. 25 investigated gas injection for enhanced oil recovery in the Elm Coulee shale reservoir under both miscible and immiscible conditions using numerical simulation. Their comparison revealed that rich gas injection could further improve the recovery factor. Tao Wan et al. 26 focused on the Eagle Ford Shale as their study subject, accounting for uncertainties in oil composition changes. They developed a geological model using a stable black oil model and, based on this, used commercial simulation software to model cyclic rich gas injection, optimizing the injection strategy to further enhance the recovery factor. Morteza Akbarabadi 27 demonstrated through core displacement experiments that hydrocarbon gases co-produced with crude oil play a significant role in enhancing oil recovery. Ala Eddine Aoun et al. 28 taking into account the field conditions of the Bakken reservoir, proposed an alternating injection scheme of associated gas at a rate of 3MMcfd, considering capital expenditure, operational costs, and oil revenue. Their calculations indicated that this approach could potentially increase oil production by 70%.GF Sancet 29 . Progress has also been reported in recent years at many other oilfields all over the world 30 – 32 . Researchers have conducted extensive studies on associated gas reinjection, but there is still a lack of research on the production dynamics after reinjecting high-CO 2 associated gas, the changes in MMP between associated gas and crude oil, and the oil recovery efficiency of associated gas and treated associated gas. Therefore, further investigation into the feasibility of reinjecting high-CO 2 associated gas and the changes in MMP after reinjection with different CO 2 concentrations is of great significance for field operations in oilfields. The H block of the Jilin oilfield has a reservoir depth of 2450 meters, a porosity ranging from 8–15%, and strong heterogeneity. To maintain reservoir pressure and well productivity, CO 2 injection was initially employed, followed by water injection in the later stages of reservoir development. Currently, the H block is in the late phase of gas injection, with a reservoir pressure of 21 MPa, a reservoir temperature of 94.7°C, and crude oil properties including a viscosity of 1.79mPa·s, a saturation pressure of 8.62 MPa, and a formation volume factor of 1.152 at 21 MPa. The gas-oil ratio is 35 under standard conditions. The CO 2 content in the associated gas remains relatively stable and high, making further CO 2 injection less effective for both enhanced oil recovery and long-term storage. Therefore, in this study, based on the current reservoir conditions, laboratory experiments were appropriately simplified. Slim tube tests were conducted using CO 2 and associated gases with varying CO 2 concentrations to measure the MMP (Minimum Miscibility Pressure) between crude oil and associated gases with different CO 2 concentrations. Supplemented by gas injection expansion experiments and solubility of different injected gases determination in crude oil to study the changes in physical properties of crude oil after gas injection. The study specifically focuses on research related to the reinjection of associated gas, providing valuable reference data for field operations in the oilfield. Experimental Materials In the experiment, a coiled sand-packed slim tube with a length of 15 meters and a diameter of 4 mm was selected. The pore volume of the tube was 86.249 cm³, with a porosity of 45.76% and a permeability of 4860mD. The crude oil used in the experiment was degassed oil sourced from Block H of Jilin oilfield, which was reconstituted into formation oil in the laboratory. The composition of the well stream fluids and the dissolved gas data are shown in Table 1. The different associated gases used in the experiment were synthesized by mixing CO 2 , CH 4 , C 2 -C 4 , and liquid C 5 and C 6 , with CO 2 molar ratios of 90%, 80%, 70%, and 60%, while maintaining the proportions of the other components constant. On this basis, CO 2 + CH 4 mixtures with different CO 2 molar ratios and associated gases with CH 4 and N 2 removed were also prepared. The composition of the well stream fluids and dissolved gas is presented in Table 1, and the composition of associated gases with varying CO 2 concentrations is shown in Table 2. Table.1 Composition of well fluids and dissolved gas. Fluid types Molar composition of components /% N 2 CO 2 C 1 C 2 C 3 iC 4 nC 4 iC 5 nC 5 C 6 C 7 + Well fluid 1.59 0.19 17.36 3.78 2.43 0.46 1.27 0.60 1.39 3.78 67.15 Dissolved gas 6.01 0.72 66.44 13.55 7.18 0.96 2.24 0.54 0.99 1.24 0 Table.2 Formulation data of associated gas. CO 2 concentration/% Proportions of components/% N 2 CO 2 C 1 C 2 C 3 iC 4 nC 4 iC 5 nC 5 C 6 90 1.484 90 5.457 1.659 0.999 0.098 0.205 0.031 0.047 0.020 80 2.969 80 10.914 3.317 1.998 0.195 0.409 0.061 0.095 0.041 70 4.454 70 16.371 4.976 2.998 0.293 0.614 0.092 0.142 0.061 60 5.939 60 21.828 6.635 3.997 0.390 0.819 0.122 0.190 0.081 Determination of solubility of different gases in crude oil A certain mass of crude oil with an initial volume V 0 is injected into a high-temperature and high-pressure reactor. The gas to be measured is then introduced into the reactor until a certain pressure is reached. The release valve is opened to expel the air inside the apparatus. The target gas is further introduced, and when the pressure in the reactor reaches the set level, the inlet is closed. The experimental temperature is set, and heating and stirring are initiated. The pressure in the reactor is recorded at 20-minute intervals. Equilibrium is considered achieved when the recorded pressure remains constant over three consecutive readings, which is noted as the equilibrium pressure. The schematic diagram of the experimental apparatus used is illustrated in Fig. 1. The solubility of the gas in crude oil is expressed as the amount of gas (in moles) dissolved per kilogram of crude oil 33 , 34 . This value is calculated by subtracting the amount of gas remaining at equilibrium from the initial amount of injected gas: $$\:X=\frac{{n}_{0}-{n}_{1}}{m}$$ (1) n 0 and n 1 are calculated using the ideal gas equation: $$\:{n}_{0}=\frac{{p}_{0}(V-{V}_{0})}{{Z}_{0}RT}$$ (2) $$\:{n}_{1}=\frac{{p}_{1}(V-{V}_{1})}{{Z}_{1}RT}$$ (3) Where: X is the solubility of the gas in oil(mol/kg), n 0 and n 1 are the amounts of the injected gas in the gas phase at the initial and equilibrium states in mole, m is the mass of the oil in grams, p 0 and p 1 are the initial and equilibrium pressures inside the reactor in MPa, V i s the effective volume of the reactor in m 3 , V 0 is the volume of oil inside the reactor in m 3 , Z 0 and Z 1 are the compressibility factors of the injected gas at the initial and equilibrium states, R is the universal gas constant (8.314 J/ mol·K), T is the temperature in Kelvin, The experiment measured the solubility of CO 2 , associated gas with varying CO 2 concentrations, and associated gas with CH 4 and N 2 removed in crude oil under different pressure conditions at the reservoir temperature of 94.7°C. Swelling test To investigate the effect of injected gas on crude oil properties and further explore the miscibility mechanism, experiments were conducted at reservoir temperature and pressure conditions. CO 2 , associated gas with 60% CO 2 concentration, and associated gas with 60% CO 2 concentration after removing CH 4 and N 2 were sequentially injected into a PVT cell according to predetermined ratios 35 . After each injection of a specific gas proportion, pressure was gradually increased until the injected gas fully dissolved in the crude oil to form a single phase. After each gas injection, the high-pressure physical properties of the reservoir fluid undergo changes. By measuring the density, bubble point pressure, swelling factor, and viscosity after each injection, the impact of the injected gas on crude oil properties can be analyzed 36 . The experimental setup is illustrated in Fig. 2 . A 100 mL oil sample was placed into a visual reactor, and gas was injected into the container. The temperature was kept constant at 94.7°C. The pressure was gradually increased in steps of 1 MPa, bringing the internal pressure of the reactor sequentially to 3–11 MPa. The mixture was stirred at a speed of 2000 r/min for 30 minutes. The liquid level of the oil sample inside the reactor’s visual window was recorded at each target pressure under 94.7°C, and the volume change of the oil sample before and after gas injection was calculated. After sealing the reactor with 100 mL of oil, the temperature was raised to the target of 94.7°C. Different amounts of gas were injected, and the oil and gas were thoroughly mixed through agitation to ensure complete dissolution. A high-temperature, high-pressure viscometer was used to measure the viscosity and density of the oil sample after gas injection. The procedure was repeated to obtain the viscosity and density of the oil sample under different gas injection volumes. Slim tube test In this experiment, the slim tube method is used to measure the minimum miscibility pressure (MMP) between the injected gas and crude oil 37 , 38 . Before conducting the experiment, formation oil and gas samples should be prepared according to the formulation data 39 . The experimental process is shown in Fig. 3 , and the specific steps are as follows: Cleaning the slim tube Before the experiment, thoroughly clean the capillary tube to ensure readiness. After cleaning (when the color of petroleum ether at the outlet no longer changes), use nitrogen gas to dry the tube and then use a vacuum pump to evacuate it. Saturating with dead oil Under experimental temperature and pressure conditions, saturate the entire capillary tube with petroleum ether. Calculate the pore volume (based on the difference in pump position between the start and end under constant pressure mode). Then, use dead oil (or petroleum ether) to raise the system pressure to the experimental pressure. Saturating with live oil Under experimental temperature and pressure conditions, use live oil with 2 times the pore volume to displace the dead oil. Calculate the gas-oil ratio at the capillary tube outlet. If this ratio is consistent with the gas-oil ratio of the live oil, saturation is complete. Injection experiment Adjust the inlet pressure to 0.05–0.1 MPa above the experimental pressure. Once the pump position stabilizes, record the initial position. Using a constant speed method, inject gas at a speed of 0.1 cm³/min to conduct the displacement experiment. Measure the amount of produced oil and gas, as well as the pump position, every 0.1 PV. Stop the displacement after a cumulative injection of 1.2 PV. Varying injection pressure Change the injection pressure while keeping the temperature constant, and measure the recovery factor at different injection pressures (while holding 1.2 PV constant). The pressure points are determined based on the recovery factor from the previous experiment, ensuring that there are at least 3 pressure points corresponding to recovery factors above and below 90%. Plot a scatter diagram of the recovery factor versus experimental pressure. Draw trend lines (straight lines) for the two pressure ranges. The intersection of the two trend lines corresponds to a recovery factor of MMP, and this pressure is considered the minimum miscibility pressure (MMP). Result and discussion Research on the miscible mechanism of associated gas reinjection Solubility of injected gas in crude oil Based on the experimental data and Equations ( 1 ) to (4), the solubility of different injected gases in crude oil under reservoir conditions was calculated. The results are shown in Table 3. Table.3 The solubility of different gas in oil Type of gas Temperature/℃ Pressure/MPa CO 2 concentration/% Solubility(mol/kg) CO 2 94.7 5 100 0.138 94.7 6 100 0.482 60 5 100 0.186 Associated gas 94.7 5 90 0.128 80 0.114 70 0.104 60 0.092 Associated gas without CH 4 and N 2 94.7 5 90 0.145 80 0.243 70 0.345 60 0.444 The experimental results indicate that, at a constant temperature, the solubility of the gas increases with an increase in initial pressure. Conversely, when the initial pressure remains constant, raising the temperature reduces the oil's ability to dissolve the gas. This phenomenon suggests that increasing the injection pressure can enhance gas dissolution into the oil, thereby facilitating a range of effects that promote oil flow. The solubility of associated gas in oil is slightly lower than that of CO 2 , whereas the removal of CH 4 and N 2 from the gas allows for even greater solubility in the oil. Analysis of crude oil gas injection expansion experiments Through the swelling test, the physical property changes of crude oil after gas injection were analyzed to study the miscible mechanism of associated gas reinjection. After gas injection, the crude oil density showed minimal change, viscosity decreased, and both saturation pressure and expansion coefficient increased. Figure 4 show the result of this experiment: (1) Density: Although gas dissolving into crude oil reduces its density, the compression of crude oil during the pressurization process after gas injection leads to a density increase. Therefore, as the amount of injected gas increases, the crude oil density shows an upward trend, but the maximum increase is only 0.008 g/cm³. Additionally, associated gas with N 2 and CH 4 removed performs better in reducing the crude oil density. (2)Viscosity: Gas injection leads to a significant reduction in crude oil viscosity. The effectiveness of viscosity reduction follows the order: associated gas without N 2 and CH 4 > CO 2 > raw associated gas. Injecting associated gas without N 2 and CH 4 decreases viscosity from 1.79 mPa·s to 0.92 mPa·s, a 48.6% reduction (Fig. 4b). This is due to CO 2 dissolving in heavy oil, disrupting colloid and asphaltene structures, and reducing molecular interactions. Hydrocarbons in the purified associated gas further enhance this effect. (3)Saturation Pressure: After gas injection, crude oil saturation pressure increases. CH 4 and N 2 in the associated gas inhibit gas solubility in oil, while the hydrocarbons dissolve more readily, leading to the observed trends in Fig. 4c. After dissolving 51.9 m³/m³ of gas, the saturation pressure for CO 2 , raw associated gas, and treated associated gas rose to 25.359 MPa, 22.733 MPa, and 19.362 MPa, respectively. (4)Expansion Coefficient: The expansion coefficient reflects the extent of crude oil volume expansion due to gas dissolution during injection. As shown in Fig. 4d, the treated associated gas exhibits a more pronounced expansion effect. When the gas injection volume reaches 51.9 m³/m³, the expansion coefficient of the crude oil reaches 1.39. The experimental results indicate that after CO 2 injection, crude oil experiences volume expansion and increased bubble point pressure, enhancing its elastic properties in the reservoir. This is consistent with the analytical results of other scholars 40 , 41 . Simultaneously, the viscosity decreases, improving oil mobility and facilitating displacement. Injecting associated gas with 60% CO 2 content shows slightly weaker expansion and viscosity reduction effects compared to CO 2 alone. However, after removing N 2 and CH 4 from the associated gas, it performs even better than pure CO 2 . Results of the slim tube test Production dynamics of associated gas reinjection In the slim-tube displacement experiment, oil and gas production rates were recorded at each 0.1 PV gas injection increment until reaching 1.2 PV. The recovery factor and gas-oil ratio (GOR) for each stage were calculated. Figure 5 shows the GOR, stage recovery factor, MMP determination curve and the non-miscible state through the viewing window for associated gas with 90% CO 2 content at various injection pressures. Results indicate that recovery factor increases with injected volume, rising rapidly before 0.9 PV. In the early injection phase (before 0.4 PV), lower injection pressures yield faster growth, with a growth rate of approximately 9.3% per 0.1 PV at 21 MPa. The GOR for each injection pressure significantly increases after 0.9 PV, reaching its peak at 1.2 PV. Similar production patterns were observed for associated gases with different CO 2 concentrations. The analysis of experimental results indicates that, prior to breakthrough, the recovery factor in associated gas flooding rises rapidly with increasing injection volume. This effect is especially pronounced at lower injection pressures, where recovery increases more quickly in the early stages. This is because, when the injection pressure is below the MMP, CO 2 struggles to mix with the crude oil, and the displacement process resembles immiscible displacement. However, lower injection pressures lead to lower recovery rates in the later stages. The main reason is that CO 2 creates a preferential flow channel after displacing some pore oil, causing most of the injected CO 2 to flow along this channel, which results in a sharp rise in the gas-oil ratio 42 . Consequently, the oil in other pore spaces is less likely to be displaced by CO 2 , leading to lower ultimate recovery at low injection pressures 43 . Influence of Associated Gas Reinjection on Minimum Miscibility Pressure Exploring the influence of associated gas reinjection on the Minimum Miscibility Pressure (MMP), as well as the mechanisms by which each component in the associated gas affects MMP, is valuable for predicting field recovery rates. Using the slim tube method, the MMP of associated gases with varying CO 2 contents, CO 2 + CH 4 mixtures, and associated gases with CH 4 and N 2 removed was determined with crude oil. The corresponding trends in MMP with changes in injected gas composition were analyzed. The relationship curve between MMP and CO 2 concentration in the injected gas with crude oil is plotted in Fig. 6 . Results indicate that MMP shows a strong linear correlation with the CO 2 concentration in the injected gas, which has correlation coefficients above 0.97. When CH 4 is present in the injected gas, MMP increases as the CO 2 content decreases. For every 10% decrease in CO 2 concentration in the associated gas, MMP rises by 0.937 MPa, reaching 27.94 MPa when the CO 2 concentration is relatively low (60%). The MMP of the CO 2 + CH 4 mixture rises even more rapidly, being 3.07 MPa higher than that of the associated gas at a 60% CO 2 concentration. Conversely, the MMP behavior of the associated gas without CH 4 and N 2 shows a different trend, with MMP decreasing by 2.469 MPa for every 10% reduction in CO 2 concentration. This modified associated gas remains miscible with crude oil even at low CO 2 concentrations, achieving an MMP of only 14.53 MPa at a 60% CO 2 level. The presence of methane or nitrogen increases the minimum miscibility pressure (MMP) of CO 2 flooding, with nitrogen having a greater effect than methane. Removing CH 4 and N 2 effectively reduces MMP. When these gases are removed from associated gas, the remaining components, apart from CO 2 , are light fractions of crude oil, which enhances miscibility with crude oil. This results in the curve being lower than the one for associated gas reinjection 44 , 45 . As the CO 2 concentration decreases, the proportion of other components that promote miscibility increases, leading to a reduction in MMP as CO 2 concentration decreases 24 , 46 . Oil displacement efficiency of associated gas To evaluate the oil displacement capacity of associated gas, the recovery factor was calculated after injecting associated gas with different CO 2 concentrations up to 1.2 PV into a slim tube at reservoir pressure (21 MPa), and compared with that of pure CO 2 injection under the same conditions. The results are shown in Fig. 7 . It can be seen that, at the current reservoir pressure, which is significantly lower than the CO 2 -oil MMP, the efficiency of CO 2 flooding is below 90%. The oil displacement efficiency of associated gas reinjection is lower than that of pure CO 2 , and at reservoir pressure, the lower the CO 2 concentration in the associated gas, the lower the displacement efficiency. With an associated gas containing 60% CO 2 , the displacement efficiency was reduced by 7.92% compared to pure CO 2 . The low oil displacement efficiency of associated gas is mainly due to the presence of CH 4 and N 2 in its composition compares the oil displacement efficiency of direct associated gas reinjection with that of purified associated gas (with CH 4 and N 2 removed). The comparison shows a significant improvement in oil displacement efficiency after removing CH 4 and N 2 impurities, resulting in a near-miscible to miscible displacement state. When the CO 2 concentration is 90%, the displacement efficiency increases by 14.39%. As the displacement efficiency of associated gas is positively correlated with its CO 2 concentration, while purified associated gas exhibits an inverse relationship, removing CH 4 and N 2 can achieve a greater efficiency improvement at lower CO 2 concentrations. For instance, at 60% CO 2 concentration, the oil displacement efficiency of purified associated gas is enhanced by 25.59%. It is undeniable that purifying CH 4 and N 2 also incurs costs 47 . Therefore, while aiming to improve recovery rates, a balance should be struck between the investment costs and the benefits. Achieving effective CO 2 sequestration alongside maximizing profitability will be a critical focus for future research. Conclusion (1)Lowering the temperature and increasing the pressure both enhance the dissolution of CO 2 into crude oil. Compared to CO 2 , associated gas is less soluble in crude oil. Under conditions of 94.7°C and 5 MPa, the solubility of CO 2 in crude oil is 1.07 to 1.5 times that of associated gas. Removing CH 4 and N 2 significantly enhances the solubility of associated gas, making it 1.05 to 3.22 times higher than that of CO 2 . The injection of CO 2 or associated gas can reduce crude oil viscosity and increase the expansion energy of fluids in the reservoir. This effect becomes more pronounced with higher gas solubility. Therefore, CO 2 flooding or associated gas injection can further enhance oil recovery by optimizing the composition of the injected gas or incorporating solubility-enhancing agents. (2)The CO 2 concentration in associated gas influences the minimum miscibility pressure (MMP): for every 10% decrease in CO 2 concentration, the MMP increases by 0.937 MPa. Methane (CH 4 ) further raises the MMP, with each 10% increase in CH 4 in a CO 2 -CH 4 mixture resulting in an MMP increase of 1.688 MPa. Removing CH 4 and nitrogen (N 2 ) from associated gas effectively reduces the MMP, with reductions ranging between 14.4% and 48.0%.Under the current reservoir pressure, pure CO 2 injection cannot achieve miscible displacement, and the oil recovery efficiency of associated gas reinjection is even lower than that of pure CO 2 injection. This efficiency gap increases as CO 2 concentration decreases, with a 7.92% reduction in recovery efficiency when using associated gas with 60% CO 2 compared to pure CO 2 . Removing CH 4 and N 2 from associated gas enhances oil recovery efficiency, especially at lower CO 2 concentrations; for instance, associated gas with 60% CO 2 concentration and without CH 4 and N 2 achieves a 25.59% increase in recovery efficiency. Declarations Author Contribution Yunfei Lei:Conceptualization,Visualization, Writing-original draft,Data curation, Experiment execution，Formal analysis.Changquan Wang:Methodology,Data curation, Writing-original draft,Project administration, Resources, Writing-review & editing.Shijin Xu:Investigation, Supervision, Writing-review & editing.Lihong Shi:Supervision, Writing-review & editing.Xinke Jin:Formal analysis,Experiment execution， Investigation. Data Availability The authors declare that, all data generated or analyzed during this study are included in this published article. References Wang, H., Tian, L., Chai, X., Wang, J. & Zhang, K. Effect of pore structure on recovery of CO 2 miscible flooding efficiency in low permeability reservoirs. J. Petrol. Sci. Eng. 208 , 109305 (2022). Vafaie, A., Cama, J., Soler, J. M., Kivi, I. R. & Vilarrasa, V. Chemo-hydro-mechanical effects of CO 2 injection on reservoir and seal rocks: A review on laboratory experiments. Renew. Sustain. 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Evaluation of Eagle Ford Cyclic Gas Injection EOR: Field Results and Economics. in (2020). 10.2118/200427-MS Baillie, J. et al. Methane emissions from conventional and unconventional oil and gas production sites in southeastern Saskatchewan, Canada. Environ. Res. Commun. 1 , 011003 (2019). Kavousi, A., Torabi, F. & Chan, C. Experimental Measurement of CO 2 Solubility in heavy Oil and Its Diffusion Coefficient calculation at both Static and Dynamic Conditions. in (OnePetro, 2013). 10.2118/165559-MS Mosavat, N. & Torabi, F. Performance of Secondary Carbonated Water Injection in Light Oil Systems. Ind. Eng. Chem. Res. 53 , 1262–1273 (2014). Abedini, A., Mosavat, N. & Torabi, F. Determination of Minimum Miscibility Pressure of Crude Oil–CO 2 System by Oil Swelling/Extraction Test. Energy Technol. 2 , 431–439 (2014). Fakher, S., Elgahawy, Y. & Abdelaal, H. Oil Swelling Measurement Techniques: Conventional Methods and Novel Pressure-Based Method. inOnePetro, (2020). 10.15530/urtec-2020-1073 Zhang, K. & Gu, Y. Two different technical criteria for determining the minimum miscibility pressures (MMPs) from the slim-tube and coreflood tests. Fuel 161 , 146–156 (2015). Voon, C. L. & Awang, M. Comparison of MMP Between Slim Tube Test and Vanishing Interfacial Tension Test. in ICIPEG 2014 (eds Awang, M., Negash, B. M., Akhir, M. & Lubis, L. A.) N. A. 137–144 (Springer, Singapore, doi: 10.1007/978-981-287-368-2_13 . (2015). Su, Y. et al. The Influence of Slim Tube Length on the Minimum Miscibility Pressure of CO 2 Gas–Crude Oil. Processes 12 , 650 (2024). Arouri, K. R. & Herrera, C. G. Phase envelopes in reservoir fill analysis: Two contrasting scenarios. Sci. Rep. 14 , 5601 (2024). Guo, X. et al. SPE, Tulsa, Oklahoma, USA,. Optimization of Tertiary Water-Alternate-CO 2 Flood in Jilin Oil Field of China: Laboratory and Simulation Studies. in SPE/DOE Symposium on Improved Oil Recovery SPE-99616-MS (2006). 10.2118/99616-MS Zhou, X. et al. Performance evaluation of CO 2 flooding process in tight oil reservoir via experimental and numerical simulation studies. Fuel 236 , 730–746 (2019). Adel, I. A., Tovar, F. D., Schechter, D. S. & Fast-Slim Tube A Reliable and Rapid Technique for the Laboratory Determination of MMP in CO 2 - Light Crude Oil Systems. in (OnePetro, (2016). 10.2118/179673-MS Keyvani, F., Safaei, A., Kazemzadeh, Y., Riazi, M. & Qajar, J. Impact of nanopore confinement on phase behavior and enriched gas minimum miscibility pressure in asphaltenic tight oil reservoirs. Sci. Rep. 14 , 13405 (2024). Fomkin, A. V., Petrakov, A. M., Nikitina, E. A. & Egorov, Y. A. Features of filtration experiments studying oil displacement by gas on slim tube as a reservoir model (Russian). Neftyanoe khozyaystvo - Oil Ind. 2023 , 42–45 (2023). Mehrjoo, H., Safaei, A., Kazemzadeh, Y., Riazi, M. & Cortés, F. B. Modeling of the movement of rich gas in a porous medium in immiscible, near miscible and miscible conditions. Sci. Rep. 13 , 6573 (2023). Shen, M. et al. Cryogenic technology progress for CO 2 capture under carbon neutrality goals: A review. Sep. Purif. Technol. 299 , 121734 (2022). Additional Declarations No competing interests reported. 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Changquan","email":"data:image/png;base64,iVBORw0KGgoAAAANSUhEUgAAAZAAAAAyAQMAAABI0h/eAAAABlBMVEX///8AAABVwtN+AAAACXBIWXMAAA7EAAAOxAGVKw4bAAAAoUlEQVRIiWNgGAWjYPACGx5+/gbStKTJSM44QJqWwzYGDQlEqjU43nvwNk/FeR4DhgOMHz7mEKPlzLlka54zt3nMmRuYJWduI0KL2Y0cM2netts8lg0H2Jh5idfy7xyPwYEEkrQ0HCBBi/2ZM8aWc44l80jOONhMnF8k23sMb7ypsbPn528++OEjMVpAQAJCMTYQqR6hZRSMglEwCkYBDgAAJoozvRj+UcQAAAAASUVORK5CYII=","orcid":"","institution":"Key Laboratory of Drilling and Production Engineering for Oil and Gas","correspondingAuthor":true,"prefix":"","firstName":"Wang","middleName":"","lastName":"Changquan","suffix":""},{"id":425696252,"identity":"c3e48651-ad55-4bff-88e6-acc62f76c148","order_by":2,"name":"Xu Shijing","email":"","orcid":"","institution":"Key Laboratory of Drilling and Production Engineering for Oil and Gas","correspondingAuthor":false,"prefix":"","firstName":"Xu","middleName":"","lastName":"Shijing","suffix":""},{"id":425696253,"identity":"0974d658-6eea-448f-baeb-88417ff1bce5","order_by":3,"name":"Shi Lihong","email":"","orcid":"","institution":"Key Laboratory of Drilling and Production Engineering for Oil and Gas","correspondingAuthor":false,"prefix":"","firstName":"Shi","middleName":"","lastName":"Lihong","suffix":""},{"id":425696255,"identity":"5c99cb8b-6f06-426e-9770-a99ee8c02b4d","order_by":4,"name":"Jin Xinke","email":"","orcid":"","institution":"Key Laboratory of Drilling and Production Engineering for Oil and Gas","correspondingAuthor":false,"prefix":"","firstName":"Jin","middleName":"","lastName":"Xinke","suffix":""}],"badges":[],"createdAt":"2025-02-27 14:08:06","currentVersionCode":1,"declarations":"","doi":"10.21203/rs.3.rs-6121673/v1","doiUrl":"https://doi.org/10.21203/rs.3.rs-6121673/v1","draftVersion":[],"editorialEvents":[{"content":"https://doi.org/10.1038/s41598-025-15039-z","type":"published","date":"2025-08-19T16:29:32+00:00"}],"editorialNote":"","failedWorkflow":false,"files":[{"id":78152718,"identity":"015312d7-6bfa-446b-9b6a-95caa37d957f","added_by":"auto","created_at":"2025-03-10 12:07:32","extension":"png","order_by":1,"title":"Figure 1","display":"","copyAsset":false,"role":"figure","size":216648,"visible":true,"origin":"","legend":"\u003cp\u003eProcess for determining the solubility of various gases in crude oil\u003c/p\u003e","description":"","filename":"1.png","url":"https://assets-eu.researchsquare.com/files/rs-6121673/v1/567cc6b98fb9f9d3d718fa31.png"},{"id":78152719,"identity":"d94775e9-6efc-4b98-96f6-a0ecf4a9f1f2","added_by":"auto","created_at":"2025-03-10 12:07:32","extension":"png","order_by":2,"title":"Figure 2","display":"","copyAsset":false,"role":"figure","size":219636,"visible":true,"origin":"","legend":"\u003cp\u003eProcess of Swelling test\u003c/p\u003e","description":"","filename":"2.png","url":"https://assets-eu.researchsquare.com/files/rs-6121673/v1/550be861a43e2a975b016d8d.png"},{"id":78151249,"identity":"7db53777-3934-4e23-a035-5dc373a7913c","added_by":"auto","created_at":"2025-03-10 11:51:32","extension":"png","order_by":3,"title":"Figure 3","display":"","copyAsset":false,"role":"figure","size":249864,"visible":true,"origin":"","legend":"\u003cp\u003eProcess of slim tube test\u003c/p\u003e","description":"","filename":"3.png","url":"https://assets-eu.researchsquare.com/files/rs-6121673/v1/fb6b48021edf2119cd285443.png"},{"id":78152387,"identity":"9350024f-45df-4a3b-814b-4e26a586d4a5","added_by":"auto","created_at":"2025-03-10 11:59:32","extension":"png","order_by":4,"title":"Figure 4","display":"","copyAsset":false,"role":"figure","size":41695,"visible":true,"origin":"","legend":"\u003cp\u003e(a) Relationship between crude oil viscosity and gas injection volume, (b) Relationship between crude oil density and gas injection volume, (c) Relationship between crude oil bubble point pressure and gas injection volume, (d) Relationship between crude oil expansion coefficient and gas injection volume.\u003c/p\u003e","description":"","filename":"4.png","url":"https://assets-eu.researchsquare.com/files/rs-6121673/v1/ac30c84bcd2d76e366b32498.png"},{"id":78155022,"identity":"aad4d380-52ef-4b9c-9aec-eccdb75bdbfc","added_by":"auto","created_at":"2025-03-10 12:23:32","extension":"png","order_by":5,"title":"Figure 5","display":"","copyAsset":false,"role":"figure","size":141969,"visible":true,"origin":"","legend":"\u003cp\u003eProduction patterns of associated gas with 90% CO\u003csub\u003e2\u003c/sub\u003e concentration under different injection pressures and MMP determination curves：(a) Incremental recovery factor, (b) Producing gas-oil ratio (GOR),\u003c/p\u003e\n\u003cp\u003e(c) MMP determination curve, (d) The non-miscible state\u003c/p\u003e","description":"","filename":"5.png","url":"https://assets-eu.researchsquare.com/files/rs-6121673/v1/5cccbd8e7a149ec89ddc5672.png"},{"id":78152430,"identity":"e0f65871-4429-476d-b3e6-e8453cb83ffb","added_by":"auto","created_at":"2025-03-10 11:59:42","extension":"png","order_by":6,"title":"Figure 6","display":"","copyAsset":false,"role":"figure","size":21924,"visible":true,"origin":"","legend":"\u003cp\u003eRelationship curves between MMP of different injection gas-oil systems and CO\u003csub\u003e2\u003c/sub\u003e concentration in the injection gas\u003c/p\u003e","description":"","filename":"6.png","url":"https://assets-eu.researchsquare.com/files/rs-6121673/v1/bf85f07bf8e44c450950b12c.png"},{"id":78151254,"identity":"6231f3f7-e4ff-4ecb-bbb4-56156bd63e30","added_by":"auto","created_at":"2025-03-10 11:51:32","extension":"png","order_by":7,"title":"Figure 7","display":"","copyAsset":false,"role":"figure","size":9659,"visible":true,"origin":"","legend":"\u003cp\u003eDisplacement efficiency of CO\u003csub\u003e2\u003c/sub\u003e and associated gas in reservoir pressure\u003c/p\u003e","description":"","filename":"7.png","url":"https://assets-eu.researchsquare.com/files/rs-6121673/v1/3cb9d5d6597a40e0b47f73ea.png"},{"id":89847841,"identity":"5d3242f6-8f24-4c60-a92c-6ef8dfce11e2","added_by":"auto","created_at":"2025-08-25 16:44:29","extension":"pdf","order_by":0,"title":"","display":"","copyAsset":false,"role":"manuscript-pdf","size":2019436,"visible":true,"origin":"","legend":"","description":"","filename":"manuscript.pdf","url":"https://assets-eu.researchsquare.com/files/rs-6121673/v1/a1c4b6b6-2ebe-4f48-b342-f183f03f434c.pdf"}],"financialInterests":"No competing interests reported.","formattedTitle":"A Study on the Miscibility Mechanisms and Patterns of High CO2 Content Associated Gas Reinjection","fulltext":[{"header":"Introduction","content":"\u003cp\u003eIn the context of the \"Dual Carbon\" era, carbon capture, utilization, and storage (CCUS) has become a key focus. Currently, the use of CO\u003csub\u003e2\u003c/sub\u003e flooding technology for oil recovery has become increasingly mature in various oilfields.\u003c/p\u003e \u003cp\u003eDuring reservoir exploitation, oil wells produce both crude oil and associated gas. Due to the severe reservoir heterogeneity caused by Chinese sedimentary environments and the issue of CO\u003csub\u003e2\u003c/sub\u003e gas breakthrough in the later stages of development, the CO\u003csub\u003e2\u003c/sub\u003e content in associated gas increases sharply. This hinders the efficient utilization of CO\u003csub\u003e2\u003c/sub\u003e and its effective sequestration in the reservoir \u003csup\u003e\u003cspan additionalcitationids=\"CR2\" citationid=\"CR1\" class=\"CitationRef\"\u003e1\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR3\" class=\"CitationRef\"\u003e3\u003c/span\u003e\u003c/sup\u003e.After the crude oil is extracted, the oil and gas enter the metering station through the oil pipeline. Following processing through a buffer tank, separator, booster pump, and other equipment, the CO\u003csub\u003e2\u003c/sub\u003e content in the associated gas increases further\u003csup\u003e\u003cspan additionalcitationids=\"CR5\" citationid=\"CR4\" class=\"CitationRef\"\u003e4\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR6\" class=\"CitationRef\"\u003e6\u003c/span\u003e\u003c/sup\u003e. The combustion of associated gas with high CO\u003csub\u003e2\u003c/sub\u003e content cannot meet the required calorific value. Purifying the CO\u003csub\u003e2\u003c/sub\u003e through physical or chemical adsorption methods for further use increases costs, adds complexity to the process, and reduces production efficiency \u003csup\u003e\u003cspan additionalcitationids=\"CR8\" citationid=\"CR7\" class=\"CitationRef\"\u003e7\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR9\" class=\"CitationRef\"\u003e9\u003c/span\u003e\u003c/sup\u003e. However, reinjecting such high-CO\u003csub\u003e2\u003c/sub\u003e-content associated gas directly into the reservoir for enhanced oil recovery can achieve both economic benefits and environmental compliance.\u003c/p\u003e \u003cp\u003eThe Weyburn Oilfield in Canada is the largest CO\u003csub\u003e2\u003c/sub\u003e flooding demonstration project to date. Since 2000, 1\u0026nbsp;million tons of CO\u003csub\u003e2\u003c/sub\u003e have been injected annually for enhanced oil recovery. In 2010, the oilfield began researching associated gas reinjection, and currently, the reinjected CO\u003csub\u003e2\u003c/sub\u003e accounts for 50% of the total injection volume\u003csup\u003e\u003cspan citationid=\"CR10\" class=\"CitationRef\"\u003e10\u003c/span\u003e,\u003cspan citationid=\"CR11\" class=\"CitationRef\"\u003e11\u003c/span\u003e\u003c/sup\u003e. In recent years, there has been a significant amount of research on associated gas reinjection\u003csup\u003e\u003cspan citationid=\"CR12\" class=\"CitationRef\"\u003e12\u003c/span\u003e\u003c/sup\u003e, Kun Su et al.\u003csup\u003e\u003cspan citationid=\"CR13\" class=\"CitationRef\"\u003e13\u003c/span\u003e\u003c/sup\u003e used numerical simulation methods to study the effect of direct associated gas reinjection in the Jilin Oilfield and found that it could further enhance oil recovery. S.L. Yang et al.\u003csup\u003e\u003cspan citationid=\"CR14\" class=\"CitationRef\"\u003e14\u003c/span\u003e\u003c/sup\u003e conducted a full-component analysis of crude oil produced at different stages and found that the proportion of each component in the produced oil before gas breakthrough was similar to that in the initial crude oil. After gas breakthrough, the proportion of light components in the produced oil gradually increased. When the CO\u003csub\u003e2\u003c/sub\u003e concentration in the reinjected gas was less than 25%, the component changes in the produced crude oil were not significant.\u003c/p\u003e \u003cp\u003eRich gas, an important component of associated gas, contributes to enhanced oil recovery \u003csup\u003e\u003cspan citationid=\"CR15\" class=\"CitationRef\"\u003e15\u003c/span\u003e\u003c/sup\u003e.The United States and Canada were among the first to conduct field trials of injecting rich gas to enhance oil recovery\u003csup\u003e\u003cspan additionalcitationids=\"CR17\" citationid=\"CR16\" class=\"CitationRef\"\u003e16\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR18\" class=\"CitationRef\"\u003e18\u003c/span\u003e\u003c/sup\u003e.The former Soviet Union successfully applied the alternating water-gas injection technique in the North Sea Oilfield\u003csup\u003e\u003cspan citationid=\"CR19\" class=\"CitationRef\"\u003e19\u003c/span\u003e,\u003cspan citationid=\"CR20\" class=\"CitationRef\"\u003e20\u003c/span\u003e\u003c/sup\u003e.Venezuela once implemented the largest natural gas injection project for enhanced oil recovery in the world\u003csup\u003e\u003cspan citationid=\"CR21\" class=\"CitationRef\"\u003e21\u003c/span\u003e\u003c/sup\u003e.As early as the 1980s,CHEN et al\u003csup\u003e\u003cspan citationid=\"CR22\" class=\"CitationRef\"\u003e22\u003c/span\u003e\u003c/sup\u003estudied the impact of solvent slug size on oil recovery efficiency in rich gas miscible flooding and establishing a slug size calculation model considering multiple factors. GLASO\u003csup\u003e\u003cspan citationid=\"CR23\" class=\"CitationRef\"\u003e23\u003c/span\u003e\u003c/sup\u003eproposed a relationship equation for predicting the minimum miscibility pressure between rich gas and crude oil. SHYEH-YUNG\u003csup\u003e\u003cspan citationid=\"CR24\" class=\"CitationRef\"\u003e24\u003c/span\u003e\u003c/sup\u003estudied the impact of the components of enriched gas and injection pressure on displacement efficiency. Regarding the reinjection of enriched associated gas, Hoffman et al.\u003csup\u003e\u003cspan citationid=\"CR25\" class=\"CitationRef\"\u003e25\u003c/span\u003e\u003c/sup\u003e investigated gas injection for enhanced oil recovery in the Elm Coulee shale reservoir under both miscible and immiscible conditions using numerical simulation. Their comparison revealed that rich gas injection could further improve the recovery factor. Tao Wan et al.\u003csup\u003e\u003cspan citationid=\"CR26\" class=\"CitationRef\"\u003e26\u003c/span\u003e\u003c/sup\u003e focused on the Eagle Ford Shale as their study subject, accounting for uncertainties in oil composition changes. They developed a geological model using a stable black oil model and, based on this, used commercial simulation software to model cyclic rich gas injection, optimizing the injection strategy to further enhance the recovery factor. Morteza Akbarabadi\u003csup\u003e\u003cspan citationid=\"CR27\" class=\"CitationRef\"\u003e27\u003c/span\u003e\u003c/sup\u003e demonstrated through core displacement experiments that hydrocarbon gases co-produced with crude oil play a significant role in enhancing oil recovery. Ala Eddine Aoun et al.\u003csup\u003e\u003cspan citationid=\"CR28\" class=\"CitationRef\"\u003e28\u003c/span\u003e\u003c/sup\u003e taking into account the field conditions of the Bakken reservoir, proposed an alternating injection scheme of associated gas at a rate of 3MMcfd, considering capital expenditure, operational costs, and oil revenue. Their calculations indicated that this approach could potentially increase oil production by 70%.GF Sancet\u003csup\u003e\u003cspan citationid=\"CR29\" class=\"CitationRef\"\u003e29\u003c/span\u003e\u003c/sup\u003e. Progress has also been reported in recent years at many other oilfields all over the world\u003csup\u003e\u003cspan additionalcitationids=\"CR31\" citationid=\"CR30\" class=\"CitationRef\"\u003e30\u003c/span\u003e\u0026ndash;\u003cspan citationid=\"CR32\" class=\"CitationRef\"\u003e32\u003c/span\u003e\u003c/sup\u003e.\u003c/p\u003e \u003cp\u003eResearchers have conducted extensive studies on associated gas reinjection, but there is still a lack of research on the production dynamics after reinjecting high-CO\u003csub\u003e2\u003c/sub\u003e associated gas, the changes in MMP between associated gas and crude oil, and the oil recovery efficiency of associated gas and treated associated gas. Therefore, further investigation into the feasibility of reinjecting high-CO\u003csub\u003e2\u003c/sub\u003e associated gas and the changes in MMP after reinjection with different CO\u003csub\u003e2\u003c/sub\u003e concentrations is of great significance for field operations in oilfields.\u003c/p\u003e \u003cp\u003eThe H block of the Jilin oilfield has a reservoir depth of 2450 meters, a porosity ranging from 8\u0026ndash;15%, and strong heterogeneity. To maintain reservoir pressure and well productivity, CO\u003csub\u003e2\u003c/sub\u003e injection was initially employed, followed by water injection in the later stages of reservoir development. Currently, the H block is in the late phase of gas injection, with a reservoir pressure of 21 MPa, a reservoir temperature of 94.7\u0026deg;C, and crude oil properties including a viscosity of 1.79mPa\u0026middot;s, a saturation pressure of 8.62 MPa, and a formation volume factor of 1.152 at 21 MPa. The gas-oil ratio is 35 under standard conditions. The CO\u003csub\u003e2\u003c/sub\u003e content in the associated gas remains relatively stable and high, making further CO\u003csub\u003e2\u003c/sub\u003e injection less effective for both enhanced oil recovery and long-term storage.\u003c/p\u003e \u003cp\u003eTherefore, in this study, based on the current reservoir conditions, laboratory experiments were appropriately simplified. Slim tube tests were conducted using CO\u003csub\u003e2\u003c/sub\u003e and associated gases with varying CO\u003csub\u003e2\u003c/sub\u003e concentrations to measure the MMP (Minimum Miscibility Pressure) between crude oil and associated gases with different CO\u003csub\u003e2\u003c/sub\u003e concentrations. Supplemented by gas injection expansion experiments and solubility of different injected gases determination in crude oil to study the changes in physical properties of crude oil after gas injection. The study specifically focuses on research related to the reinjection of associated gas, providing valuable reference data for field operations in the oilfield.\u003c/p\u003e"},{"header":"Experimental","content":"\u003cdiv id=\"Sec3\" class=\"Section2\"\u003e\n \u003ch2\u003eMaterials\u003c/h2\u003e\n \u003cp\u003eIn the experiment, a coiled sand-packed slim tube with a length of 15 meters and a diameter of 4 mm was selected. The pore volume of the tube was 86.249 cm\u0026sup3;, with a porosity of 45.76% and a permeability of 4860mD. The crude oil used in the experiment was degassed oil sourced from Block H of Jilin oilfield, which was reconstituted into formation oil in the laboratory. The composition of the well stream fluids and the dissolved gas data are shown in Table\u0026nbsp;1. The different associated gases used in the experiment were synthesized by mixing CO\u003csub\u003e2\u003c/sub\u003e, CH\u003csub\u003e4\u003c/sub\u003e, C\u003csub\u003e2\u003c/sub\u003e-C\u003csub\u003e4\u003c/sub\u003e, and liquid C\u003csub\u003e5\u003c/sub\u003e and C\u003csub\u003e6\u003c/sub\u003e, with CO\u003csub\u003e2\u003c/sub\u003e molar ratios of 90%, 80%, 70%, and 60%, while maintaining the proportions of the other components constant. On this basis, CO\u003csub\u003e2\u003c/sub\u003e\u0026thinsp;+\u0026thinsp;CH\u003csub\u003e4\u003c/sub\u003e mixtures with different CO\u003csub\u003e2\u003c/sub\u003e molar ratios and associated gases with CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e removed were also prepared. The composition of the well stream fluids and dissolved gas is presented in Table 1, and the composition of associated gases with varying CO\u003csub\u003e2\u003c/sub\u003e concentrations is shown in Table 2.\u003c/p\u003e\n \u003cp\u003e\u003cstrong\u003eTable.1 Composition of well fluids and dissolved gas.\u003c/strong\u003e\u003c/p\u003e\n \u003ctable id=\"Taba\" border=\"1\"\u003e\n \u003cthead\u003e\n \u003ctr\u003e\n \u003cth align=\"left\" rowspan=\"2\"\u003e\n \u003cp\u003eFluid types\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\" colspan=\"11\"\u003e\n \u003cp\u003eMolar composition of components /%\u003c/p\u003e\n \u003c/th\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eN\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eC\u003csub\u003e1\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eC\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eC\u003csub\u003e3\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eiC\u003csub\u003e4\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003enC\u003csub\u003e4\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eiC\u003csub\u003e5\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003enC\u003csub\u003e5\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eC\u003csub\u003e6\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eC\u003csub\u003e7\u003c/sub\u003e+\u003c/p\u003e\n \u003c/th\u003e\n \u003c/tr\u003e\n \u003c/thead\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003eWell fluid\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e1.59\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.19\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e17.36\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e3.78\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e2.43\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.46\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e1.27\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.60\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e1.39\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e3.78\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003e67.15\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003eDissolved gas\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e6.01\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.72\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e66.44\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e13.55\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e7.18\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.96\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e2.24\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.54\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.99\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e1.24\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003e0\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n \u003cbr\u003e\n \u003cp\u003e\u003cstrong\u003eTable.2 Formulation data of associated gas.\u003c/strong\u003e\u003c/p\u003e\n \u003ctable id=\"Tabb\" border=\"1\"\u003e\n \u003cthead\u003e\n \u003ctr\u003e\n \u003cth align=\"left\" rowspan=\"2\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e concentration/%\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\" colspan=\"10\"\u003e\n \u003cp\u003eProportions of components/%\u003c/p\u003e\n \u003c/th\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eN\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eC\u003csub\u003e1\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eC\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eC\u003csub\u003e3\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eiC\u003csub\u003e4\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003enC\u003csub\u003e4\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eiC\u003csub\u003e5\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003enC\u003csub\u003e5\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eC\u003csub\u003e6\u003c/sub\u003e\u003c/p\u003e\n \u003c/th\u003e\n \u003c/tr\u003e\n \u003c/thead\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003e90\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e1.484\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e90\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e5.457\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e1.659\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.999\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.098\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.205\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.031\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.047\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.020\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003e80\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e2.969\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e80\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e10.914\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e3.317\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e1.998\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.195\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.409\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.061\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.095\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.041\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003e70\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e4.454\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e70\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e16.371\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e4.976\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e2.998\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.293\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.614\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.092\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.142\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.061\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003e60\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e5.939\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e60\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e21.828\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e6.635\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e3.997\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.390\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.819\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.122\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.190\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.081\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n \u003cbr\u003e\n\u003c/div\u003e\n\u003ch3\u003eDetermination of solubility of different gases in crude oil\u003c/h3\u003e\n\u003cp\u003eA certain mass of crude oil with an initial volume \u003cem\u003eV\u003c/em\u003e\u003csub\u003e\u003cem\u003e0\u003c/em\u003e\u003c/sub\u003e is injected into a high-temperature and high-pressure reactor. The gas to be measured is then introduced into the reactor until a certain pressure is reached. The release valve is opened to expel the air inside the apparatus. The target gas is further introduced, and when the pressure in the reactor reaches the set level, the inlet is closed. The experimental temperature is set, and heating and stirring are initiated. The pressure in the reactor is recorded at 20-minute intervals. Equilibrium is considered achieved when the recorded pressure remains constant over three consecutive readings, which is noted as the equilibrium pressure. The schematic diagram of the experimental apparatus used is illustrated in Fig. 1.\u003c/p\u003e\n\u003cp\u003eThe solubility of the gas in crude oil is expressed as the amount of gas (in moles) dissolved per kilogram of crude oil\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e33\u003c/span\u003e,\u003cspan class=\"CitationRef\"\u003e34\u003c/span\u003e\u003c/sup\u003e. This value is calculated by subtracting the amount of gas remaining at equilibrium from the initial amount of injected gas:\u003c/p\u003e\n\u003cdiv id=\"Equ1\" class=\"Equation\"\u003e\n \u003cdiv class=\"mathdisplay\" id=\"FileID_Equ1\" name=\"EquationSource\"\u003e$$\\:X=\\frac{{n}_{0}-{n}_{1}}{m}$$\u003c/div\u003e\n\u003c/div\u003e\n\u003cp\u003e(1)\u003c/p\u003e\n\u003cp\u003e\u003cem\u003en\u003c/em\u003e \u003csub\u003e\u0026nbsp;\u003cem\u003e0\u003c/em\u003e\u0026nbsp;\u003c/sub\u003e and \u003cem\u003en\u003c/em\u003e\u003csub\u003e\u003cem\u003e1\u003c/em\u003e\u003c/sub\u003e are calculated using the ideal gas equation:\u003c/p\u003e\n\u003cdiv id=\"Equ2\" class=\"Equation\"\u003e\n \u003cdiv class=\"mathdisplay\" id=\"FileID_Equ2\" name=\"EquationSource\"\u003e$$\\:{n}_{0}=\\frac{{p}_{0}(V-{V}_{0})}{{Z}_{0}RT}$$\u003c/div\u003e\u003c/div\u003e\u003cp\u003e(2)\u003c/p\u003e\u003cdiv id=\"Equ3\" class=\"Equation\"\u003e\u003cdiv class=\"mathdisplay\" id=\"FileID_Equ3\" name=\"EquationSource\"\u003e$$\\:{n}_{1}=\\frac{{p}_{1}(V-{V}_{1})}{{Z}_{1}RT}$$\u003c/div\u003e\u003c/div\u003e\u003cp\u003e(3)\u003c/p\u003e\u003cp\u003eWhere:\u003c/p\u003e\u003cp\u003e\u003cem\u003eX\u003c/em\u003e is the solubility of the gas in oil(mol/kg),\u003c/p\u003e\u003cp\u003e\u003cem\u003en\u003c/em\u003e \u003csub\u003e\u0026nbsp;\u003cem\u003e0\u003c/em\u003e\u0026nbsp;\u003c/sub\u003e and \u003cem\u003en\u003c/em\u003e\u003csub\u003e\u003cem\u003e1\u003c/em\u003e\u003c/sub\u003e are the amounts of the injected gas in the gas phase at the initial and equilibrium states in mole,\u003c/p\u003e\u003cp\u003e\u003cem\u003em\u003c/em\u003e is the mass of the oil in grams,\u003c/p\u003e\u003cp\u003e\u003cem\u003ep\u003c/em\u003e \u003csub\u003e\u0026nbsp;\u003cem\u003e0\u003c/em\u003e\u0026nbsp;\u003c/sub\u003e and \u003cem\u003ep\u003c/em\u003e\u003csub\u003e\u003cem\u003e1\u003c/em\u003e\u003c/sub\u003e are the initial and equilibrium pressures inside the reactor in MPa,\u003c/p\u003e\u003cp\u003e\u003cem\u003eV i\u003c/em\u003es the effective volume of the reactor in m\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e3\u003c/span\u003e\u003c/sup\u003e,\u003c/p\u003e\u003cp\u003e\u003cem\u003eV\u003c/em\u003e \u003csub\u003e\u0026nbsp;\u003cem\u003e0\u003c/em\u003e\u0026nbsp;\u003c/sub\u003e is the volume of oil inside the reactor in m\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e3\u003c/span\u003e\u003c/sup\u003e,\u003c/p\u003e\u003cp\u003e\u003cem\u003eZ\u003c/em\u003e \u003csub\u003e\u0026nbsp;\u003cem\u003e0\u003c/em\u003e\u0026nbsp;\u003c/sub\u003e and \u003cem\u003eZ\u003c/em\u003e\u003csub\u003e\u003cem\u003e1\u003c/em\u003e\u003c/sub\u003e are the compressibility factors of the injected gas at the initial and equilibrium states,\u003c/p\u003e\u003cp\u003e\u003cem\u003eR\u003c/em\u003e is the universal gas constant (8.314 J/ mol\u0026middot;K),\u003c/p\u003e\u003cp\u003e\u003cem\u003eT\u003c/em\u003e is the temperature in Kelvin,\u003c/p\u003e\u003cp\u003eThe experiment measured the solubility of CO\u003csub\u003e2\u003c/sub\u003e, associated gas with varying CO\u003csub\u003e2\u003c/sub\u003e concentrations, and associated gas with CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e removed in crude oil under different pressure conditions at the reservoir temperature of 94.7\u0026deg;C.\u003c/p\u003e\u003ch3\u003eSwelling test\u003c/h3\u003e\u003cp\u003eTo investigate the effect of injected gas on crude oil properties and further explore the miscibility mechanism, experiments were conducted at reservoir temperature and pressure conditions. CO\u003csub\u003e2\u003c/sub\u003e, associated gas with 60% CO\u003csub\u003e2\u003c/sub\u003e concentration, and associated gas with 60% CO\u003csub\u003e2\u003c/sub\u003e concentration after removing CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e were sequentially injected into a PVT cell according to predetermined ratios\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e35\u003c/span\u003e\u003c/sup\u003e. After each injection of a specific gas proportion, pressure was gradually increased until the injected gas fully dissolved in the crude oil to form a single phase. After each gas injection, the high-pressure physical properties of the reservoir fluid undergo changes. By measuring the density, bubble point pressure, swelling factor, and viscosity after each injection, the impact of the injected gas on crude oil properties can be analyzed\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e36\u003c/span\u003e\u003c/sup\u003e. The experimental setup is illustrated in Fig. \u003cspan class=\"InternalRef\"\u003e2\u003c/span\u003e.\u003c/p\u003e\u003cp\u003eA 100 mL oil sample was placed into a visual reactor, and gas was injected into the container. The temperature was kept constant at 94.7\u0026deg;C. The pressure was gradually increased in steps of 1 MPa, bringing the internal pressure of the reactor sequentially to 3\u0026ndash;11 MPa. The mixture was stirred at a speed of 2000 r/min for 30 minutes. The liquid level of the oil sample inside the reactor\u0026rsquo;s visual window was recorded at each target pressure under 94.7\u0026deg;C, and the volume change of the oil sample before and after gas injection was calculated.\u003c/p\u003e\u003cp\u003eAfter sealing the reactor with 100 mL of oil, the temperature was raised to the target of 94.7\u0026deg;C. Different amounts of gas were injected, and the oil and gas were thoroughly mixed through agitation to ensure complete dissolution. A high-temperature, high-pressure viscometer was used to measure the viscosity and density of the oil sample after gas injection. The procedure was repeated to obtain the viscosity and density of the oil sample under different gas injection volumes.\u003c/p\u003e\u003ch3\u003eSlim tube test\u003c/h3\u003e\u003cp\u003eIn this experiment, the slim tube method is used to measure the minimum miscibility pressure (MMP) between the injected gas and crude oil\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e37\u003c/span\u003e,\u003cspan class=\"CitationRef\"\u003e38\u003c/span\u003e\u003c/sup\u003e. Before conducting the experiment, formation oil and gas samples should be prepared according to the formulation data\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e39\u003c/span\u003e\u003c/sup\u003e. The experimental process is shown in Fig. \u003cspan class=\"InternalRef\"\u003e3\u003c/span\u003e, and the specific steps are as follows:\u003c/p\u003e\u003cp\u003e\u003cstrong\u003eCleaning the slim tube\u003c/strong\u003e\u003c/p\u003e\u003cp\u003eBefore the experiment, thoroughly clean the capillary tube to ensure readiness. After cleaning (when the color of petroleum ether at the outlet no longer changes), use nitrogen gas to dry the tube and then use a vacuum pump to evacuate it.\u003c/p\u003e\u003cp\u003e\u003cstrong\u003eSaturating with dead oil\u003c/strong\u003e\u003c/p\u003e\u003cp\u003eUnder experimental temperature and pressure conditions, saturate the entire capillary tube with petroleum ether. Calculate the pore volume (based on the difference in pump position between the start and end under constant pressure mode). Then, use dead oil (or petroleum ether) to raise the system pressure to the experimental pressure.\u003c/p\u003e\u003cp\u003e\u003cstrong\u003eSaturating with live oil\u003c/strong\u003e\u003c/p\u003e\u003cp\u003eUnder experimental temperature and pressure conditions, use live oil with 2 times the pore volume to displace the dead oil. Calculate the gas-oil ratio at the capillary tube outlet. If this ratio is consistent with the gas-oil ratio of the live oil, saturation is complete.\u003c/p\u003e\u003cp\u003e\u003cstrong\u003eInjection experiment\u003c/strong\u003e\u003c/p\u003e\u003cp\u003eAdjust the inlet pressure to 0.05\u0026ndash;0.1 MPa above the experimental pressure. Once the pump position stabilizes, record the initial position. Using a constant speed method, inject gas at a speed of 0.1 cm\u0026sup3;/min to conduct the displacement experiment. Measure the amount of produced oil and gas, as well as the pump position, every 0.1 PV. Stop the displacement after a cumulative injection of 1.2 PV.\u003c/p\u003e\u003cp\u003e\u003cstrong\u003eVarying injection pressure\u003c/strong\u003e\u003c/p\u003e\u003cp\u003eChange the injection pressure while keeping the temperature constant, and measure the recovery factor at different injection pressures (while holding 1.2 PV constant). The pressure points are determined based on the recovery factor from the previous experiment, ensuring that there are at least 3 pressure points corresponding to recovery factors above and below 90%. Plot a scatter diagram of the recovery factor versus experimental pressure. Draw trend lines (straight lines) for the two pressure ranges. The intersection of the two trend lines corresponds to a recovery factor of MMP, and this pressure is considered the minimum miscibility pressure (MMP).\u003c/p\u003e"},{"header":"Result and discussion","content":"\u003cdiv id=\"Sec8\" class=\"Section2\"\u003e\n \u003ch2\u003eResearch on the miscible mechanism of associated gas reinjection\u003c/h2\u003e\n \u003cp\u003eSolubility of injected gas in crude oil\u003c/p\u003e\n \u003cp\u003eBased on the experimental data and Equations (\u003cspan class=\"InternalRef\"\u003e1\u003c/span\u003e) to (4), the solubility of different injected gases in crude oil under reservoir conditions was calculated. The results are shown in Table\u0026nbsp;3.\u003c/p\u003e\n \u003cp\u003e\u003cstrong\u003eTable.3 The solubility of different gas in oil\u003c/strong\u003e\u003c/p\u003e\n \u003cdiv class=\"gridtable\"\u003e\u0026nbsp;\u003ctable id=\"Tabd\" border=\"1\"\u003e\n \u003cthead\u003e\n \u003ctr\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eType of gas\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eTemperature/℃\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003ePressure/MPa\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e concentration/%\u003c/p\u003e\n \u003c/th\u003e\n \u003cth align=\"left\"\u003e\n \u003cp\u003eSolubility(mol/kg)\u003c/p\u003e\n \u003c/th\u003e\n \u003c/tr\u003e\n \u003c/thead\u003e\n \u003ctbody\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\" rowspan=\"3\"\u003e\n \u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003e94.7\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e5\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e100\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.138\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003e94.7\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e6\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e100\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.482\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\"\u003e\n \u003cp\u003e60\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e5\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e100\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.186\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\" rowspan=\"4\"\u003e\n \u003cp\u003eAssociated gas\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"left\" rowspan=\"4\"\u003e\n \u003cp\u003e94.7\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\" rowspan=\"4\"\u003e\n \u003cp\u003e5\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e90\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.128\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e80\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.114\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e70\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.104\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e60\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.092\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"left\" rowspan=\"4\"\u003e\n \u003cp\u003eAssociated gas without CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"left\" rowspan=\"4\"\u003e\n \u003cp\u003e94.7\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\" rowspan=\"4\"\u003e\n \u003cp\u003e5\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e90\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.145\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e80\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.243\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e70\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.345\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003ctr\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e60\u003c/p\u003e\n \u003c/td\u003e\n \u003ctd align=\"char\"\u003e\n \u003cp\u003e0.444\u003c/p\u003e\n \u003c/td\u003e\n \u003c/tr\u003e\n \u003c/tbody\u003e\n \u003c/table\u003e\n \u003c/div\u003e\n \u003cbr\u003e\n \u003cp\u003eThe experimental results indicate that, at a constant temperature, the solubility of the gas increases with an increase in initial pressure. Conversely, when the initial pressure remains constant, raising the temperature reduces the oil\u0026apos;s ability to dissolve the gas. This phenomenon suggests that increasing the injection pressure can enhance gas dissolution into the oil, thereby facilitating a range of effects that promote oil flow. The solubility of associated gas in oil is slightly lower than that of CO\u003csub\u003e2\u003c/sub\u003e, whereas the removal of CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e from the gas allows for even greater solubility in the oil.\u003c/p\u003e\n \u003cp\u003eAnalysis of crude oil gas injection expansion experiments\u003c/p\u003e\n \u003cp\u003eThrough the swelling test, the physical property changes of crude oil after gas injection were analyzed to study the miscible mechanism of associated gas reinjection. After gas injection, the crude oil density showed minimal change, viscosity decreased, and both saturation pressure and expansion coefficient increased. Figure 4 show the result of this experiment:\u003c/p\u003e\n \u003cp\u003e(1) Density: Although gas dissolving into crude oil reduces its density, the compression of crude oil during the pressurization process after gas injection leads to a density increase. Therefore, as the amount of injected gas increases, the crude oil density shows an upward trend, but the maximum increase is only 0.008 g/cm\u0026sup3;. Additionally, associated gas with N\u003csub\u003e2\u003c/sub\u003e and CH\u003csub\u003e4\u003c/sub\u003e removed performs better in reducing the crude oil density.\u003c/p\u003e\n \u003cp\u003e(2)Viscosity: Gas injection leads to a significant reduction in crude oil viscosity. The effectiveness of viscosity reduction follows the order: associated gas without N\u003csub\u003e2\u003c/sub\u003e and CH\u003csub\u003e4\u003c/sub\u003e\u0026thinsp;\u0026gt;\u0026thinsp;CO\u003csub\u003e2\u003c/sub\u003e\u0026thinsp;\u0026gt;\u0026thinsp;raw associated gas. Injecting associated gas without N\u003csub\u003e2\u003c/sub\u003e and CH\u003csub\u003e4\u003c/sub\u003e decreases viscosity from 1.79 mPa\u0026middot;s to 0.92 mPa\u0026middot;s, a 48.6% reduction (Fig. 4b). This is due to CO\u003csub\u003e2\u003c/sub\u003e dissolving in heavy oil, disrupting colloid and asphaltene structures, and reducing molecular interactions. Hydrocarbons in the purified associated gas further enhance this effect.\u003c/p\u003e\n \u003cp\u003e(3)Saturation Pressure: After gas injection, crude oil saturation pressure increases. CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e in the associated gas inhibit gas solubility in oil, while the hydrocarbons dissolve more readily, leading to the observed trends in Fig. 4c. After dissolving 51.9 m\u0026sup3;/m\u0026sup3; of gas, the saturation pressure for CO\u003csub\u003e2\u003c/sub\u003e, raw associated gas, and treated associated gas rose to 25.359 MPa, 22.733 MPa, and 19.362 MPa, respectively.\u003c/p\u003e\n \u003cp\u003e(4)Expansion Coefficient: The expansion coefficient reflects the extent of crude oil volume expansion due to gas dissolution during injection. As shown in Fig.\u0026nbsp;4d, the treated associated gas exhibits a more pronounced expansion effect. When the gas injection volume reaches 51.9 m\u0026sup3;/m\u0026sup3;, the expansion coefficient of the crude oil reaches 1.39.\u003c/p\u003e\n \u003cp\u003eThe experimental results indicate that after CO\u003csub\u003e2\u003c/sub\u003e injection, crude oil experiences volume expansion and increased bubble point pressure, enhancing its elastic properties in the reservoir. This is consistent with the analytical results of other scholars\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e40\u003c/span\u003e,\u003cspan class=\"CitationRef\"\u003e41\u003c/span\u003e\u003c/sup\u003e. Simultaneously, the viscosity decreases, improving oil mobility and facilitating displacement. Injecting associated gas with 60% CO\u003csub\u003e2\u003c/sub\u003e content shows slightly weaker expansion and viscosity reduction effects compared to CO\u003csub\u003e2\u003c/sub\u003e alone. However, after removing N\u003csub\u003e2\u003c/sub\u003e and CH\u003csub\u003e4\u003c/sub\u003e from the associated gas, it performs even better than pure CO\u003csub\u003e2\u003c/sub\u003e.\u003c/p\u003e\n\u003c/div\u003e\n\u003ch3\u003eResults of the slim tube test\u003c/h3\u003e\n\u003cp\u003eProduction dynamics of associated gas reinjection\u003c/p\u003e\n\u003cp\u003eIn the slim-tube displacement experiment, oil and gas production rates were recorded at each 0.1 PV gas injection increment until reaching 1.2 PV. The recovery factor and gas-oil ratio (GOR) for each stage were calculated. Figure\u0026nbsp;5 shows the GOR, stage recovery factor, MMP determination curve and the non-miscible state through the viewing window for associated gas with 90% CO\u003csub\u003e2\u003c/sub\u003e content at various injection pressures. Results indicate that recovery factor increases with injected volume, rising rapidly before 0.9 PV. In the early injection phase (before 0.4 PV), lower injection pressures yield faster growth, with a growth rate of approximately 9.3% per 0.1 PV at 21 MPa. The GOR for each injection pressure significantly increases after 0.9 PV, reaching its peak at 1.2 PV. Similar production patterns were observed for associated gases with different CO\u003csub\u003e2\u003c/sub\u003e concentrations.\u003c/p\u003e\n\u003cp\u003eThe analysis of experimental results indicates that, prior to breakthrough, the recovery factor in associated gas flooding rises rapidly with increasing injection volume. This effect is especially pronounced at lower injection pressures, where recovery increases more quickly in the early stages. This is because, when the injection pressure is below the MMP, CO\u003csub\u003e2\u003c/sub\u003e struggles to mix with the crude oil, and the displacement process resembles immiscible displacement. However, lower injection pressures lead to lower recovery rates in the later stages. The main reason is that CO\u003csub\u003e2\u003c/sub\u003e creates a preferential flow channel after displacing some pore oil, causing most of the injected CO\u003csub\u003e2\u003c/sub\u003e to flow along this channel, which results in a sharp rise in the gas-oil ratio\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e42\u003c/span\u003e\u003c/sup\u003e. Consequently, the oil in other pore spaces is less likely to be displaced by CO\u003csub\u003e2\u003c/sub\u003e, leading to lower ultimate recovery at low injection pressures\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e43\u003c/span\u003e\u003c/sup\u003e.\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eInfluence of Associated Gas Reinjection on Minimum Miscibility Pressure\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eExploring the influence of associated gas reinjection on the Minimum Miscibility Pressure (MMP), as well as the mechanisms by which each component in the associated gas affects MMP, is valuable for predicting field recovery rates. Using the slim tube method, the MMP of associated gases with varying CO\u003csub\u003e2\u003c/sub\u003e contents, CO\u003csub\u003e2\u003c/sub\u003e\u0026thinsp;+\u0026thinsp;CH\u003csub\u003e4\u003c/sub\u003e mixtures, and associated gases with CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e removed was determined with crude oil. The corresponding trends in MMP with changes in injected gas composition were analyzed.\u003c/p\u003e\n\u003cp\u003eThe relationship curve between MMP and CO\u003csub\u003e2\u003c/sub\u003e concentration in the injected gas with crude oil is plotted in Fig. \u003cspan class=\"InternalRef\"\u003e6\u003c/span\u003e. Results indicate that MMP shows a strong linear correlation with the CO\u003csub\u003e2\u003c/sub\u003e concentration in the injected gas, which has correlation coefficients above 0.97. When CH\u003csub\u003e4\u003c/sub\u003e is present in the injected gas, MMP increases as the CO\u003csub\u003e2\u003c/sub\u003e content decreases. For every 10% decrease in CO\u003csub\u003e2\u003c/sub\u003e concentration in the associated gas, MMP rises by 0.937 MPa, reaching 27.94 MPa when the CO\u003csub\u003e2\u003c/sub\u003e concentration is relatively low (60%). The MMP of the CO\u003csub\u003e2\u003c/sub\u003e\u0026thinsp;+\u0026thinsp;CH\u003csub\u003e4\u003c/sub\u003e mixture rises even more rapidly, being 3.07 MPa higher than that of the associated gas at a 60% CO\u003csub\u003e2\u003c/sub\u003e concentration. Conversely, the MMP behavior of the associated gas without CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e shows a different trend, with MMP decreasing by 2.469 MPa for every 10% reduction in CO\u003csub\u003e2\u003c/sub\u003e concentration. This modified associated gas remains miscible with crude oil even at low CO\u003csub\u003e2\u003c/sub\u003e concentrations, achieving an MMP of only 14.53 MPa at a 60% CO\u003csub\u003e2\u003c/sub\u003e level.\u003c/p\u003e\n\u003cp\u003eThe presence of methane or nitrogen increases the minimum miscibility pressure (MMP) of CO\u003csub\u003e2\u003c/sub\u003e flooding, with nitrogen having a greater effect than methane. Removing CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e effectively reduces MMP. When these gases are removed from associated gas, the remaining components, apart from CO\u003csub\u003e2\u003c/sub\u003e, are light fractions of crude oil, which enhances miscibility with crude oil. This results in the curve being lower than the one for associated gas reinjection\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e44\u003c/span\u003e,\u003cspan class=\"CitationRef\"\u003e45\u003c/span\u003e\u003c/sup\u003e. As the CO\u003csub\u003e2\u003c/sub\u003e concentration decreases, the proportion of other components that promote miscibility increases, leading to a reduction in MMP as CO\u003csub\u003e2\u003c/sub\u003e concentration decreases\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e24\u003c/span\u003e,\u003cspan class=\"CitationRef\"\u003e46\u003c/span\u003e\u003c/sup\u003e.\u003c/p\u003e\n\u003cp\u003e\u003cstrong\u003eOil displacement efficiency of associated gas\u003c/strong\u003e\u003c/p\u003e\n\u003cp\u003eTo evaluate the oil displacement capacity of associated gas, the recovery factor was calculated after injecting associated gas with different CO\u003csub\u003e2\u003c/sub\u003e concentrations up to 1.2 PV into a slim tube at reservoir pressure (21 MPa), and compared with that of pure CO\u003csub\u003e2\u003c/sub\u003e injection under the same conditions. The results are shown in Fig. \u003cspan class=\"InternalRef\"\u003e7\u003c/span\u003e. It can be seen that, at the current reservoir pressure, which is significantly lower than the CO\u003csub\u003e2\u003c/sub\u003e-oil MMP, the efficiency of CO\u003csub\u003e2\u003c/sub\u003e flooding is below 90%. The oil displacement efficiency of associated gas reinjection is lower than that of pure CO\u003csub\u003e2\u003c/sub\u003e, and at reservoir pressure, the lower the CO\u003csub\u003e2\u003c/sub\u003e concentration in the associated gas, the lower the displacement efficiency. With an associated gas containing 60% CO\u003csub\u003e2\u003c/sub\u003e, the displacement efficiency was reduced by 7.92% compared to pure CO\u003csub\u003e2\u003c/sub\u003e.\u003c/p\u003e\n\u003cp\u003eThe low oil displacement efficiency of associated gas is mainly due to the presence of CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e in its composition compares the oil displacement efficiency of direct associated gas reinjection with that of purified associated gas (with CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e removed). The comparison shows a significant improvement in oil displacement efficiency after removing CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e impurities, resulting in a near-miscible to miscible displacement state. When the CO\u003csub\u003e2\u003c/sub\u003e concentration is 90%, the displacement efficiency increases by 14.39%. As the displacement efficiency of associated gas is positively correlated with its CO\u003csub\u003e2\u003c/sub\u003e concentration, while purified associated gas exhibits an inverse relationship, removing CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e can achieve a greater efficiency improvement at lower CO\u003csub\u003e2\u003c/sub\u003e concentrations. For instance, at 60% CO\u003csub\u003e2\u003c/sub\u003e concentration, the oil displacement efficiency of purified associated gas is enhanced by 25.59%.\u003c/p\u003e\n\u003cp\u003eIt is undeniable that purifying CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e also incurs costs\u003csup\u003e\u003cspan class=\"CitationRef\"\u003e47\u003c/span\u003e\u003c/sup\u003e. Therefore, while aiming to improve recovery rates, a balance should be struck between the investment costs and the benefits. Achieving effective CO\u003csub\u003e2\u003c/sub\u003e sequestration alongside maximizing profitability will be a critical focus for future research.\u003c/p\u003e"},{"header":"Conclusion","content":"\u003cp\u003e(1)Lowering the temperature and increasing the pressure both enhance the dissolution of CO\u003csub\u003e2\u003c/sub\u003e into crude oil. Compared to CO\u003csub\u003e2\u003c/sub\u003e, associated gas is less soluble in crude oil. Under conditions of 94.7\u0026deg;C and 5 MPa, the solubility of CO\u003csub\u003e2\u003c/sub\u003e in crude oil is 1.07 to 1.5 times that of associated gas. Removing CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e significantly enhances the solubility of associated gas, making it 1.05 to 3.22 times higher than that of CO\u003csub\u003e2\u003c/sub\u003e. The injection of CO\u003csub\u003e2\u003c/sub\u003e or associated gas can reduce crude oil viscosity and increase the expansion energy of fluids in the reservoir. This effect becomes more pronounced with higher gas solubility. Therefore, CO\u003csub\u003e2\u003c/sub\u003e flooding or associated gas injection can further enhance oil recovery by optimizing the composition of the injected gas or incorporating solubility-enhancing agents.\u003c/p\u003e \u003cp\u003e(2)The CO\u003csub\u003e2\u003c/sub\u003e concentration in associated gas influences the minimum miscibility pressure (MMP): for every 10% decrease in CO\u003csub\u003e2\u003c/sub\u003e concentration, the MMP increases by 0.937 MPa. Methane (CH\u003csub\u003e4\u003c/sub\u003e) further raises the MMP, with each 10% increase in CH\u003csub\u003e4\u003c/sub\u003e in a CO\u003csub\u003e2\u003c/sub\u003e-CH\u003csub\u003e4\u003c/sub\u003e mixture resulting in an MMP increase of 1.688 MPa. Removing CH\u003csub\u003e4\u003c/sub\u003e and nitrogen (N\u003csub\u003e2\u003c/sub\u003e) from associated gas effectively reduces the MMP, with reductions ranging between 14.4% and 48.0%.Under the current reservoir pressure, pure CO\u003csub\u003e2\u003c/sub\u003e injection cannot achieve miscible displacement, and the oil recovery efficiency of associated gas reinjection is even lower than that of pure CO\u003csub\u003e2\u003c/sub\u003e injection. This efficiency gap increases as CO\u003csub\u003e2\u003c/sub\u003e concentration decreases, with a 7.92% reduction in recovery efficiency when using associated gas with 60% CO\u003csub\u003e2\u003c/sub\u003e compared to pure CO\u003csub\u003e2\u003c/sub\u003e. Removing CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e from associated gas enhances oil recovery efficiency, especially at lower CO\u003csub\u003e2\u003c/sub\u003e concentrations; for instance, associated gas with 60% CO\u003csub\u003e2\u003c/sub\u003e concentration and without CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e achieves a 25.59% increase in recovery efficiency.\u003c/p\u003e"},{"header":"Declarations","content":"\u003ch2\u003eAuthor Contribution\u003c/h2\u003e\u003cp\u003eYunfei Lei:Conceptualization,Visualization, Writing-original draft,Data curation, Experiment execution，Formal analysis.Changquan Wang:Methodology,Data curation, Writing-original draft,Project administration, Resources, Writing-review \u0026amp; editing.Shijin Xu:Investigation, Supervision, Writing-review \u0026amp; editing.Lihong Shi:Supervision, Writing-review \u0026amp; editing.Xinke Jin:Formal analysis,Experiment execution， Investigation.\u003c/p\u003e\u003ch2\u003eData Availability\u003c/h2\u003e\u003cp\u003eThe authors declare that, all data generated or analyzed during this study are included in this published article.\u003c/p\u003e"},{"header":"References","content":"\u003col\u003e\u003cli\u003e\u003cspan\u003eWang, H., Tian, L., Chai, X., Wang, J. \u0026amp; Zhang, K. 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Technol.\u003c/em\u003e \u003cb\u003e299\u003c/b\u003e, 121734 (2022).\u003c/span\u003e\u003c/li\u003e\u003c/ol\u003e"}],"fulltextSource":"","fullText":"","funders":[],"hasAdminPriorityOnWorkflow":false,"hasManuscriptDocX":true,"hasOptedInToPreprint":true,"hasPassedJournalQc":"","hasAnyPriority":false,"hideJournal":false,"highlight":"","institution":"","isAcceptedByJournal":true,"isAuthorSuppliedPdf":false,"isDeskRejected":"","isHiddenFromSearch":false,"isInQc":false,"isInWorkflow":false,"isPdf":false,"isPdfUpToDate":true,"isWithdrawnOrRetracted":false,"journal":{"display":true,"email":"[email protected]","identity":"scientific-reports","isNatureJournal":false,"hasQc":true,"allowDirectSubmit":false,"externalIdentity":"scirep","sideBox":"Learn more about [Scientific Reports](http://www.nature.com/srep/)","snPcode":"","submissionUrl":"","title":"Scientific Reports","twitterHandle":"","acdcEnabled":true,"dfaEnabled":true,"editorialSystem":"stoa","reportingPortfolio":"Scientific Reports","inReviewEnabled":true,"inReviewRevisionsEnabled":true},"keywords":"","lastPublishedDoi":"10.21203/rs.3.rs-6121673/v1","lastPublishedDoiUrl":"https://doi.org/10.21203/rs.3.rs-6121673/v1","license":{"name":"CC BY 4.0","url":"https://creativecommons.org/licenses/by/4.0/"},"manuscriptAbstract":"\u003cp\u003eTo investigate the enhanced oil recovery mechanisms during the reinjection of CO₂-rich associated gas, analyze the miscibility behavior between associated gas and crude oil, and provide guidance for further improving oil recovery in field development, this study conducted gas injection expansion experiments, solubility measurements of various gases in crude oil, and slim tube experiments. The experimental results demonstrated that CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e reduce the solubility of associated gas in crude oil, the solubility of associated gas without CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e in crude oil is 1.05 to 3.22 times that of CO\u003csub\u003e2\u003c/sub\u003ewhile their removal enables the solubility of associated gas in crude oil to surpass that of CO\u003csub\u003e2\u003c/sub\u003e. Both CO\u003csub\u003e2\u003c/sub\u003e and associated gas can cause crude oil to swell and reduce its viscosity, and the absence of CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e amplifies these effects. The minimum miscibility pressure (MMP) for CO\u003csub\u003e2\u003c/sub\u003e flooding is 24.29 MPa, while the reservoir pressure of 21 MPa is insufficient to achieve miscible flooding. Removing CH\u003csub\u003e4\u003c/sub\u003e and N\u003csub\u003e2\u003c/sub\u003e from the associated gas can reduce the MMP by up to 48%, resulting in a 25.59% improvement in oil recovery efficiency.\u003c/p\u003e","manuscriptTitle":"A Study on the Miscibility Mechanisms and Patterns of High CO2 Content Associated Gas Reinjection","msid":"","msnumber":"","nonDraftVersions":[{"code":1,"date":"2025-03-10 11:51:26","doi":"10.21203/rs.3.rs-6121673/v1","editorialEvents":[{"type":"communityComments","content":0},{"type":"decision","content":"Revision requested","date":"2025-03-31T15:58:38+00:00","index":"","fulltext":""},{"type":"editorInvitedReview","content":"","date":"2025-03-27T07:39:28+00:00","index":"hide","fulltext":""},{"type":"editorInvitedReview","content":"","date":"2025-03-20T20:12:36+00:00","index":"hide","fulltext":""},{"type":"reviewerAgreed","content":"127642940124807398848688703775885168146","date":"2025-03-18T14:00:21+00:00","index":"hide","fulltext":""},{"type":"reviewerAgreed","content":"209602291600212046516829696170911000128","date":"2025-03-15T18:58:50+00:00","index":"hide","fulltext":""},{"type":"reviewersInvited","content":"","date":"2025-03-15T18:55:26+00:00","index":"","fulltext":""},{"type":"editorAssigned","content":"","date":"2025-03-15T18:54:20+00:00","index":"","fulltext":""},{"type":"editorInvited","content":"","date":"2025-03-07T15:42:20+00:00","index":"","fulltext":""},{"type":"checksComplete","content":"","date":"2025-03-06T09:49:28+00:00","index":"","fulltext":""},{"type":"submitted","content":"Scientific Reports","date":"2025-02-27T13:52:28+00:00","index":"","fulltext":""}],"status":"published","journal":{"display":true,"email":"[email protected]","identity":"scientific-reports","isNatureJournal":false,"hasQc":true,"allowDirectSubmit":false,"externalIdentity":"scirep","sideBox":"Learn more about [Scientific Reports](http://www.nature.com/srep/)","snPcode":"","submissionUrl":"","title":"Scientific Reports","twitterHandle":"","acdcEnabled":true,"dfaEnabled":true,"editorialSystem":"stoa","reportingPortfolio":"Scientific Reports","inReviewEnabled":true,"inReviewRevisionsEnabled":true}}],"origin":"","ownerIdentity":"3e6e8d84-f9cd-4063-ba50-84aa674119fa","owner":[],"postedDate":"March 10th, 2025","published":true,"recentEditorialEvents":[],"rejectedJournal":[],"revision":"","amendment":"","status":"published-in-journal","subjectAreas":[{"id":45372218,"name":"Physical sciences/Energy science and technology/Carbon capture and storage"},{"id":45372219,"name":"Physical sciences/Energy science and technology/Fossil fuels/Crude oil"}],"tags":[],"updatedAt":"2025-08-25T16:40:22+00:00","versionOfRecord":{"articleIdentity":"rs-6121673","link":"https://doi.org/10.1038/s41598-025-15039-z","journal":{"identity":"scientific-reports","isVorOnly":false,"title":"Scientific Reports"},"publishedOn":"2025-08-19 16:29:32","publishedOnDateReadable":"August 19th, 2025"},"versionCreatedAt":"2025-03-10 11:51:26","video":"","vorDoi":"10.1038/s41598-025-15039-z","vorDoiUrl":"https://doi.org/10.1038/s41598-025-15039-z","workflowStages":[]},"version":"v1","identity":"rs-6121673","journalConfig":"researchsquare"},"__N_SSP":true},"page":"/article/[identity]/[[...version]]","query":{"redirect":"/article/rs-6121673","identity":"rs-6121673","version":["v1"]},"buildId":"XKTyCvWXoU3ODBz1xrDgd","isFallback":false,"isExperimentalCompile":false,"dynamicIds":[84888],"gssp":true,"scriptLoader":[]}