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. 2024 Jul 3;9(28):30131–30141. doi: 10.1021/acsomega.3c08088

Research on Component Variation and Factors Affecting Minimum Miscible Pressure in Low Viscosity Oil Miscibility Process

Kun Yang †, Shenglai Yang †,*, Jiangtao Hu †, Yumeng Gao †, Xinyue Liu †, Zhipeng Xiao ‡
PMCID: PMC11256103  PMID: 39035904

Abstract

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Miscible gas flooding is an important approach for enhancing the recovery of unconventional oil reservoirs. The injected gas and crude oil components has a significant impact on the minimum miscible pressure. In order to clarify the miscibility characteristics and factors influencing the minimum miscibility pressure, combining PVT and slim tube experiments, the minimum miscibility pressure between Tuha low viscosity oil and different injected gas was measured. Additionally, chromatography experiments were conducted to study the composition changes of produced oil. The results indicate that when the injection pressure is higher than the minimum miscible pressure, the extraction effect of injected gas on heavy fraction (C16+) in crude oil is enhanced and the extraction effect on light alkanes (C1–C6) is reduced. The increase in the content of light alkanes (C1–C6) and middle distillates (C7–C15) in crude oil reduces the minimum miscibility pressure between crude oil and injected gas. Pipeline gas can effectively extract heavy fraction from crude oil, but its breakthrough time is early. Under the same pressure, earlier breakthrough time of injected gas makes it more difficult for the crude oil and injected gas to miscible. Through the analysis of experimental results, the following main conclusions are drawn: Immiscible flooding causes heavy fraction (C16+) in crude oil to remain, which might affect the physical properties of the reservoir, increasing the difficulty of subsequent development. Gas fingering phenomenon significantly influences the miscibility of injected gas and crude oil, and the viscosity ratio of injected gas and crude oil under high-pressure conditions can be used as an important criterion for screening injected gas.

1. Introduction

Unconventional reservoirs are characterized by low porosity and permeability, small pore radius, and significant development challenges. Conventional depletion development methods often fail to achieve high recovery. Gas flooding is a widely used in the development of unconventional reservoirs, such as tight oil reservoirs and shale oil reservoirs,1,2 as gas molecules can enter small pores and improve reservoir sweep efficiency. In ultratight reservoirs, the mass exchange between injected gas and formation crude oil can improve the final recovery rate of the reservoir as gas molecules can enter small pores and improve reservoir sweep efficiency. In ultratight reservoirs that are challenging to flow, the mass exchange between injected gas and formation crude oil can improve the final recovery rate of the reservoir.3 Under high temperature and pressure conditions, gas and crude oil can easily form miscibility, resulting the disappearance of the interface between the two phases and significantly reducing the impact of capillary resistance on seepage. At the same time, CO2 has the effect of selling and viscosity reduction, reducing fluid flow resistance and improving oil recovery.

Miscible flooding has become an essential development method for unconventional oil reservoirs. Common miscible gases include CO2, liquefied petroleum gas, and rich gas. Among them, CO2 has a wide range of sources and low miscibility, making it widely used in oilfield miscible flooding.4,5 Additionally, pipeline gas in oilfield production processes is often used as a miscible gas for reservoir miscible development.

The minimum miscibility pressure is a critical indicator for evaluating the potential for achieving miscibility between injected gas and crude oil.6,7 Scholars have utilized various techniques to determine the minimum miscible pressure of crude oil and injected gas, including the slim tube method,8,9 empirical formula method,10,11 numerical simulation method,12−14 and artificial intelligence methods.15−18 The slim tube experiment utilizes the mass transfer of components between crude oil and injected fluid, allowing crude oil and injected fluid to repeatedly come into contact during the flow process, ultimately achieving miscibility. Despite its drawbacks such as being time-consuming and expensive, the slim tube method is the most common and widely recognized as the most accurate method for testing minimum miscible pressure.8,9 Research has also investigated the effects of various parameters on minimum miscible pressure, including the composition of the crude oil and injected gas, temperature, and pressure, to optimize enhanced oil recovery processes and improve oil recovery.19−21

Numerous experimental and theoretical studies have established that minimum miscible pressure is influenced by several factors, including reservoir temperature, crude oil properties, and injected gas components. In Yelling and Metcalfe study, temperature has a significant impact on the minimum miscible pressure.22 However, cooling the oil reservoir by injecting a coolant can adversely impact the physical properties of the reservoir, resulting in poor economic benefits. Consequently, researchers have focused on exploring the relationship between the composition of crude oil and injected gas and minimum miscibility pressure to reduce the latter.

Cronquist23 demonstrated that the molecular weight of the C5+ fraction is a reliable parameter for correlating MMP. Yuan et al.24 found that increasing the mole fraction of intermediate components C2–C6 can lower the minimum miscibility pressure. Mogensen et al.21 observed that the empirical formula often overestimates the impact of light oil components on MMP while underestimating the influence of heavy oil components. Mutailipu et al.25 employed the interfacial tension method to determine the minimum miscibility pressure of CO2 and alkanes and discovered that the difficulty of achieving miscibility increases with the carbon number of alkanes. Scholars have also utilized artificial intelligence to predict minimum miscible pressure and analyzed the sensitivity of different components to MMP based on experimental and simulation data.26−28 Shokir29 used the ACE algorithm to predict the minimum miscible pressure of impure CO2 and crude oil and found that C1 and N2 are positively correlated with MMP, while H2S and hydrocarbon components (C2–C4) are negatively correlated with the minimum miscible pressure of crude oil. Chen et al.11 established an empirical formula to predict the minimum miscible pressure of pure CO2 and impure CO2 with crude oil and observed that increasing intermediate components C2–C6 can reduce the minimum miscible pressure of injected gas and crude oil.

In the past few decades, Orr et al. have conducted extensive research on the phase behavior of CO2 and crude oil systems.30,31 Due to gas source issues, various pipeline gases are also used for miscible flooding. It is of great significance to clarify the changes in crude oil components during the miscibility process of different gases and crude oil. To address this gap, this study employs PVT experimental thins, slim tube experiments, and chromatographic experiments to investigate the changes in crude oil components during the miscibility process of different injected gas and crude oil. The study aims to determine the influence of various components in crude oil on the minimum miscible pressure of injected gas and crude oil. tube experiments, and chromatographic experiments to investigate the changes in crude oil components during the miscibility process of different injected gas and crude oil. The study aims to determine the influence of various components in crude oil on the minimum miscible pressure of injected gas and crude oil.

2. Experimental Section

In order to study the change of crude oil composition during the miscibility process and clarify the influence of injected gas composition and crude oil composition on crude oil miscibility, a Ruska PVT-3000 high-pressure physical property analyzer was used to prepare live oil with a certain gas-oil ratio. Slim tube experiments were carried out using CO2, pipeline gas and crude oil, and combined with chromatographic experiments to analyze the components of the crude oil produced. The specific experimental program is shown in Table 1.

Table 1. Experimental Program.

block crude oil inject gas chromatographic experiments
1 dead oil CO2 √
1 live oil CO2 √
1 live oil pipeline gas √
2 dead oil CO2 √
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2.1. PVT Experiment

Live oil was configured using the Ruska PVT-3000 high-pressure physical property test device, and the schematic diagram of the PVT test equipment is shown in Figure 1. The components of the injected gas are shown in Table 2, and the components of the dead oil and live oil in the two blocks are shown in Table 3.

Figure 1.

Figure 1

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Schematic diagram of live oil configuration using Ruska PVT-3000 high-pressure physical property test device.

Table 2. Components of Inject Gas.

component CO2 pipeline gas
CO2 100 0
C1 0 84.29
C2 0 8.36
C3 0 4.31
C4 0 2.40
C5 0 0.64
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Table 3. Components of Dead Oil and Live Oil from Different Blocks.

component dead oil of Block 1 mol % live oil of Block 1 mol % dead oil of Block 2 mol %
CO2 0.000 0.236 0.000
N2 0.000 3.191 0.000
C1 0.000 38.774 0.000
C2 0.009 3.850 0.000
C3 0.337 2.153 0.250
C4 2.316 2.275 0.670
C5 4.909 2.777 2.590
C6 6.603 3.339 3.710
C7 11.210 5.669 4.490
C8 19.469 9.846 5.150
C9 3.681 1.861 4.510
C10 3.032 1.534 4.630
C11 3.004 1.519 4.680
C12 2.941 1.488 4.540
C13 2.739 1.385 5.120
C14 2.846 1.439 4.930
C15 2.868 1.451 4.810
C16 2.872 1.453 4.710
C17 2.771 1.401 4.620
C18 2.810 1.421 4.580
C19 2.841 1.437 4.670
C20 2.810 1.421 4.300
C21 2.524 1.277 4.200
C22 2.450 1.239 3.930
C23 2.272 1.149 3.840
C24 2.266 1.146 3.140
C25 1.866 0.944 3.100
C26 1.892 0.957 2.230
C27 1.354 0.685 1.930
C28 1.236 0.625 1.310
C29 0.890 0.450 1.110
C30 0.837 0.423 0.670
C31 0.560 0.283 0.620
C32 0.602 0.304 0.510
C33 0.441 0.223 0.450
C34 0.532 0.269 0.000
C35 0.210 0.106 0.000
Total 100 100 100
oil molecular weight g/mol 105.43 68.67 157.7
oil density g/cm3 823.43 719.73 843.49
C7+ molar weight g/mol 122.5 122.5 162.2
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As shown in Table 3, the difference in dead oil components between the two blocks is mainly reflected in C3–C8. The content of C3–C8 in dead oil in Block 1 is significantly higher than that in Block 2. At normal temperature and pressure, the density of Block 1 dead oil is 823.43 kg/m3 and the viscosity is 2 mPa·s, while the density of Block 2 dead oil is 843.49 kg/m3 and the viscosity is 5 mPa·s. The gas-oil ratio of live oil is 94.51 m3/m3 and the bubble point pressure is 20 MPa. The density of live oil is 719.73 kg/m3 and the viscosity is 0.12 mPa·s at 60 °C. The content of light components such as C1–C4 in the live oil has increased substantially, accounting for about 46.8%.

2.2. Slim Tube Experiment

Oil recovery of slim tube experiment is an crucial parameter for evaluating miscibility. As injection pressure increases, oil recovery increases. Therefore, the minimum miscible pressure is determined by testing the oil recovery at different pressures. However, temperature and pressure changes during crude oil extraction can cause the light components in crude oil to volatilize, leading to significant measurement errors. To improve the accuracy of the experiment, a low-temperature separation device was installed at the liquid outlet in this experiment. The schematic diagram of the slim tube experimental device is shown in Figure 2.

Figure 2.

Figure 2

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Schematic diagram of the slim tube experimental device.

In this study, the minimum miscibility pressures of crude oil and different injected gases in the two blocks were tested at 60 °C. The parameters of the slim tube used in the experiment are shown in Table 4. This study was conducted in accordance with the petroleum industry standard SY/T 6573–2016 “Test Method for Minimum Miscible Pressure—Slim Tube Method.” The specific procedure of the slim tube experiment is as follows:

  • (1)

    Prior to the experiment, the pipeline was cleaned with petroleum ether until the petroleum ether at the inlet matched that at the outlet. Then the cleaned thin tube was blown dry with nitrogen, and dried at 60 °C for 6 h.

  • (2)

    The slim tube is then saturated at 60 °C. After injecting 2PV, the fluid component at the outlet was measured every 0.1PV injected. Saturation is completed when the fluid composition at the inlet is the same as that at the outlet.

  • (3)

    The ISCO pump was used to inject gas at a rate of 0.1 mL/min. After the injected gas breaks through, the injection rate could be increased to 0.25 mL/min, and the displacement experiment was ended after injecting 1.2PV.

  • (4)

    Record all oil volumes produced in the export section under different injecting PV. Calculate the oil recovery. Change the injection pressure and repeat the above steps.

Table 4. Parameters of the Slim Tube.

parameters value
length/cm 1251
diameter/cm 0.458
porosity/% 37.17
pore volume/mL 76.60
permeability/D 5.30
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After measuring the oil recovery at different injection pressures, drawn the relationship curve between pressure and crude oil recovery. Divide the data points into two parts based on a recovery of 90%. Drawn two straight lines separately, and their intersection is the MMP. Taking the dead oil in Block 2 as an example, the relationship between CO2 injection volume and crude oil recovery is shown in Figure 3a, and the determination of MMP is shown in Figure 3b.

Figure 3.

Figure 3

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Relationship diagram between CO2 injection volume and crude oil recovery of Block 2 (a) and the determination of the MMP (b).

2.3. Chromatography Experiment

In this study, an Agilent 7890A gas chromatograph was used to analyze the components of the produced crude oil. In the experiment, 99.99% nitrogen was used as the carrier gas, and the temperature of the inlet was 310 °C. The chromatographic column is an HP-1 elastic quartz capillary column (60 m × 0.25 mm × 0.25 mm). The initial temperature of the column is 40 °C, keep it for 10 min, raise the temperature to 70 °C at 4 °C/min, raise the temperature to 310 °C at 8 °C/min and keep it for 40 min. The carrier gas flow rate was constant at 1 mL/min. The measured chromatogram is shown in Figure 4. For the convenience of observation, we processed the chromatogram, as shown in Figure 5.

Figure 4.

Figure 4

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Chromatogram of produced crude oil of Block 2 before the breakthrough at 10 MPa.

Figure 5.

Figure 5

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Crude oil component content after processing.

3. Results

In this study, the minimum miscible pressure of different components of crude oil and inject gas were measured through slim tube experiments. The experimental results, presented in Table 5, reveal that the minimum miscible pressure varies for different combinations of crude oil and injected gas. The minimum miscible pressure of Block 2 dead oil and CO2 is 16.04 MPa, which is significantly higher than that of Block 1 dead oil. Moreover, the bubble point pressure of Block 1 live oil is relatively high, and its recovery was over 94% when the pressure was higher than the bubble point pressure. Its minimum miscible pressure with CO2 cannot be measured. When pipeline gas was used as the injected gas, the minimum miscible pressure rose sharply to 42 MPa, which is much higher than the formation pressure of this block (24 MPa).

Table 5. Summary of Minimum Miscibility Pressure between Crude Oil and Inject Gas.

the type of crude oil and inject gas Block 1 dead oil–CO2 Block 1 live oil–CO2 Block 1 live oil-pipeline gas Block 2 dead oil–CO2
MMP 11.95   42 16.04
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To elucidate the changes in crude oil components during the process of crude oil miscibility, we conducted chromatographic experiments to analyze the crude oil components during the displacement process. The analysis results are shown below:

3.1. Changes in Crude Oil Components during Different Pressure Displacement Processes

Pressure plays a critical role in determining the miscibility of injected gas and crude oil. In the experiment, the component content of the produced crude oil was analyzed before and after gas breakthrough at various pressures. In this chapter, the analysis focuses on Block 2 crude oil, which has a minimum miscible pressure of 16.04 MPa. The changes in the crude oil components during different pressure displacement processes are illustrated in Figure 6.

Figure 6.

Figure 6

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Changes of crude oil components during different pressure displacement processes.

Differences in the changes of crude oil components under varying pressures were observed. At 10 MPa, CO2 and crude oil were not miscible, and the extraction effect of CO2 was not significant. Only some light components in crude oil were extracted with the CO2. As displacement progressed, the content of C3–C7 decreased continuously, while the content of C8–C15 increased, and the content of C16+ hardly changed. At 12 MPa, the CO2 extraction effect was enhanced, and with the breakthrough of CO2, the content of C7–C15 in crude oil increased. When the pressure increased to 14 MPa, the composition of the crude oil changed dramatically after the breakthrough. The content of C7–C15 in the crude oil accounted for over 70%, and the content of C16+ was much lower than the initial level. This was due to the improvement of CO2 extraction effect with the increase of displacement pressure. Although CO2 and crude oil were not yet miscible, the middle distillates (C7–C15) were extracted from the crude oil and condensed at the outlet for liquid recovery. After the components with lower C number were extracted, heavy fraction (C16+) in the crude oil began to be extracted with the continuous injection of CO2, and the content of heavy fraction in the produced crude oil increased. In the late stage of displacement, the components of the produced oil no longer changed significantly with the increase of CO2 injection volume, and the content of heavy fraction (C16+) in crude oil was higher than the initial level.

The changes in crude oil components are fully reflected in the color of the produced oil, as shown in Figure 7. Figure 7a shows the crude oil before the breakthrough, and Figure 7b shows the produced crude oil when the gas breaks through. These produced crude oils appear as black in color. Over time, the color of the produced oil changes to bright yellow, as shown in Figure 7c. As the volume of the injected gas increases, the color of the produced oil deepens, as shown in Figure 7d, indicating that the gas begins to extract components with larger C numbers.

Figure 7.

Figure 7

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Crude oil produced at different times at 14 MPa.

At 16 MPa, similar to that at 14 MPa, there is a significant change in the crude oil components after CO2 breakthrough. However, as the pressure increases, the content of C7–C13 in the produced crude oil decreases. This indicates that increased pressure can slow down the extraction of light components by CO2. At 18 MPa, Figure 6 clearly shows that the components of the produced crude oil are mainly C13–C23 after CO2 breakthrough. When the injection volume reaches 1.2 PV, the content of heavy fraction (C16+) in the crude oil decreases, while the content of middle distillates (C7–C15) increases. This fully indicates that as the pressure increases, the extraction effect of CO2 on middle distillates (C7–C15) decreases, while the extraction effect on heavy fraction (C16+) increases.

During the experiment, we found that when the displacement pressure was less than the minimum pressure, the crude oil recovery was lower, and the displacement pressure was larger when the slim tube was cleaned. After CO2 displacement, the remaining oil in the slim tube is viscous and has poorly flowing capacity. The components of the residual oil under different pressures are shown in Figure 8. With the change of the displacement pressure, the components of the residual oil have changed a lot. The injection pressure rise from 12 to 14 MPa, the CO2 extraction effect was enhanced, and the content of C16+ in residual oil increased significantly. The injection pressure changed from 14 to 16 MPa, which is very close to the minimum pressure. Under this pressure, the extraction of heavy components is strengthened, while the extraction of light components is inhibited, resulting in the increase of the content of C3–C15 in residual oil.

Figure 8.

Figure 8

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Residual oil components after CO2 displacement under different pressures.

3.2. Influence of Crude Oil Components on Miscibility

Crude oil composition may be one of the key factors responsible for the difference in minimum miscibility pressure. Based on the experimental results, it was observed that the minimum miscible pressure of Block 2 dead oil and CO2 was higher than that of Block 1 dead oil. By comparing the components of the two crude oils, it was found that the content of C3–C8 in Block 1 crude oil was much higher than that of Block 2, which could be the primary reason for its lower minimum miscibility pressure. The components of the two produced oils after gas breakthrough were analyzed, as shown in Figure 9. It can be seen that the content of middle distillates (C7–C15) in the Block 1 dead oil is relatively high, and the content of heavy fraction (C16+) in the produced oil after breakthrough continues to decrease with the increase of pressure. The content of light alkanes in the Block 2 dead oil is relatively low. As the injection pressure increases, the extraction effect of CO2 on middle distillates (C7–C15) is first enhanced. Middle distillates (C7–C15) are dissolved in multiple contact with crude oil during CO2 migration, reducing the difficulty of miscibility. Therefore, it can be inferred that an increase in the content of middle distillates (C7–C15) in crude oil can improve the extraction of heavy fraction by injected gas, making it easier for injected gas and crude oil to reach a miscible state.

Figure 9.

Figure 9

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Changes in oil components after gas breakthrough of two blocks’ dead oil.

3.3. Influence of Inject Gas Components on Miscibility

The composition of the injection gas is another important factor affecting the minimum miscibility pressure. This study focused on Block 1 live oil to investigate the impact of CO2 and pipeline gas on the minimum miscibility pressure of Block 1 live oil. When the injected gas is CO2, the crude oil and CO2 are miscible at the bubble point pressure, and the oil recovery rate is over 90%. However, when the injected gas is pipeline gas, it becomes difficult for crude oil to be miscible. The minimum miscibility pressure increases up to 42 MPa, which is far higher than the formation pressure (24 MPa).

Previous studies have indicated that the CH4 content in the injection gas can increase the difficulty of miscibility. In the case of pipeline gas, the C1 component accounts for 84.29%, while the other components only account for 15.71%. This may be the primary reason for the significant increase in the minimum miscibility pressure between pipeline gas and Block 1 live oil. When miscible flooding is not achieved, pipeline gas flooding, in contrast to CO2 flooding, primarily extracts heavy components such as C16+. With an increase in the amount of gas injection, the content of heavy components in crude oil decreases. However, upon the breakthrough of injected gas, it will extract the C7–C15 components in the crude oil, as shown in Figure 10. When the CO2 injection volume reaches 1.0PV, the gas breaks through, and the gas-oil ratio at the outlet of the slim tube increases. However, when the gas injection volume of the pipeline gas reaches 0.5PV, the gas starts to break through. There are noticeable differences in the components of crude oil after the breakthrough of injected gases, as shown in Figure 11. When the injected gas is CO2, the content of C7–C15 in the produced oil is lower, while the content of C16+ is higher. This is because, at 30 MPa, pipeline gas and crude oil cannot reach a miscible state. During the displacement process, the injected gas can extract components such as C7–C15, but cannot effectively extract heavy components such as C16+ (Figure 11).

Figure 10.

Figure 10

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Changes in crude oil composition during pipeline gas displacement.

Figure 11.

Figure 11

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Components of crude oil after the breakthrough of different injected gases.

4. Discussion

4.1. Mechanism of Near-Miscible Flooding to Enhance Oil Recovery

In recent years, miscible flooding has become a popular method for developing unconventional oil reservoirs. However, due to the strong reservoir heterogeneity in unconventional reservoirs, reaching a miscible state can be challenging. To enhance oil recovery, scholars have conducted extensive research on reducing the difficulty of oil and gas miscibility and proposed the concept of near-miscible flooding.32,33 Near-miscible flooding can increase oil recovery to a greater extent than immiscible flooding, and the oil recovery is close to that of miscible flooding.13 In this study, the minimum miscibility pressure of Block 2 crude oil and CO2 is 16.08 MPa, and the calculated near-miscibility interval is 14.8 MPa–16.08 MPa. Based on the experimental results, it was observed that in the near-miscible interval, the primary reason for the improvement of oil recovery is the change in the CO2 extraction effect. In the near-miscible interval, the extraction effect of CO2 on components with lower C number is reduced, and the extraction effect on components with higher C number is enhanced, which reduces the flow resistance of the crude oil, so that the crude oil recovery is higher. At the same time, after gas breakthrough, the content of components with lower C number in the produced oil is higher.

4.2. Effect of Displacement Pressure on Reservoir Physical Properties

The experimental results show that the oil recovery of immiscible flooding is lower than that of miscible flooding. After gas breakthrough, due to the extraction effect, the heavy components in crude oil remain in the slim tube and are difficult to displace. As the displacement pressure increases, the content of heavy fraction in the residue first increases and then decreases. Based on pressure changes and heavy alkane content, it can be inferred that increasing the injection pressure of the gas as much as possible in the near-miscible range can reduce the residual heavy components.

The slim tube experiment involves the contact between CO2 and crude oil, resulting in multiple miscible phases as shown in Figure 12. As the miscibility process takes place, the composition of the crude oil continuously changes. In the Section 3, we examine the changes in crude oil composition during the displacement process. Upon analyzing the produced oil’s composition changes, it can be found that due to pore volume replacement, the crude oil at the outlet is directly produced in the early stage of displacement. However, the crude oil at the inlet end and middle part of the slim tube is in full contact with CO2, and as a result, a significant amount of light and medium components are extracted. This also leads to the phenomenon that the medium component in the produced oil first increases and then decreases in the later stage of displacement. Consequently, a significant amount of heavy components remains at the entrance and middle of the slim tube, making subsequent cleaning challenging. During the reservoir development process, full contact between CO2 and crude oil will inevitably lead to a large amount of heavy components remaining, significantly affecting reservoir properties and subsequent development. Especially, in tight and shale oil reservoirs, the pore and throat radius are small, and the residual heavy components may cause pore throat blockage of the reservoir, making it difficult for the fluid to flow. The changes in the residual components after displacement show that the increase in injection pressure can increase the extraction of heavy components by CO2 and reduce the residual heavy components in the middle of the reservoir. Therefore, when conducting miscible flooding, it is necessary to consider the gas injection pressure.

Figure 12.

Figure 12

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Schematic diagram of the miscible process of multiple contacts between CO2 and crude oil and schematic diagram of heavy components precipitation after displacement.

4.3. Effect of Gas Viscous Fingering on Miscibility

The experimental results show that the minimum miscibility pressure of CO2 and Block 1 crude oil is much lower than that of pipeline gas. During the experiment, it was observed that the breakthrough of CO2 was later in time than that of pipeline gas. This led to a serious viscous fingering phenomenon in the displacement process of pipeline gas, which is the primary reason why its breakthrough time was earlier than that of CO2 and the difficulty of miscibility increased.

Under high-pressure conditions, gases are in a supercritical state with a certain viscosity. When the viscosity difference between gas and crude oil is significant, the gas fingering phenomenon is noticeable, and the gas breakthrough time is early. The gas breakthrough time and oil recovery of pipeline gas under different pressures were recorded and are displayed in Table 6. It was observed that the gas breakthrough time has a significant influence on the oil recovery of the slim tube experiment. As the pressure increases, the breakthrough time of gas is delayed, and the oil recovery increases correspondingly. This indicates that the injection pressure has a significant influence on gas viscosity fingering. The early breakthrough of gas shortens the contact time between injected gas and crude oil, significantly increases the difficulty of miscibility, and raises the minimum miscibility pressure.

Table 6. Summary of Gas Breakthrough Time and Recovery in Slim Tube Experiment Using Block 1 Live Oil, CO2, and Pipeline Gas.

experimental oil experimental pressure (MPa) injected gas injection volume while gas breakthrough (PV) recovery (%)
Block 1 live oil 30 CO2 1.12 95.80
Block 1 live oil 24 pipeline gas 0.27 58.42
Block 1 live oil 30 pipeline gas 0.49 62.72
Block 1 live oil 35 pipeline gas 0.55 77.42
Block 1 live oil 40 pipeline gas 1.05 89.57
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To verify the influence of compressed gas viscosity on minimum miscibility pressure, we simulated the minimum miscibility pressure of different injected gas and Block 1 live oil using PVT-sim, based on the PR/PR78 equation of state with Peneloux volume correction and the Pedersen viscosity calculation model. Before simulation, PVT-sim was used to simulate the viscosity change curve of pure CO2 and compared it with experimental values to verify the accuracy of the software. As shown in Figure 13, the calculated values are consistent with the experimental results, and PVT-sim can be used for viscosity simulation calculations.

Figure 13.

Figure 13

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Comparison between the viscosity change curve of pure CO2 calculated by PVT-sim and experimental values.

The components and content of different injected gas are shown in Table 7. The difference between different injected gas is mainly reflected in CO2 and C1. The relationship between gas viscosity and miscible pressure are shown in Figure 14. The viscosity of injection gas increases with the injection pressure, and the viscosity ratio of injection gas to oil at the miscible pressure is between 0.19 and 0.31. The increase in injection pressure increases the viscosity of the gas, which significantly delays the breakthrough time of the injection gas and increases the contact time between the gas and crude oil, eventually leading to miscibility between the crude oil and the injected gas. Based on the findings, it can be concluded that the viscosity ratio of high-pressure gas to crude oil is a crucial parameter in determining whether the gas and crude oil can reach miscibility. This parameter can aid in the selection of a suitable gas for miscible flooding in the oil field.

Table 7. Component Content of Different Injected Gas.

component injected gas 1 injected gas 2 injected gas 3 injected gas 4 injected gas 5 injected gas 6
N2 0 1.18 1.18 1.18 1.181 1.18
CO2 100 80.07 60.07 40.07 20.07 0.07
C1 0 15.15 35.15 55.15 75.148 95.15
C2 0 2.74 2.74 2.74 2.741 2.74
C3 0 0.54 0.54 0.54 0.54 0.54
C4 0 0.20 0.20 0.20 0.20 0.20
C5 0 0.12 0.12 0.12 0.12 0.12
MMP (MPa) 9.74 11.68 14.52 29.23 37.25 43.85
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Figure 14.

Figure 14

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Viscosity curves of different injected gases (a) and gas-oil viscosity ratio at minimum miscibility pressure (b).

5. Conclusions

The study investigated the miscibility process of different injected gases and crude oil using slim tube, PVT experiments, and chromatographic experiments. The main conclusions are as follows:

  • (1)

    When the injection pressure is below the miscible pressure, the gas extraction effect has a significant impact on oil recovery. As the injection pressure increases, the extraction effect of the injected gas improves, leading to higher oil recovery. After gas breakthrough, the produced oil mainly comprises middle distillates (C7–C15), and its color is bright yellow. When the injection pressure is above the miscible pressure, it greatly reduces the extraction of middle distillates (C7–C15) by the injected gas and enhances the extraction of heavy fraction (C16+), thus improving oil recovery.

  • (2)

    When the injection pressure is below the minimum miscibility pressure, gas displacement leaves a considerable amount of heavy fraction such as C16+, which can damage the physical properties of the reservoir and increase the difficulty of subsequent development. Therefore, the change of physical properties of the reservoir caused by heavy alkane residues might be considered during oilfield production.

  • (3)

    Under the same injection pressure, the difference in injected gas composition leads to a significant variation in gas breakthrough time. Increasing the viscosity of the injected gas can effectively delay gas breakthrough time. Increasing the contact time between the oil and injected gas can reduce the difficulty of miscibility, thereby enhancing oil recovery.

Acknowledgments

This study was supported by the National Key Basic Research and Development Program (973 Program) (2015CB250904) and the National Natural Science Foundation of China (51574257).

Author Contributions

K.Y.: Methodology, experiments, writing. S.Y.: Methodology, revising. J.H.: Revising. Y.G.: Experiments, data analysis. X.L.: Experiments, data analysis. Z.X.: Providing experimental materials and oilfield data.

The authors declare no competing financial interest.

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