Experimental Study on Miscible Phase and Imbibition Displacement of Crude Oil Injected with CO₂ in Shale Oil Reservoir

Abstract

Jimsar shale oil in China has undergone a rapid decline in formation energy and has a low recovery rate, with poor reservoir permeability. CO₂ injection has become the main method for improving oil recovery. Pre-fracturing with CO₂ energy storage in Jimsar shale oil has been performed, yielding a noticeable increase in oil recovery. However, the CO₂ injection mechanism still requires a deeper understanding. Focusing on Jimsar shale oil in China, this paper studies the effect of CO₂ on crude oil viscosity reduction, miscible phase testing, and the law of imbibition displacement. The results show that CO₂ has a significant viscosity reduction effect on Jimsar shale oil, with a minimum miscible pressure between CO₂ and Jimsar shale oil of 25.51 MPa, which can allow for miscibility under formation conditions. A rise in pressure increased the displacement capacity of supercritical CO₂, as well as the displacement volume of crude oil. However, the rate of increase gradually declined. This research provides a theoretical basis for CO₂ injection fracturing in Jimsar shale oil, which is helpful for improving the development effects of Jimsar shale oil.

1. Introduction

Compared with conventional oil and gas, shale oil reservoirs require large-scale reconstruction to achieve efficient extraction [1,2]. Horizontal wells with stimulated reservoir volume have been prominently used in shale oil development [3]. Scholars are concerned about carbon dioxide as a greenhouse gas and how to use it. Carbon dioxide has been widely studied in the field of chemical research [4,5]. Meanwhile, technological advancements have also facilitated the use of CO₂ injection to effectively increase production output [6,7]. The CO₂ flooding mechanism includes viscosity reduction, extraction, and expansion [8]. Here, CO₂ is typically injected into the injection well, which increases the pressure and drives crude oil into the production well [9,10]. The injected CO₂ gradually blends with the oil under specific reservoir conditions, reducing interfacial tension and greatly improving recovery [11,12]. Most of the oil fields in China are continental sedimentary reservoirs, with crude oil characterized by strong heterogeneity and high viscosity. Therefore, it is necessary to carry out related research on viscosity reduction and imbibition displacement with CO₂ injection [13,14,15,16,17].

Guo et al. revealed the mechanism of enhanced oil recovery by conducting experiments on the swelling of formation oil by CO₂ injection and feldspar core displacement, as well as viscosity–temperature curve tests for different systems. CO₂ dissolution in a viscosity-reducing agent also reduces the interfacial tension of a co-viscosity-reducing system agent, driving synergistic oil displacement between both agents [18]. Li et al. investigated a CO₂ viscosity-reducing composite flooding technology, revealing the influence of viscosity-reducing slug on system performance and the composite flooding effect. The study involved long core-displacement experiments on a low-permeability, heavy-oil reservoir (Z13) [19]. Li et al. studied the enhanced oil recovery (EOR) technology of intelligent nano black tape flooding for high-temperature and low-permeability reservoirs in the Henan oilfield, believing that the technology could increase the EOR by 15.8 to 20.0 percentage points for the target oilfield [20]. Yang et al. conducted core imbibition and CO₂ shuttling experiments on the Lusaogou formation in Jimsar. They found that presence of imbibition liquid in the core after imbibition can reduce the minimum pore radius of CO₂, promote the spread of CO₂ in micropores, and improve the core recovery efficiency [21]. Zhang et al. established a numerical model for simulating reservoir production that considers the formation of complex fractures after CO₂ composite pressure flooding. The research results suggested that the main mechanisms of CO₂ pressure flooding include reducing crude oil viscosity, expanding crude oil, enhancing crude oil fluidity, creating fractures near injection wells to improve CO₂ injection capacity, and increasing formation pressure [22].

Nuclear magnetic resonance (NMR) technology, which has unique advantages for studying pore sizes, is widely used in petroleum engineering research [23,24]. Jin et al., taking the reservoir of the Chang 6 Member of Ordos Basin as the research object, based on the characterization of the reservoir characteristics, used high-temperature and high-pressure nuclear magnetic resonance to dynamically monitor the multiphase flow and migration behavior of crude oil in each stage of CO₂ flooding in real-time. They discussed the influence of injection pressure on the recovery efficiency and the degree of micro-pore crude oil recovery [25]. Xiao et al., using Jimsar shale oil as the research object, studied the characteristics of pore throat fluid utilization and oil recovery changes during CO₂ huff and puff using a low-frequency nuclear magnetic resonance core analyzer. The effect of fracturing fluid-assisted CO₂ huff-n-puff in enhancing oil recovery was evaluated [26]. Zhao et al. used this technology to investigate the characteristics and mechanism of crude oil production in micro-nano pores of shale. They also studied the influence of contact time and contact number on the degree of recovery, concluding that the main mechanism involves CO₂ dissolution and diffusion [27]. Pu et al. used NMR to determine the displacement behavior of CO₂ injection in tight oil reservoirs from a microscopic perspective, noting that CO₂ flooding could effectively drive crude oil in tight pores [28]. Lang et al. also used NMR to study how CO₂ injection enhances oil recovery in shale oil reservoirs, and they analyzed the influence of fracture development degree on EOR based on the NMR images. The results showed that the degree of recovery gradually increased with the extension of the CO₂ injection time. Essentially, the injected CO₂ diffuses and dissolves in the crude oil, which increases the volume of the crude oil and decreases the viscosity; finally, the crude oil is discharged from the core pores onto the core surface [29]. Similarly, Zheng et al. used NMR to study how CO₂ adsorption replaces CH₄ in coal and rock through injection. The results showed that, during the replacement, the maximum methane adsorption capacity was distributed in a low-pressure and high-pressure stage as the CO₂ injection pressure changed [30].

Taking Jimsar shale oil in China as the research object, this study conducted investigations on the behavior of oil viscosity reduction and imbibition replacement by CO₂ injection, which could provide a reference for the subsequent and efficient development of shale oil.

2. Effect of CO₂ on Crude Oil Viscosity Reduction

2.1. Experimental Equipment

Jimsar shale oil was used as the research object, and the degassed crude oil was obtained on-site. The formation pressure in the target area is 40.3 MPa. In order to restore the crude oil condition under the formation condition, the sample was reconfigured according to the ratio of crude oil to gasoline. The process of reducing the formation of crude oil is as follows: First, a specific volume of dehydrated crude oil is added to the sample distributor and heated to the formation temperature (90 °C). Then, according to the test results of the field separated gas components (as shown in

Table 1. Gas components.

Components	CO2	CH4	C2H6	C3H8	iC4H10	nC4H10	iC5H12	nC5H12
Content/%	0.54	66.3	13.35	14.86	2.18	2.19	0.21	0.38

), the re-injection gas—configured in the laboratory in the same proportion—is mixed into the sample distributor. During this period, it is continuously stirred and gradually pressurized to the formation pressure (40.3 MPa), and the final mixture is the reduced formation crude oil.

The experimental device was a mercury-free transparent piston-type high-pressure PVT device, which is shown in Figure 1. The PVT analyzer was cleaned at the formation temperature (90 °C) in the test area and vacuumed. Then, a certain amount of test area formation crude oil sample was transferred into the PVT instrument in a single phase and kept constant at the formation temperature for 8 h. First, the sample volume was tested under the formation pressure, and a certain amount of CO₂ gas was injected into the formation crude oil at this pressure; the system’s pressure was raised until all the CO₂ was dissolved. Then, the system was made to be single-phase. The saturation pressure, volume expansion coefficient, and other parameters of the CO₂-formation crude oil system were tested. When the layer of crude oil is at saturation pressure, every injection of CO₂ into it will cause the system pressure to increase. When the CO₂ in this section is wholly dissolved in the crude oil, the system pressure is the CO₂ saturation pressure, which reflects the dissolution capacity of CO₂ in the crude oil. Finally, the mixed sample of CO₂-formation crude oil in the PVT instrument was transferred to a high-temperature and high-pressure falling ball viscometer, and the single-phase viscosity of the system was tested at the formation temperature, completing the first aeration expansion experiment.

After the PVT instrument was cleaned, the above steps were repeated for the second aeration expansion experiment. The volume of CO₂ gas injected this time was greater than that of the first experiment. The saturation pressure, volume expansion coefficient, viscosity, and other parameters of the CO₂-formation crude oil system were also tested. Overall, a total of six aeration expansion experiments were carried out at the formation temperature.

Table 2. Summary of experimental results.

Number	CO2 Molar Fraction/mol%	Saturation Pressure/MPa	Gas-Oil Ratio/-	Coefficient of Crude Expansion	Density/g/cm3	Viscosity/mPa·s
0	0.00	5.69	20.0	1.0000	0.8526	19.03
1	18.85	8.55	40.9	1.0465	0.8536	12.35
2	40.00	15.45	82.5	1.1145	0.8566	7.85
3	52.10	22.12	121.2	1.1918	0.8645	6.56
4	62.00	33.05	175.5	1.2895	0.8751	5.76
5	69.00	47.26	225.4	1.3805	0.8935	5.49
6	72.45	57.76	271.6	1.4315	0.9048	5.40

provides a summary of the experimental results.

2.2. Changes in CO₂ Saturation Pressure

Figure 2 illustrates the relationship between the saturated pressure of crude oil and the amount of CO₂ injected. After the CO₂ injection, the saturation pressure of the formation crude oil increases significantly; the greater the amount of CO₂ injected, the higher the saturation pressure. For example, at a CO₂ content of 72.45 mol% in the formation crude oil, the saturation pressure of the co-formation crude oil system reaches 57.76 MPa. The variation in the saturated pressure of the CO₂–formation crude oil system also reflects the solubility of CO₂ in the crude oil. Moreover, the solubility of CO₂ in the crude oil increases with increasing pressure. The higher the gas injection pressure, the more the CO₂ dissolves in the crude oil, which improves the oil displacement efficiency.

2.3. Changes in Expansion Coefficient

Figure 3 illustrates the relationship between the coefficient of volume expansion and pressure and the amount of CO₂ injection. The volume expansion coefficient refers to the ratio of the crude oil volume under formation pressure after adding CO₂ to the volume without adding CO₂ (still under formation pressure). This coefficient reflects the capacity of CO₂ to expand crude oil after gas injection. Figure 4 shows the curve of the coefficient for the CO₂–ground oil system against the amount of CO₂ injected. The experimental results show that the volume of crude oil significantly expands after CO₂ injection, and the volume expansion coefficient increases with the increase in the amount of CO₂ injected. Because the solubility of CO₂ in crude oil increases with rising pressure, the ability of CO₂ expansion volume is enhanced by increasing the injection pressure, which is conducive to improving the oil displacement efficiency.

2.4. Changes in Viscosity

Figure 4 illustrates the relationship between viscosity and CO₂ injection amount. CO₂ flooding effectively improves oil displacement efficiency because it reduces the viscosity of crude oil after dissolving into the crude oil, and the viscosity reduction effect is closely related to the oil displacement effect. In this study, after CO₂ injection, the CO₂–formation crude oil system was tested under saturated pressure to evaluate the effect of CO₂ injection on the viscosity reduction of formation crude oil in the test area. The experimental results show that, upon CO₂ injection, the viscosity of the formation crude oil decreases considerably, and the system’s viscosity decreases with an increasing CO₂ amount, albeit at a gradually reducing rate. These results show that CO₂ injection has a strong expansion ability and good viscosity reduction effect on the formation oil in the test area, and it improves the oil recovery to a certain extent.

3. Behavior of Minimum CO₂ Miscible Pressure

3.1. Subsection

The formation of a miscible phase in the displacement process is the key factor affecting the oil displacement efficiency. In an immiscible displacement, the oil displacement efficiency is low, and the oil displacement efficiency no longer changes substantially after the formation of immiscible displacement.

The classic thin-tube experimental method was employed to test the minimum miscible pressure (MMP) of CO₂ miscibility in crude oil by using a specific experimental device, as shown in Figure 5. The essence of the experiment is to displace crude oil in porous media provided by a thin tube model by injecting a gas, which eliminates the influence of the mobility ratio, gravity differentiation, heterogeneity, and other factors to the greatest extent. For a given formation crude oil and reservoir temperature, the displacement pressure and injected gas composition are the main factors that determine miscibility. By varying the displacement pressure or injected gas composition, we can obtain a curve that depicts the relationship between displacement efficiency and displacement pressure (or injected gas composition) under the same injection pore volume. The pressure corresponding to the inflection point of the curve is the lowest miscible pressure.

The experimental device for determining the minimum miscible pressure is shown in Figure 6, and it mainly comprises the model, injection, measuring, and output systems.

3.2. Experimental Steps

(1)

Preparation of live oil samples

A certain volume of dead oil was added to the high-temperature and high-pressure sample distributor (Cochi (Beijing) Technology Limited, Beijing, China), as well as a certain amount of gas sample (the amount of oil and gas sample was accurately calculated using the PVTsim software (version PVT 240-1500 FV) before oil distribution). A constant temperature of 60 °C and pressure of 20 MPa were maintained and the sample was fully stirred and balanced to ensure that it was in a stable single-phase state. Then, the sample was transferred to the kettle containing the live oil in the thermostat in preparation for the thin tube experiment.

(2)

Density and volume coefficient test under different pressures

The density meter (Anton Paar (Shanghai) Trading Co., Shanghai, China) was used to measure the density of degassed dead oil samples. The relevant data of the volume coefficient under different pressures were obtained through the constant mass expansion experiment using a PVT test.

(3)

Cleaning of thin tubes

Petroleum ether was used to clean the thin tubes at a constant flow of 5 mL/min. During the cleaning, the back pressure was adjusted to increase the pressure to the experimental measuring point. During the cleaning, approximately 2–3 PV were cleaned, and once clear petroleum ether appeared at the end, it was transferred to the crude oil saturation stage.

(4)

Saturation of formation crude oil

The formation crude oil sample was saturated at a 2 mL/min constant flow. When the saturation was approximately 1.5 PV, the composition and gas–oil ratio of the oil sample at the end was determined. When it was consistent with the original sample, it was transferred to the displacement stage.

(5)

Thin tube displacement test

At the formation temperature, a 0.2 mL/min constant-flow CO₂ displacement experiment was performed on the configured formation samples by changing the experimental pressure conditions. The stage recovery and total recovery were calculated under each pressure condition.

3.3. Experimental Conditions

The basic parameters and experimental conditions of the thin tube model are presented in

Table 3. The basic parameters and experimental conditions of the thin tube model.

The Basic Parameters of the Thin Tube Model	Value
Length	1570 cm
Inner diameter	0.45 cm
Outer diameter	0.6 cm
Filler name	Quartz sand
Filler particles	200
Porosity	46.69%
Gas permeability	4834 mD

and

Table 4. Experimental conditions of the thin tube.

Experimental Parameters	2802H	2805H
Formation temperature	87.77	90.99
Formation pressure	41.21	42.39
Experimental temperature	89 °C	98 °C
Displacement rate	0.2 mL/min	0.2 mL/min

.

3.4. Experimental Results

Taking the formation pressure as the starting point, six groups of experiments were conducted after a gradual reduction in the pressure to obtain the recovery rate under the corresponding pressures.

Table 5. Results of thin tube experiments.

No.	Temperature (°C)	Pressure (MPa)	Oil Displacement Efficiency (%)
1	89	15.3	68.43
2	89	21.3	82.17
3	89	24.3	87.81
4	89	29.3	92.08
5	89	34.3	93.76
6	89	39.3	95.47

shows the results of thin tube experiments. Figure 7 illustrates the relationship between the displacement efficiency and the experimental pressure obtained by the experiment. The black curve represents the first stage, which corresponds to a displacement pressure of 15.3 MPa–24.3 MPa and a recovery degree of 68.43%–87.81%. This stage is the immiscible flooding stage, where the increase in pressure is accompanied by a corresponding significant increase in the recovery rate. The red curve depicts the second stage of miscible flooding, corresponding to a displacement pressure of 29.3 MPa–39.3 MPa and recovery degree of 92.08%–95.47%. Here, as the pressure increases, the recovery rate also increases, but by only 3%. The two curves intersect at a point, indicating when the mixing is completed. Moreover, the horizontal coordinate of this turning point corresponds to the minimum miscible pressure (25.5 MPa). Since the formation pressure is 25.5 MPa, and the Jimsar formation pressure is 40.3 MPa, which is higher than the minimum miscible pressure, it is judged that CO₂ can be miscible with crude oil after injection into the formation.

4. CO₂ and Crude Oil Imbibition Displacement Experiment

4.1. Experimental Principle

An immersion experiment combined with NMR scanning was used to study how CO₂ displaces crude oil. The experimental equipment mainly comprised a thermostat, a CO₂ high-temperature and high-pressure reaction tank with four containers numbered ①–④, and a low-field NMR equipment, as shown in Figure 8, Figure 9 and Figure 10.

The CO₂ immersion rock experiment was performed under monitored formation temperatures and pressures on an oil-bearing core. The phenomenon of crude oil precipitation was qualitatively studied from the experimental results, whereas the ability of CO₂ to displace crude oil was quantitatively analyzed using NMR scanning.

Firstly, a mixture of carbon tetrachloride and ethanol 1:1 was selected as the oil-washing agent to pretreat the oil-bearing core (oil washing). Due to the high viscosity of the residual oil in the core, the oil is washed for 30 days in a 24 h high-temperature cycle to ensure that the residual oil is removed as much as possible.

Table 6. Parameters of the equipment in the NMR test.

Parameters	Value	Parameters	Value
The primary value of the RF signal frequency/MHz	12	Cumulative number of sampling frequency	16
Frequency deviation of an RF signal/Hz	559,002.34	Echo time/ms	0.07
90 degree pulse width/μs	5.6	Number of echoes	5000
180 degree pulse width/μs	9.44	Digital gain/db	3
Sampling bandwidth/KHz	250	Analog gain/db	20
Signal delay/ms	0.02	Preamplification gain/db	1
Interval for repeated sampling/ms	3000

shows the parameters of the equipment in the NMR test, which remain unchanged in subsequent NMR tests.

Here, the nuclear magnetic semaphore of crude oil was first calibrated. Figure 11 illustrates the relationship between the nuclear magnetic semaphore and crude oil quality, so as to establish the equation between nuclear magnetic semaphore and crude oil quality.

4.2. Experimental Procedure

The experimental procedure was as follows:

• A standard core with a diameter of 2.5 cm was cut approximately 7 cm in length and was weighed, with the weight denoted as M1;
• The Jimsar crude oil after core saturation and dehydration was weighed, with the weight denoted as M2;
• The core was tested after the crude oil saturation using NMR to obtain the crude oil distribution in pores in the initial state;
• The core was loaded into a high-temperature and high-pressure reaction tank, placed in an incubator, and preheated to the experimental temperature;
• The CO₂ was introduced into the reaction tank and pressurized to the experimental pressure, after which it was placed back in the incubator;
• A constant temperature was maintained until the end of the experiment, at which point the reaction tank was removed; then, the vent valve was opened to release the high-pressure CO₂ in the tank; the core was taken out, oil was gently wiped on the surface, and weighed, with the weight denoted as M3;
• After the experiment, the core was tested again using NMR to obtain the distribution of the replaced crude oil in the pores.

4.3. Results and Analysis

The experimental replacement conditions are presented in

Table 7. The experimental conditions.

No.	Length/cm	Diameter/cm	Mass/g	Mode	Pressure/MPa	Temperature/°C	Time/h
1	7.48	2.5	82.439	Replacement	40	90	24
2	7.60	2.5	84.926	Replacement	30	90	24
3	7.48	2.5	83.576	Replacement	20	90	24
4	7.67	2.5	87.158	Displacement	20	90	/
5	7.38	2.5	86.104	Replacement	20	90	6
6	7.56	2.5	82.887	Replacement	20	90	12
7	7.40	2.5	82.209	Replacement	10	90	24

. Figure 12 shows the core after the replacement experiment.

Before the immersion experiment, seven cores were tested using NMR, and the initial oil content of the cores was measured while obtaining the above calibration results of nuclear magnetic semaphore, as shown in

Table 8. The initial oil content of ten cores.

No.	Saturated Oil Mass/g
1	3.903
2	3.801
3	5.692
4	4.713
5	5.530
6	5.708
7	3.646

.

Figure 13 shows the T2 spectra of the original state of seven cores. The NMR test results of the original state of the seven cores are the basis of the experimental design. The table and figure show that the oil content and porosity of cores 1, 2, and 7 were close to each other; hence, they were used to determine the influence of pressure on the recovery rate. Furthermore, cores 3, 5, and 6 were also close and were used to study the change in recovery rate relative to time. The oil content of core 4 was between that of both groups, and the occurrence of crude oil was relatively close to that of core 3. Therefore, it was designated as a displacement under the same experimental conditions (20 MPa, 90 °C) as those of core 3, as a comparison of different experimental methods.

Figure 14 shows the T2 spectra before and after displacement of seven cores. The imbibition displacement experimental results were obtained after the displacement experiment are presented in

Table 9. Experimental results.

No.	Length/cm	Diameter/cm	Saturated Oil Mass/g	Initial Mass/g	Post-Displacement Mass/g	Extracted Mass/g	Recovery Rate
1	7.48	2.5	3.903	82.439	40	2.210	56.70%
2	7.60	2.5	3.801	84.926	30	1.940	51.07%
3	7.48	2.5	5.692	83.576	20	2.419	42.50%
5	7.38	2.5	5.530	86.104	20	1.181	21.35%
6	7.56	2.5	5.708	82.887	20	2.002	35.07%
7	7.40	2.5	3.646	82.209	10	0.848	23.26%

. Recovery curves based on the experimental results were drawn for groups 1, 2, 3, 7, and 3, 5, 6, respectively, as shown in Figure 15 and Figure 16. It can be found that the increase in pressure led to an increase in the displacement capacity of supercritical CO₂, and the amount of displaced crude oil was higher at the same time. However, the rate of increase gradually declined. The displacement persisted with time, although with a gradually declining displacement efficiency. Overall, the displacement occurred at a fast rate.

A comparison of the T2 spectra of core NMR before and after groups 1, 2, 3, 5, 6, 7, and 6 of the replacement experiments yielded the following observations:

• Under the initial conditions, two wave peaks occurred in each of the six cores: 0.01 < relaxation time < the left wave peak and relaxation time of 100 > the right wave peak of 100.
• After the replacement experiment, the left wave peak decreased while the right wave peak shifted to the left. The observation on the surface that the left shift of the right wave peak included two processes: first, the original right wave peak disappeared, which corresponds to the displacement of crude oil from the core in the large pore; second, the oil in the small pore represented by the left wave peak gradually migrated into the large pore, and in this continuous process, the oil in the middle pore was monitored.
• Comparing cores 1, 2, 3, and 7, in the T2 spectrum after the replacement experiment of cores 1 and 2, the left wave peak not only decreased in its peak value, but also shifted to the left, a phenomenon that is not observed for cores 3, 7, 4, 5, and 6. The intuitive interpretation is that, under high-pressure conditions, some amount of oil is squeezed into smaller pores. Moreover, the use of NMR offers another possibility that the relative content of heavy components in the crude oil also caused this phenomenon; thus, under high-pressure conditions, the supercritical CO₂ extraction capacity is stronger, the replaced crude oil is mostly light, and the remaining crude oil in the core is heavy.
• A comparison of cores 3, 5, and 6 showed that, after the replacement experiment, the left wave peak area relative to the original wave peak reduced with time, indicating a reduction in the oil content in the core.

5. Conclusions

An experimental study on CO₂ viscosity reduction and miscibility of Jimsar shale oil in Junggar Basin, China, was carried out. The imbibition displacement of crude oil was studied using nuclear magnetic resonance. This research provides a theoretical basis for the CO₂ injection fracturing of Jimsar shale oil, which is helpful for improving the development effect of Jimsar shale oil. The research in this paper provides the basis for our subsequent mathematical modeling and simulation analysis. The main conclusions of this paper are as follows.

• In the process of CO₂ injection in Jimsar shale oil, the formation of crude oil has a strong expansion capacity and noticeable viscosity reduction effect, which can improve the recovery rate to a certain extent.
• Under formation conditions, the minimum miscible pressure of CO₂ and Jimsar shale oil is 25.5 MPa, while the formation pressure of Jimsar is 40.3 MPa, which is higher than the minimum miscible pressure. Therefore, it is judged that CO₂ can be miscible with crude oil after injection into the formation.
• A rise in pressure enhances the displacement capacity of supercritical CO₂, and the amount of displaced crude oil also increases but at a gradually reduced rate. The dis-placement persists with time, but the displacement efficiency gradually decreases. Overall, the displacement is a very fast process.