The Influence of Injection Modes on CO₂ Flooding and Storage in Low-Permeability Reservoirs

Abstract

Low-permeability reservoirs have poor reservoir properties and are difficult to develop by conventional water flooding. CO₂ flooding can significantly improve oil recovery while achieving carbon storage, and is widely recognized as an effective solution for the development of low-permeability oil reservoirs. In order to address the lack of a comparative quantitative analysis of the tradeoff between oil recovery factor, CO₂ storage rate, and total CO₂ storage volume for the main injection modes in low-permeability reservoirs, this study systematically evaluated the performance of CO₂-enhanced oil recovery (EOR) and geological storage under different pressures and injection modes through core flooding experiments. The results indicate that displacement pressure and injection strategy significantly influence the CO₂ flooding performance. Continuous miscible flooding (30 MPa) substantially reduced the displacement pressure differential (maximum 6.1 MPa) and achieved the highest oil recovery (78.96%) and the greatest CO₂ storage capacity (5916 cm³). Miscible WAG flooding effectively delayed gas breakthrough (extended to 1.90 pore volumes), homogenized the displacement front, and yielded the best overall outcome: the highest ultimate oil recovery (83.8%) coupled with the optimal CO₂ storage rate (89.1%). The study further reveals that the pre-breakthrough stage is critical for contributing to oil recovery and achieving efficient storage, regardless of the injection modes. These findings clarify the technical characteristics and applicable conditions of different injection modes, providing crucial theoretical insights and practical guidance for optimizing CO₂ EOR and storage projects in low-permeability reservoirs.

1. Introduction

China possesses abundant low-permeability oil and gas resources [1,2,3], accounting for 46% of the nation’s total oil and gas resources. According to statistics from the Ministry of Land and Resources, the proven geological reserves of low-permeability oil and gas in China exceed 14 billion tons [4], making them a major area for increasing reserves and production in the oil and gas industry. Efficient development of low-permeability reservoirs is of great significance for ensuring national energy security. Low-permeability reservoirs are characterized by low porosity and permeability, exhibiting poor fluid flow capacity. Production under natural energy is low [5], and conventional water flooding faces technical challenges such as “difficulty in water injection [6] and low productivity from production wells [7,8],” resulting in low oil recovery and production rate [9]. CO₂ has low viscosity [10] and is easy to inject [11,12,13,14]. Under high-pressure conditions, through multiple contacts with crude oil, it continuously extracts the light components from the oil [15], eventually achieving miscibility with the crude oil [16], thereby significantly enhancing oil recovery [17,18,19]. Moreover, while displacing crude oil, CO₂ can be permanently stored underground through mechanisms such as oil displacement, dissolution in oil and water, and mineralization reactions. Thus, CO₂ flooding offers a dual benefit of carbon emission reduction [20] and enhanced oil production [17,21,22,23], serving as a key technology for the green and low-carbon transformation of the fossil energy industry.

Based on the relationship between reservoir pressure and the minimum miscibility pressure (MMP) of CO₂-crude oil systems, CO₂ flooding can be classified into three continuous gas injection modes: miscible flooding, near-miscible flooding, and immiscible flooding. Depending on variations in the injected medium, CO₂ flooding can also be divided into continuous gas injection and water-alternating-gas (WAG) injection. Numerous studies have been conducted by researchers on the oil displacement effectiveness of different CO₂ flooding modes. Physical simulation studies have shown that within a certain range, higher continuous CO₂ injection pressure leads to higher oil recovery. Separately, it has been demonstrated that water-alternating-gas (WAG) injection yields better recovery than continuous gas injection under the same pressure conditions [24,25]. Researchers conducted a study that involved both physical and numerical simulations to explore how CO₂ interacts with crude oil under different pressures [26] and the subsequent differences in oil displacement efficiency [27,28,29,30]. They found that there was no significant diffusion mass transfer at a pressure of 10 MPa; when the pressure rises to 14 MPa, there was a slight extraction effect of CO₂ on light components. As the pressure further increases, this interaction gradually strengthens. When the pressure reaches 25 MPa, the mutual mass transfer becomes very strong, and it can be observed that the light components of crude oil were vigorously extracted by CO₂. This indicates that as the pressure increases, the mass transfer diffusion effect in the initial contact stage gradually increases, and the molecular weight of the crude oil components that CO₂ can extract gradually increases.

Regarding CO₂ flooding for enhanced oil recovery, extensive research has been conducted by previous scholars. In terms of injection methods, continuous gas flooding often leads to premature gas breakthrough and low wave propagation efficiency due to CO₂’s low viscosity and high flowability [31]. To improve flow control, water-alternating-gas (WAG) injection has been widely adopted. This technique injects water plugs to suppress gas breakthrough, thereby enhancing macroscopic sweep efficiency [32,33]. Studies indicate that WAG injection mobilizes more crude oil from medium and small pores, achieving superior oil displacement [34,35]. Additionally, some research has explored periodic gas injection patterns (e.g., “pulsing”) and found that under specific conditions, these may outperform continuous gas flooding and WAG injection [34]. Regarding displacement mechanisms, while achieving complete miscibility represents the ideal state for enhancing micro-scale oil recovery efficiency [17], extensive research confirms that near-miscible pressure conditions can yield recovery rates approaching those of miscible displacement through key mechanisms such as crude oil swelling and viscosity reduction [36].

In summary, although extensive research has explored the mechanisms and patterns of CO₂-enhanced oil recovery [37,38], significant variations exist in displacement methods and experimental conditions across studies. There remains a lack of systematic, comprehensive comparative analysis of recovery and sequestration behaviors under unified conditions for different injection patterns. Particularly as the integration of CO₂-enhanced oil recovery (EOR) with carbon capture, utilization, and storage (CCUS) emerges as a developmental trend [39,40,41], the patterns and mechanisms of CO₂ sequestration under different injection methods demand urgent in-depth investigation [42].

This study systematically investigates the effects of different injection modes on CO₂ displacement and storage performance through long-core experiments. It reveals the influence patterns of injection modes on key parameters characterizing CO₂ flooding and storage, aiming to provide fundamental guidance for designing CO₂ flooding and storage projects as well as formulating development strategies for low-permeability reservoirs.

2. CO₂ Flooding and Storage Experiments

To clarify the impact of different injection modes on CO₂ flooding and storage effects, experiments of CO₂ immiscible flooding, near-miscible flooding, miscible flooding, and WAG flooding were carried out. The variation laws of key parameters such as pressure difference, gas–oil ratio (GOR), oil recovery, storage capacity, and storage rate during CO₂ flooding and storage were analyzed.

2.1. Experimental Samples and Equipment

2.1.1. Core Samples

The sandstone core samples used in the experiments were all taken from a typical low-permeability reservoir with a permeability of 10–20 mD and a porosity of 15–20%, buried at a depth of about 3200 m [43]. The cores were washed with solvents such as toluene and then dried [44,45]. It should be noted that the focus of this study is to clarify the influence of injection modes on CO₂ flooding and storage. Therefore, the selected core samples are from the same region and same layer to minimize the influence of the geo-logical heterogeneity [46,47]. The short cores were sequentially spliced into a long core following the harmonic mean principle. The physical properties of the cores are presented in

Table 1. Physical properties of the cores used in the experiments.

Core No.	Length (cm)	Diameter (cm)	Porosity (%)	Permeability (mD)
F1	4.21	2.526	16.30	17.71
F2	4.19	2.522	16.68	16.96
F3	3.28	2.526	16.98	15.58
F4	4.41	2.526	15.75	15.21
F5	3.75	2.524	16.63	11.45

.

2.1.2. Experimental Fluids

Oil sample: The simulated oil sample in the experiments was prepared based on degassed crude oil of typical low-permeability oil reservoirs according to the crude oil composition and the GOR. The saturation pressure of the oil sample is 14.2 MPa, the solution GOR is 69.6 m³/m³, the density under reservoir conditions is 0.78 g/cm³, and the viscosity is 1.31 mPa·s. Long tube displacement tests show the MMP between the oil sample and CO₂ is 29.8 MPa.

Water sample: CaCl₂-type formation water with a salinity of 61,390.50 mg/L was prepared according to the composition shown in

Table 2. Ionic composition of formation water used in the experiments.

Ions	Na+ + K+	Ca2+	Mg2+	HCO3−	SO42−	Cl−	Total
Composition/(mg/L)	13,130.13	8987.94	729.30	610.20	90.06	37,842.88	61,390.50

Gas sample: CO₂ gas with a purity of 99.99%.

.

2.1.3. Experimental Equipment

The CO₂ flooding and storage experiments were conducted using a high-temperature, high-pressure long-core flooding system manufactured in Hai’an County, Jiangsu Province, China. It mainly consists of a high-precision micro-injection pump, fluid container, core holder, confining pressure system, backpressure system, produced fluid measurement system, and constant temperature system. A schematic diagram of the apparatus is shown in Figure 1.

2.2. Experimental Methods

All CO₂ flooding and storage experiments were conducted at the reservoir temperature of 126 °C. In the experiments, the backpressure for immiscible flooding, near-miscible flooding [21], miscible flooding, and WAG flooding was set to 20 MPa, 25 MPa, 30 MPa, and 30 MPa, respectively. The main experimental steps are as follows:

(1)

Preparation of simulated oil and simulated formation water based on the composition of the reservoir crude oil and formation water.

(2)

The long core was placed into the core holder and vacuumed to saturate the simulated formation water, followed by oil flooding to establish irreducible water saturation. The system was then aged at constant temperature for 24 h.

(3)

Conducting CO₂ flooding and storage experiments under different schemes:

①

For immiscible, near-miscible, and miscible flooding: Back pressures were set at 20 MPa, 25 MPa, and 30 MPa, respectively. CO₂ was injected at a rate of 0.05 mL/min until oil production ceased at the core outlet.

②

For miscible WAG flooding: The back pressure was set at 30 MPa. CO₂ and water slugs were injected alternately at a rate of 0.05 mL/min with an interval of 0.1 pore volume (PV) until oil production ceased at the core outlet.

It is worth noting that due to the low-permeability of core samples, if the injection rate is high, it will lead to a sharp increase in upstream injection pressure. The rate of 0.05 mL/min is a relatively reasonable value obtained through multiple tests before the experiments.

During the experiments, the inlet pressure, outlet pressure, back pressure, and volumes of produced oil/gas/water were recorded. The crude oil recovery, CO₂ storage rate, and storage capacity were calculated. The formula for calculating storage rate is shown in Equation (1):

$$Storage rate(\%)={\displaystyle \frac{V_{injection}-V_{production}}{V_{injection}}}$$

(1)

where V_injection and V_production are the injected volume and produced volume of CO₂ (under standard conditions), respectively. The final storage capacity under different injection modes are defined as the CO₂ storage capacity corresponding to the cessation of oil production.

3. Results and Discussion

3.1. CO₂ Immiscible Flooding and Storage

The injection-production performance curve for the CO₂ immiscible flooding and storage experiment at 20 MPa is shown in Figure 2. At the initial stage of gas injection, CO₂ gradually dissolves in the crude oil while displacing it. This process reduces the viscosity of the crude oil and causes its volume to expand, while also lowering the interfacial tension between oil and water to reduce displacement resistance. Due to the weak occupation effect of CO₂ on pore space during the dissolution process, the injection and production pressure difference increases slowly. As oil production began at the outlet, the oil recovery increased slowly. During this stage, the produced GOR remained stable, equal to the initial solution GOR of the crude oil, and all injected CO₂ was stored within the core, resulting in a storage efficiency of 100%.

When the injected volume reached approximately 0.6 pore volumes (PV), the dissolution of CO₂ into the oil within the swept zone approached saturation. At this point, the displacement effect of CO₂ became stronger than its dissolution effect, leading to a rapid increase in both the pressure differential and the oil recovery. When the cumulative CO₂ injection reached 1.41 PV, CO₂ was on the verge of breaking through the core. The pressure differential peaked at 8.5 MPa, corresponding to an oil recovery of 52.97%. After exceeding 1.41 PV of CO₂ injection, a gas channel formed within the core due to the significant viscosity difference between CO₂ and crude oil, reducing CO₂ flow resistance. Consequently, the pressure differential decreased rapidly. Significant CO₂ production was observed at the outlet, causing the GOR to rise sharply. The increase in oil recovery became marginal, and the CO₂ storage efficiency gradually declined. The final oil recovery was 62.13%, which is lower than the 70.2% oil recovery of CO₂ immiscible flooding in the high-permeability reservoir of Palogue Oilfield in Sudan. This may be attributed to differences in reservoir properties [48,49,50]; the permeability of Palogue Oilfield reaches 700–9600 mD, while the permeability of the core used in this experiment is 11–17 mD, which restricts the improvement of displacement efficiency [51,52]. However, the CO₂ storage rate of 42.7% in this experiment is comparable to the values reported for CO₂ storage in tight sandstones [53,54,55]. Therefore, the contribution of CO₂ immiscible flooding to both oil recovery and storage rate is primarily realized during the production stage before gas breakthrough. After CO₂ breakthrough, even substantial additional gas injection is ineffective in further significantly enhancing oil recovery.

3.2. CO₂ Near-Miscible Flooding and Storage

The injection-production performance curve for CO₂ near-miscible flooding and storage at 25 MPa is shown in Figure 3. The pressure of 25 MPa is close to the MMP of CO₂ and crude oil. At this condition, the displacement mechanism shows transitional characteristics, retaining the dissolution and viscosity reduction effect of non-miscible flooding while beginning to exhibit the advantage of a sharp reduction in interfacial tension of near-miscible flooding. Similarly to the immiscible flooding behavior, CO₂ initially primarily dissolved into the crude oil after injection began, resulting in a relatively slow increase in the displacement pressure differential. The produced GOR equaled the solution GOR of the crude oil, and all injected CO₂ was stored at this stage.

As CO₂ injection continued, its dissolution in the oil near the injection end gradually approached saturation. Subsequently, the displacement effect of CO₂ strengthened, leading to a rapid rise in both the pressure differential and the oil recovery. When the cumulative CO₂ injection reached 1.52 pore volumes (PV), the CO₂ front arrived at the core outlet. At this point, the pressure differential peaked at 7.0 MPa, corresponding to an oil recovery of 59.65%.

Upon further CO₂ injection, gas breakthrough occurred at the production end, causing the GOR to increase rapidly. Consequently, the pressure differential and CO₂ storage efficiency decreased significantly, while the oil recovery continued to increase only slightly until oil production ceased. The final oil recovery and CO₂ storage rate were 74.9% and 51.7%, respectively, indicating a clear improvement in both displacement and storage performance compared to immiscible flooding. This is consistent with the research conclusion of Lei et al. [56], whose study shows that when the pressure is close to MMP, the recovery rate of CO₂ flooding can be increased by 10% to 15% compared with non-miscible flooding.

3.3. CO₂ Miscible Flooding and Storage

During the CO₂ miscible flooding, a miscible zone between CO₂ and crude oil is formed, and the interfacial tension between oil and CO₂ is almost completely eliminated. Meanwhile, CO₂ can extract a large amount of hydrocarbon components from crude oil, significantly improving the fluidity of crude oil. The injection-production performance curve for CO₂ miscible flooding and storage at 30 MPa is shown in Figure 4. The results indicate that during the initial stage of CO₂ miscible flooding, the higher injection pressure enhances the dissolution capacity of CO₂ in the crude oil, resulting in a lower initial injection-production pressure differential compared to immiscible and near-miscible flooding. As CO₂ injection continued, the pressure differential first increased slowly and then rose rapidly. Prior to CO₂ breakthrough in the core, the GOR remained stable, oil recovery continued to increase, and all injected CO₂ was stored.

When the cumulative CO₂ injection reached 1.75 pore volumes (PV), CO₂ broke through at the core outlet. At this point, the pressure differential peaked at 6.1 MPa, corresponding to an oil recovery of 60.3%. Subsequently, a gas channel formed within the core, leading to significant gas production at the outlet, a sharp decline in the pressure differential, and a rapid increase in GOR. Nevertheless, due to the continuous extraction of residual oil by the miscible zone, the oil recovery continued to rise, ultimately reaching a final recovery of 78.96%—a greater increase compared to near-miscible and immiscible flooding-while the CO₂ storage rate gradually decreased to 74.1%.

Compared with the studies of the same type of oil reservoirs, the final recovery rate of the miscible flooding in this experiment (78.96%) is slightly lower than the predicted recovery rate of CO₂ miscible flooding in Karamay Oilfield, which may be related to the limitation of the experimental core size. However, the CO₂ storage rate (74.1%) was significantly higher than that of non-miscible flooding and near-miscible flooding, which is in line with the conclusion proposed by Lei et al. that the CO₂ retention capacity is enhanced under miscible conditions [56]. Their research shows that after eliminating the influence of CH₄ and N₂, the storage rate of miscible flooding can be increased by more than 20%.

3.4. CO₂ Water-Alternating-Gas Miscible Flooding and Storage

The injection-production performance curve for WAG miscible flooding and storage at 30 MPa is shown in Figure 5. The results show that during the initial injection stage, with the increase in CO₂ and water injection volumes, the injection-production pressure differential exhibited minor fluctuations while rising rapidly overall. This is attributed to the lower viscosity and higher compressibility of CO₂, which provides better injectability compared to water, leading to a smaller pressure increase during CO₂ injection than during water injection, and thus minor fluctuations in the pressure differential. Concurrently, the alternating injection of gas and water created multiple gas–liquid interfaces within the pores, generating the Jamin effect and enhancing fluid flow resistance, raising the overall injection pressure, and gradually enlarging the pressure differential. During this stage, oil recovery increased slowly.

When the cumulative injection of CO₂ and water reached approximately 1.4 pore volumes (PV), water production began at the outlet, with the water cut gradually increasing. At a total injection volume of about 1.90 PV, the CO₂ front reached the production end, and the pressure differential peaked at 11.8 MPa, corresponding to an oil recovery of 63.5%. Subsequently, CO₂ broke through at the outlet, causing a gradual decrease in the pressure differential, a marked increase in the GOR, and a reduction in CO₂ storage rate. However, due to the alternating production of CO₂ and water—where gas production is accompanied by less water, and water production is accompanied by lower gas output—both the water cut and GOR exhibited fluctuating increases, with the overall rise in GOR being relatively moderate. This indicates that WAG injection effectively controls gas channeling. In the later stages of flooding, the decline in the pressure differential slowed, and oil recovery continued to increase, ultimately reaching a final recovery of 83.8% and a CO₂ storage rate of 89.1%.

3.5. Comparative Analysis of CO₂ Flooding and Storage Under Different Injection Modes

The aforementioned results indicate that while the production performance curves of CO₂ immiscible, near-miscible, miscible, and WAG flooding exhibit similar trends, their displacement and storage rate differ significantly. To further quantitatively investigate the influence of flooding schemes on CO₂ displacement and storage, this section systematically compares and analyzes the variations and differences in production characteristic parameters—such as displacement pressure differential, gas breakthrough time, and GOR—as well as development evaluation parameters, including oil recovery, storage rate, and storage capacity, under the four flooding schemes. This analysis aims to provide guidance for optimizing CO₂ flooding and storage strategies in low-permeability reservoirs.

3.5.1. Influence on Production Characteristic Parameters

The variation curves of displacement pressure differential and GOR under different flooding schemes are shown in Figure 6. The results show that for continuous gas injection, a higher pressure level corresponds to a lower displacement pressure differential. The peak displacement pressure differential for CO₂ miscible flooding at 30 MPa was 6.1 MPa, whereas for immiscible flooding at 20 MPa it reached 8.5 MPa. This difference arises because, under immiscible conditions, the interfacial tension between CO₂ and crude oil increases flow resistance, while under miscible conditions, thorough contact between CO₂ and oil reduces interfacial tension to nearly zero, significantly lowering flow resistance and thus resulting in a lower pressure differential compared to immiscible and near-miscible flooding. In WAG flooding, alternating gas and water injection creates multiple gas–liquid interfaces within the pores. Due to interfacial tension effects, fluid flow resistance is higher than in continuous gas injection, enabling WAG flooding to maintain a higher displacement pressure differential and thereby mobilize oil from smaller pores.

From the GOR variation curves under different flooding schemes, it can be observed that significant GOR increases occurred at injection volumes of approximately 1.41 PV, 1.52 PV, 1.75 PV, and 1.90 PV for immiscible, near-miscible, miscible, and WAG flooding, respectively. This indicates that for continuous gas injection, lower reservoir pressure levels lead to earlier gas breakthrough and faster gas channeling. In WAG flooding, water preferentially enters larger, well-connected pores, making it less likely for CO₂ to form dominant flow channels along these pores. This delays gas breakthrough, and due to the alternating production of gas and water, the GOR remains at a relatively low level, which facilitates the more efficient utilization and storage of CO₂.

3.5.2. Influence on Oil Displacement Efficiency

A comparison of the oil recovery under different displacement schemes is shown in Figure 7. The results indicate that prior to gas breakthrough, the oil recovery ranged from 53.0% to 63.5% across the different CO₂ flooding methods, ranked from high to low as follows: WAG miscible flooding, miscible flooding, near-miscible flooding, and immiscible flooding. After gas breakthrough, the incremental recoveries for WAG, miscible, near-miscible, and immiscible flooding were 20.3%, 18.7%, 15.3%, and 9.2%, respectively. This demonstrates that WAG flooding outperforms continuous gas injection both before and after gas breakthrough. This is attributed to the fact that during continuous gas injection, CO₂ preferentially displace oil in larger pores. Once the injected CO₂ volume reaches a certain threshold, the interconnected larger pores gradually form dominant flow channels for CO₂, leading to premature gas breakthrough and channeling. In WAG flooding, the alternating injection of CO₂ and water allows water to first enter the larger pores, and due to its higher flow resistance, subsequently injected CO₂ is diverted into medium and small pores to mobilize otherwise hard-to-recover oil. Consequently, WAG flooding effectively homogenizes the displacement front and controls gas channeling, resulting in superior displacement efficiency compared to other methods. However, regardless of the flooding scheme, the incremental oil recovery achieved after gas breakthrough is significantly lower than the cumulative recovery before breakthrough. Therefore, optimizing the displacement scheme and injection-production parameters to prevent premature gas breakthrough is key to enhancing the effectiveness of CO₂ flooding.

3.5.3. Influence on Storage Rate

The final storage capacity and storage rate of CO₂ at the point of ceased oil production under different displacement schemes are compared in Figure 8. The results show that CO₂ miscible flooding achieved the highest storage capacity, reaching 5916 cm³. This is attributed to the high-pressure level associated with miscible flooding, which allows for a greater cumulative volume of compressed CO₂ to be injected. Despite some CO₂ being produced along with oil after gas breakthrough, the overall amount sequestered remains the highest, with a storage efficiency of 74.1%. WAG flooding ranks second in terms of final storage capacity. Although the cumulative CO₂ injected in WAG flooding is relatively lower, the alternating water and CO₂ slugs effectively suppress channeling by mutually inhibiting flow. This significantly delays gas breakthrough, allowing the injected CO₂ to be more fully utilized for oil displacement with minimal production, thereby resulting in a high storage capacity and a storage rate of 89.1%. In contrast, near-miscible and immiscible flooding involve relatively larger volumes of injected CO₂. However, earlier gas breakthrough and severe channeling in later stages lead to substantial CO₂ production, consequently resulting in lower storage capacity and rate.

In summary, CO₂ miscible flooding yields the optimal result in terms of final storage capacity, while WAG flooding achieves the highest storage rate. In practical applications, the choice of an appropriate CO₂ flooding scheme should be determined by comprehensively considering factors such as the degree of enhanced oil recovery, CO₂ storage rate, storage capacity, and economic viability.

Although the linear core model employed in this study differs from actual heterogeneous reservoirs in terms of geometric configuration, boundary conditions, and physical property simplification, it enables effective control of variables and successfully reveals the fundamental mechanisms and key behavioral patterns of CO₂ flooding under varying pressures and injection modes. The findings regarding the influence of pressure on miscibility, the role of injection modes in controlling gas channeling, and the distinct contributions of pre- and post-breakthrough stages to oil recovery and CO₂ storage possess significant mechanistic universality. These insights provide a theoretical basis for the design of CO₂-enhanced oil recovery and storage programs and offer practical guidance for optimizing injection parameters and defining development stages in field applications. Subsequent studies may further extend these understandings to more complex geological conditions through numerical and physical simulations.

4. Conclusions

This study conducted long-core experiments on CO₂ immiscible, near-miscible, miscible, and WAG flooding in low-permeability reservoirs. The effects of different injection modes on CO₂ flooding performance characteristics, oil recovery rate, and storage rate were compared and analyzed. The main conclusions are as follows:

(1)

The injection modes significantly impact CO₂ flooding efficiency. Miscible WAG injection achieved the highest oil recovery (83.8%), followed by miscible flooding (79.0%), near-miscible flooding (74.9%), and immiscible flooding (62.1%). WAG injection effectively enhanced oil displacement both before and after CO₂ breakthrough by homogenizing the displacement front and suppressing gas channeling.

(2)

CO₂ storage rate is closely related to the injection modes and CO₂ breakthrough time. Miscible WAG injection, with water slugs effectively inhibiting CO₂ channeling, achieved the highest storage rate (89.1%). In contrast, high-pressure miscible flooding yielded the greatest absolute storage capacity (5916 cm³) due to a larger cumulative injected volume. For continuous gas injection, higher pressure and later breakthrough correlate with higher storage rate.

(3)

Production performance characteristics vary distinctly. Under continuous gas injection, higher pressure reduces interfacial tension between CO₂ and crude oil, leading to lower flow resistance and a consequently lower maximum displacement pressure differential (6.1 MPa for miscible vs. 8.5 MPa for immiscible). WAG injection exhibited the highest flow resistance and maintained a higher displacement pressure differential due to multiple gas–liquid interfaces formed, enabling the mobilization of oil from smaller pores.

(4)

Controlling gas channeling is crucial for optimizing both oil recovery and storage. For all injection modes, the incremental oil recovery after CO₂ breakthrough was significantly lower than the cumulative recovery before CO₂ breakthrough. Both WAG injection and high-pressure miscible flooding substantially improved pre-breakthrough displacement efficiency by delaying CO₂ breakthrough (to 1.90 PV and 1.75 PV, respectively), laying a foundation for subsequent storage.