CO₂ Injection for Enhanced Gas Recovery in Tight Gas Reservoirs of the Central Shenfu Area

Abstract

The tight gas reservoirs developed in the central Shenfu block are characterized by ultra-low porosity and permeability (typically < 10% porosity, <1 mD permeability), and high irreducible water saturation (40–60%). The frequent water blocking issue sharply reduces gas relative permeability during the production period, severely limiting well productivity. In this study, core flooding experiments using artificial cores were conducted to systematically evaluate the feasibility of CO₂ injection for enhanced gas recovery (EGR). The results show that the effectiveness of CO₂ EGR is sensitive to many factors, such as injection pressure, injection rate, total injection volume, and core permeability. The higher injection pressure and rate would improve the pressure gradient, CO₂ sweep efficiency, and EGR. An optimal total volume with the value (around 2.0 pore volumes, PV) was recommended as the amount of CO₂ injection are varied in the range of 0.5–2.5 PV. A higher permeable tight reservoir is prone to a higher nature gas recovery. The experimental findings, within the controlled conditions of this study, suggest that a flowback strategy of “slow startup and controlled depressurization” could be considered. Combining CO₂ injection with managed pressure drop of production and optimized fracturing process is proposed as a potential comprehensive strategy focused on “energy supplement, damage mitigation, and water control,” which may provide a useful reference for the efficient development of high-water-saturation tight gas reservoirs.

1. Introduction

Carbon capture, utilization, and storage (CCUS) is a key pathway toward the low-carbon utilization of fossil energy, attracting global attention for its dual role in reducing carbon emissions while enhancing oil and gas recovery [1,2,3,4]. The development of tight gas reservoirs with CO₂ injection not only improves gas recovery by displacing residual natural gas but also enables geological CO₂ storage, offering integrated energy and environmental benefits. The Shenfu central tight gas reservoirs are characterized by ultra-low porosity and permeability, strong water wet, and high irreducible water saturation (40–60%), which normally lead to severe water blocking damage accompanying with significant gas permeability reduction and lower of well productivity. Therefore, the investigation on the feasibility and mechanisms of CO₂ EGR is essential to realizing an efficient development and carbon reduction synergistically.

The process of CO₂-EGR generally involves two main stages: injection and post-injection diffusion [5]. During the injection process, viscous forces dominate CO₂ diffusion. Density differences between CO₂ and reservoir fluids induce buoyancy effects—CO₂ is denser and more viscous than CH₄, yet lighter and less viscous than formation water. When CO₂ is injected at the gas–water contact, it acts similarly to “cushion gas” in underground storage, the effect of expanding during production would enhance CH₄ output. However, research on CO₂-EGR in ultra-low-permeability tight gas reservoirs remains limited. Liu et al. [6] used CT scanning to show that CO₂ injection enlarges gas flow channels and improves gas permeability. Gao et al. [7] experimentally demonstrated that CO₂ injection replenishes reservoir energy and slows water invasion. Patel et al. [8,9] also conducted numerical simulations that showed that irreducible water can cause early CO₂ breakthrough, thereby reducing CH₄ recovery. Ye et al. [10] confirmed through experiments that supercritical CO₂ alters rock wettability, alleviating water blocking damage. In field applications, Zhao et al. [11] reported that CO₂-energized fracturing enhances flowback and enables CO₂ storage. Zhou et al. [12] observed that injection timing and rate influence recovery in core flooding tests.

Key factors affecting CO₂-EGR efficiency in tight reservoirs include water saturation, pore structure, and pressure differential [13]. However, most studies focus on medium-to-high-permeability reservoirs or idealized conditions. For strongly water-wet, high-water-saturation reservoirs like those in the Shenfu area, fundamental mechanisms—such as multiphase flow behavior, threshold pressure gradient variation, and microscopic displacement—remain unclear. In particular, systematic experimental studies are lacking on the combined mechanisms of CO₂ diffusion, flooding, and replacement under ultra-low-permeability conditions, as well as on the optimization of injection parameters and water-block removal. To address these research gaps, this study investigates the feasibility and mechanisms of CO₂-EGR in the Shenfu tight gas reservoir using core flooding experiments. We analyze how CO₂ injection affects gas–water relative permeability, threshold pressure gradient, and ultimate recovery, and clarify the effects of injection pressure, rate, volume, and reservoir properties. The results provide theoretical and technical support for implementing CO₂-EGR in similar reservoirs.

2. Reservoir Characteristics and Water Production Mechanism

2.1. Reservoir Physical Properties

Tight gas sandstone reservoirs in the central Shenfu area are mainly present in the He 8 member of the Shihezi Formation, along with the Shanxi, Taiyuan, and Benxi formations. These reservoirs show ultra-low porosity and permeability, typically with porosity values between 5.5 and 10% and permeability below 0.75 × 10⁻³ μm² (

Table 1. Statistical summary of reservoir properties for key formations in the central Shenfu area.

Stratigraphic Level	Porosity (%)	Permeability (×10−3 μm2)	Average Atmospheric Layer Thickness (m)	Gas Saturation (%)
He 8 member	7.7–9.6	0.33–0.75	15–25	50–60
Taiyuan Formation	6.5–8.8	0.28–0.68	12–22	45–55
Benxi Formation	5.5–7.2	0.20–0.50	8–15	40–50
Shanxi Formation	6.0–8.5	0.30–0.70	10–18	45–55

). The relatively thick gas layers are found within the He 8 member and Taiyuan Formation, averaging about 19.5 m in thickness, and constitute the primary producing zones in this area. The formation pressure coefficient is between 0.98 and 1.00, and the geothermal gradient is about 2.7–2.9 °C/100 m, reflecting normal pressure and temperature conditions. The dominant rock types are lithic sandstone and feldspathic lithic sandstone. The main clay minerals are illite and kaolinite, with limited occurrence of smectite, chlorite, and mixed-layer clays.

2.2. Water Production Mechanism

The complex water production mechanism in the tight gas reservoirs of the central Shenfu area is primarily driven by the interaction between intrinsic reservoir properties and development operations. Intrinsically, the reservoirs are characterized by high irreducible water saturation. Under static conditions, this water is trapped by strong capillary forces in micron- to nano-scale pore throats. During production, the pressure drawdown from bottom-hole pressure reduction can exceed the capillary entry pressure, disrupting the initial capillary pressure equilibrium and mobilizing the previously immobile water, especially near the wellbore where the pressure drop is greatest. Furthermore, certain intervals in the central Shenfu area exhibit gas–water layering or water-over-gas configurations (as shown in Figure 1). The decline in reservoir pressure during production under such conditions increases the risk of edge- or bottom-water intrusion as well as in situ water mobilization.

Additionally, hydraulic fracturing, a key stimulation method for tight gas reservoirs, can intensify water production. Due to significant vertical heterogeneity and localized high-water-saturation zones (e.g., the upper water layer in the He 8 member), it is challenging to control fracture height growth. Modeling of post-fracturing parameters (see Figure 2) shows that fractures may propagate vertically and connect to adjacent water-bearing layers, introducing external water. In representative wells, chloride ion concentrations in flowback fluids increased after fracturing (Figure 3). Furthermore, analysis of characteristic chemical coefficients in produced water confirms its origin as formation water (see

Table 2. Chemical characteristic coefficients of water produced from target wells.

Well	Sodium-Chloride Coefficient	Chlorine-Magnesium Coefficient	Alkali Exchange Coefficient	Water-Type	pH
SM-67	0.54	185.26	23.1	CaCl2	6.0
SM-63	0.58	82.22	17.4	CaCl2	6.0
SM-48	0.77	56.44	21.6	CaCl2	6.0

and

Table 3. Quantitative identification indicators of formation water chemistry in the central Shenfu area.

Classification	Formation Water	Condensate Water	Fracturing Residual Fluid
Mineralization degree (mg/L)	35,000~55,000	<10,000	20,000~50,000
pH	5.8~6.2	6.0~6.3	6.2~6.9
Sodium-Chloride coefficient	0.3~0.65	0.5~0.8	0.3~0.7
Chlorine-Magnesium coefficient	>50	<30	30–60
Alkali Exchange coefficient	3~25	0.5~5	2~15
Water-type	CaCl2	NaHCO3, Na2SO4	CaCl2

).

3. Rock Wettability and Water Blocking Damage Evaluation

3.1. Wetting Characteristics

Based on the Chinese petroleum and natural gas industry standard SY/T 5153-2007 [14] “Methods for Determining Wettability of Reservoir Rocks”, a core sample is considered hydrophilic when the measured contact angle falls between 0° and 75°. Furthermore, if the wettability index ranges from 0.7 to 1.0, the sample is classified as strongly water-wet.

The capillary pressure measurements and core wettability experiments conducted on-site (

Table 4. Calculation results of capillary pressure and gas reservoir wettability in the central Shenfu area.

Simulation Target Layer	Core Number	Permeability (×10−3 μm2)	Capillary Pressure (MPa)	Contact Angle (°)	Wettability Index	Wettability
Tai 1 Section	X-1	0.09	−0.267	28.60	0.71	Water wetting
	X-2	0.15	−0.190	22.61	0.82
He 8 member	Y-3	0.48	−0.125	17.50	0.73
	Y-4	0.65	−0.106	26.06	0.72
Tai 2 Section	Z-2	0.29	−0.160	33.69	0.79
	Z-5	1.87	−0.086	43.86	0.71

) indicate that the reservoir rocks are predominantly strongly water-wet. This wettability condition results in the formation of a continuous water film on rock grain surfaces under capillary action, which occupies effective pore throats and consequently reduces gas relative permeability, as illustrated in Figure 4.

The strongly water-wet characteristics not only increase native water retention but also facilitate the intrusion of external fluids, such as fracturing fluid filtrate [11], during pressure drawdown from production. This notably aggravates water blocking damage. The resulting water blocking effect sharply raises gas flow resistance near the wellbore, leading to severe productivity loss and presenting a major obstacle to the efficient development of tight gas reservoirs in this area.

3.2. Water Blocking Damage

Water blocking damage in tight cores from the central Shenfu area is primarily caused by capillary trapping and pore-throat blockage. This manifests as a sharp, nonlinear decline in gas permeability with increasing water saturation. Once water saturation exceeds a critical value of 37.38%—determined from the inflection point of the relative permeability curve—permeability drops abruptly (Figure 5), from 0.0827 × 10⁻³ μm² to about 0.0230 × 10⁻³ μm², accompanied by a water blocking damage ratio exceeding 82%. At a water saturation of 90.95%, the damage ratio reaches 99.96% (

Table 5. Experimental results of water blocking damage in tight core samples.

Number	Water Saturation (%)	Effective Permeability (10−3 μm2)	Water Blocking Damage Rate (%)	Water Block Index
1	90.95	0.0001	99.96	1.00
2	88.98	0.0019	98.53	0.99
3	85.44	0.0030	97.67	0.98
4	79.93	0.0184	85.65	0.86
5	77.18	0.0193	84.96	0.85
6	76.78	0.0212	83.40	0.83
7	67.41	0.0230	82.02	0.82
8	37.38	0.0827	35.36	0.35
9	19.45	0.1084	15.33	0.15
10	19.29	0.1096	14.40	0.14
11	17.71	0.1100	14.08	0.14

), essentially eliminating gas flow capability. These findings confirm that an increase in movable water severely obstructs gas flow pathways and significantly impairs permeability.

In the tight reservoirs of this block, water blocking damage is most severe when water saturation is between 0.4 and 0.6. Within this range, both gas and water relative permeabilities are low, ranging from 0.03 to 0.43 (see Figure 6). Three main mechanisms cause this behavior. First, the reservoir has strongly water-wet nano-scale pores and throats. Capillary forces are significant here. Water preferentially enters and blocks the gas flow paths. This greatly reduces gas relative permeability. Second, this water saturation range falls within a narrow co-flow zone. In this zone, both gas and water flow poorly. Gas flow efficiency is further limited as a result. Third, the formation water has high salinity. This increases the interfacial tension between gas and water. Higher tension strengthens capillary trapping and physical pore-throat blockage. Collectively, these mechanisms sharply reduce gas relative permeability. This results in low gas mobility and persistent capillary trapping, which severely restricts well productivity.

4. Countermeasures and Suggestions

4.1. Mechanisms of CO₂ Action

CO₂ injection represents a key technical approach for enhancing flow capacity and mitigating water blocking damage in high-water-saturation tight gas reservoirs of the central Shenfu area. Based on previous studies, its potential mechanisms involve multiple aspects, including interfacial property alteration, rock–fluid interactions, and energy replenishment [15]. Depending on the injection conditions, CO₂ can exist in either a gaseous or supercritical state. When temperature and pressure exceed 34.1 °C and 7.38 MPa, CO₂ enters a supercritical state [16,17]. The literature indicates that supercritical CO₂ exhibits properties such as significantly reduced gas–water interfacial tension, enhanced solubility in formation water, and strong rock–fluid interactions, which could collectively weaken capillary forces, promote wettability alteration, and improve gas mobility [18,19]. In the gaseous state, CO₂ may primarily contribute through pressure maintenance, molecular diffusion, and competitive adsorption displacement, which could also aid in mobilizing trapped gas and mitigating water blockage [20]. Furthermore, CO₂ injection could replenish reservoir energy, reduce gas viscosity, and enhance overall flooding efficiency [21,22].

4.2. Engineering Strategy and Operational Parameters

In engineering implementation, systematic optimization of injection parameters is required. Core flooding tests and pilot data [23,24,25] show that the best results occur with an injection volume of 0.5–2 PV and a soaking time of about 72 h (see

Table 6. Changes in core permeability in different soaking time in Shenfu central area.

Core Number	Initial Permeability (×10−3 μm2)	Soaking Time (h)	Permeability After Soaking (×10−3 μm2)	Rate of Permeability Change (%)
Y-1	0.12	0	0.12	0.0
		24	0.16	+33.3
		72	0.21	+75.0
		150	0.19	+58.3
Y-3	0.48	0	0.48	0.0
		24	0.56	+16.7
		72	0.83	+72.9
		150	0.81	+68.8

). Below 0.5 PV, desorption is limited. Above 2 PV may lead to gas channeling or ineffective circulation. Too short a soak time restricts CO₂ diffusion; too long affects production efficiency [26,27]. Overall, CO₂ injection represents an effective development technology for strongly water-wet, ultra-low-permeability tight gas reservoirs in the central Shenfu region.

5. Experiments

5.1. Materials

The experiments used CO₂ and CH₄ as injection gases. The brine salinity ranged from 35,000 to 60,000 mg/L (the brine was synthetically prepared.), which represents the typical range of formation water salinity in the central Shenfu area, thereby ensuring experimental representativeness. The experiments utilized rectangular artificial core samples (Figure 7), measuring 0.3 m in length and 0.045 m in both width and height. The rectangular shape was chosen to facilitate uniform fluid distribution and to minimize edge effects during flooding experiments, allowing for more consistent and reproducible results. It should be noted that artificial cores exhibit characteristics such as relatively homogeneous pore structures, simplified mineral composition, and controllable surface properties. These features make them suitable for systematically studying key mechanisms and parameter sensitivities of CO₂ flooding under controlled conditions. However, micro-scale characteristics—including pore structures, clay mineral content, and wettability—differ from those of natural reservoirs. Therefore, the quantitative conclusions drawn from this study are primarily applicable to the specific experimental setup. These cores were composed primarily of quartz sand and fragments of natural reservoir rock. Detailed petrophysical parameters are provided in

Table 7. Physical properties of experimental rock cores.

Simulation Target Layer	Core Number	Porosity (%)	Permeability (×10−3 μm2)
He 8 member	Y-1	5.5	0.12
	Y-2	6.2	0.15
	Y-3	8.4	0.48
	Y-4	9.1	0.65
	Y-5	7.8	0.35
Tai 1 Section	X-1	4.3	0.09
	X-2	6.2	0.15
	X-3	7.8	0.35
	X-4	8.9	1.20
	X-5	12.5	1.82
Tai 2 Section	Z-1	3.9	0.15
	Z-2	4.3	0.29
	Z-3	6.8	0.54
	Z-4	7.1	0.81
	Z-5	14.7	1.87

.

5.2. Apparatuses

The overall experimental setup is shown in Figure 8. It comprises a constant pressure/constant rate pump (TC-100D) for brine injection, a CO₂ gas cylinder (99.9% purity) equipped with a high-precision pressure regulator for gas injection, and a core holder with an overburden pump to apply confining pressure. A custom-made accumulator (316 stainless steel, pressure rating ≥ 30 MPa) was used to separate gas and liquid phases, ensuring a well-defined flooding process. A back-pressure regulator (BPR) was installed downstream of the core holder to precisely control the system pressure (P_sys).

Pressure Control Logic:

Inlet Pressure (P_in): The pressure of the injected gas (CO₂) at the core inlet, regulated by the gas cylinder’s pressure-reducing valve.

System/Back Pressure (P_sys): The stabilized pore pressure within the core assembly, actively maintained by the downstream BPR.

Pressure Differential (ΔP): To ensure CO₂ flow into the core, a constant pressure differential was maintained between the inlet and the system: ΔP = P_in − P_sys = 0.5 MPa. For each target P_sys, the gas regulator was set so that P_in = P_sys + 0.5 MPa.

Depletion Pressure (P_dep): This refers to the target system pressure (P_sys) set during the primary depletion stage (Step 4 in Section 5.3), simulating the reservoir pressure after a period of natural production. In this study, three P_dep values (10, 8, and 6 MPa) were tested to represent different stages of field depletion.

5.3. Procedure

(1)

Core Preparation: A dried core sample was loaded into the holder. The system was assembled, and all instruments were calibrated prior to testing.

(2)

Vacuum and Saturation: The core was evacuated. Formation water was then injected to establish irreducible water saturation (S_wi). The pore volume (PV) was determined from the injected water volume.

(3)

Pressurization and Heating: With S_wi established, the system was pressurized with natural gas to the initial reservoir pressure of 20 MPa (confining pressure was maintained 5 MPa higher). The temperature was then raised and stabilized at the reservoir condition of 60 °C for 12 h.

(4)

Primary Depletion (Simulating Natural Production): After establishing initial reservoir conditions (20 MPa, 60 °C), the system was subjected to a staged pressure depletion to simulate natural gas production. The back-pressure regulator was used to lower the system pressure (P_sys) in three sequential steps: 10 MPa, 8 MPa, and 6 MPa. Each of these target pressures is defined as a depletion pressure (P_dep). The system was stabilized for 30 min at each P_dep step, and the cumulative volume of produced CH₄ was recorded. This step established the baseline recovery before CO₂ injection.

(5)

CO₂ Flooding: Following the depletion stage, CO₂ flooding was initiated at the reservoir temperature of 60 °C. The flooding experiment was conducted by controlling two key pressures: The system pressure (P_sys) was maintained at a level corresponding to the final P_dep of the previous step (e.g., 6, 8, or 10 MPa) using the back-pressure regulator. The CO₂ injection pressure (P_in) at the core inlet was set to be 0.5 MPa higher than the prevailing P_sys (i.e., P_in = P_sys + 0.5 MPa) to ensure a constant driving force (ΔP = 0.5 MPa) for flow.

Note on CO₂ State: Under these experimental conditions (60 °C, with P_sys and consequently P_in ranging from 3 to 8 MPa in most tests), the CO₂ remained in a gaseous state for the majority of the experiments, as the pressure was below the critical pressure of 7.38 MPa. The CO₂ was injected at a constant interstitial velocity (e.g., 0.233 ft/day), and the total injection volume varied between 0.5 and 2.5 pore volumes (PVs). Key parameters, including P_in, P_sys, cumulative CH₄ production, and effluent gas composition, were monitored and recorded in real time.

(6)

Post-Test: After each test, the core was cleaned with anhydrous alcohol. The procedure was repeated for replicate experiments.

5.4. Conditions

The experiments simulated the gas reservoir conditions in the central Shenfu area, with a formation temperature of 60 °C. A total of threesets of experiments were designed (see

Table 8. Experimental conditions for different gas injection pressures.

Core Permeability (10−3 μm2)	Core Porosity (%)	Pressure Depletion (MPa)	Injection Pressure (MPa)
0.81	7.1	6, 8, 10	3
			4
			5
			6
			8

,

Table 9. Experimental conditions for different gas interstitial injection velocities.

Core Permeability (10−3 μm2)	Core Porosity (%)	Pressure Depletion (MPa)	Interstitial Injection Velocity (ft/day)
0.81	7.1	10	0.117
			0.233
			0.350
			0.466
			0.583

and

Table 10. Experimental conditions for different injection volumes.

Core Permeability (10−3 μm2)	Core Porosity (%)	Pressure Depletion (MPa)	Injection Volume (PV)
0.81	7.1	10	0.5
			1.0
			1.5
			2.0
			2.5

). Three artificial cores, namely X-4, Z-4, and Z-5, were selected for the flooding experiments, with their parameters shown in the table. The selection of these cores was based on covering a representative range of porosity and permeability observed in the target formations: X-4 and Z-4 represent moderate–low-permeability conditions typical of the majority of the reservoir. In contrast, Z-5, with higher porosity and permeability, was included to evaluate the effect of more favorable petrophysical properties on CO₂ flooding efficiency. This approach allows for a comparative analysis of CO₂ injection performance across varying reservoir qualities. Interstitial injection velocity setting references Liu et al. [6].

6. Results and Discussion

6.1. Gas–Water Relative Permeability Characteristics

The relative permeability curves obtained from the tests (Figure 9) indicate that the tight sandstone in the central Shenfu area exhibits typical “water-dominated” characteristics, which are manifested as follows: (1) extremely high irreducible water saturation (40–60%), resulting in limited effective gas flow space; (2) very low relative permeability at the iso-permeability point (mostly below 0.05), indicating weak flow capacity for both phases; (3) a steep decline in gas relative permeability with increasing water saturation, showing a sharp curve profile; and (4) an extremely narrow two-phase co-flow region, with an effective water saturation range typically less than 15%. These characteristics are primarily controlled by the reservoir’s microscopic pore structure, where the dominant configuration of large pores with narrow throats, strong water-wet affinity, and high formation water salinity collectively lead to significant degradation of gas phase permeability. The narrow co-flow zone and the steep drop in gas permeability highlight the critical importance of water control during development. Any factor that raises water saturation in the near-wellbore region may thereby cause severe productivity loss.

These relative permeability characteristics are primarily governed by the microscopic pore structure of the reservoir. The dominant configuration of “large pores with narrow throats” features small throat sizes and a high pore-throat ratio, which generates strong capillary forces. This not only leads to high irreducible water saturation but also causes significant capillary trapping effects during two-phase flow, resulting in considerable flow resistance. Additionally, formation water salinity, strongly water-wet rock properties, and reservoir temperature–pressure conditions collectively contribute to the reduction in gas phase permeability [28,29]. In summary, the gas–water two-phase flow characteristics in the tight reservoirs of the central Shenfu area differ significantly from those in conventional gas reservoirs. The key distinctions lie in the unique shape of the relative permeability curves and the narrow co-flow region, which decisively influence well performance after water breakthrough. The narrow co-flow zone and the steep decline in gas relative permeability underscore the critical importance of water control in developing this area.

6.2. Analysis of Gas Injection Influencing Factors

6.2.1. Effect of Pressure

The effect of CO₂ injection pressure (P_in) was investigated under three different depletion pressure (P_dep) backgrounds (10, 8, and 6 MPa). During flooding, the system pressure (P_sys) was maintained at the respective P_dep level, while P_in was varied from 3 to 8 MPa, maintaining a constant ΔP of 0.5 MPa over P_sys, as shown in Figure 10. Specifically, at a depletion pressure of 10 MPa, the recovery increase is the highest, reaching 11.5% (

Table 11. Total recovery factor under different injection pressures (3–8 MPa).

Depletion Pressure (MPa)	Injection Pressure (MPa)	Recovery Before Injection (%)	Enhanced Recovery (%)	Total Recovery (%)
10	3	43.5	4.2	47.7
	4	43.5	6.8	50.3
	5	43.5	8.5	52
	6	43.5	10.3	53.8
	8	43.5	11.5	55
8	3	58.2	3.1	61.3
	4	58.2	4.7	62.9
	5	58.2	6	64.2
	6	58.2	7.2	65.4
	8	58.2	8	66.2
6	3	65.7	2	67.7
	4	65.7	3.2	68.9
	5	65.7	4.5	70.2
	6	65.7	5.8	71.5
	8	65.7	6.5	72.2

), followed by 8 MPa, while the increase at 6 MPa is relatively lower. Laboratory experiments demonstrate that CO₂ injection can effectively enhance recovery in tight gas reservoirs, with the effect jointly influenced by injection pressure and depletion pressure. Specifically, a lower depletion pressure results in higher cumulative recovery; under the same depletion pressure, increasing the injection pressure further improves recovery, showing a clear positive correlation.

This phenomenon can be explained by the following mechanisms supported by experimental observations. First, a lower depletion pressure (e.g., 6 MPa) indicates lower initial reservoir energy and pore pressure, which reduces gas flow resistance and allows injected gaseous CO₂ to more readily enter micropores and throats under the pressure differential, promoting more thorough molecular diffusion and flooding residual CH₄. Second, a higher injection pressure (e.g., 8 MPa) establishes a stronger flooding pressure gradient, effectively overcoming the significant capillary forces (0.1–0.3 MPa) and threshold pressure gradients in tight formations, thereby expanding the sweep volume of CO₂. Furthermore, at the experimental temperature of 60 °C, when the injection pressure reaches or exceeds 7.38 MPa, CO₂ may locally attain a supercritical state (critical point: 7.38 MPa, 34.1 °C). Supercritical CO₂ is reported to combine high diffusivity with liquid-like density and dissolution capacity, which could enhance flooding efficiency and promote interfacial tension reduction [18]. However, in most of the tested pressure range (3–6 MPa), CO₂ remained in a gaseous state. The observed positive correlation between injection pressure and recovery may be attributed to increased pressure gradient, enhanced molecular diffusion, and improved sweep efficiency, which are effective even with gaseous CO₂. These interpretations align with prior studies on CO₂ flooding in tight media, where both gaseous and supercritical states are suggested to contribute to recovery enhancement through complementary pathways [19,20].

6.2.2. Effect of Interstitial Injection Velocity

Faster injection helps establish a higher instantaneous pressure gradient within the pore-throat network, facilitating the mobilization and flow of gas from low-permeability zones. As shown in

Table 12. Total recovery factor under different interstitial injection velocities.

Interstitial Injection Velocity (ft/day)	Recovery Before Injection (%)	Enhanced Recovery (%)	Total Recovery (%)
0.117	43.5	1.2	44.7
0.233	43.5	2.5	46
0.350	43.5	3.8	47.3
0.466	43.5	5	48.5
0.583	43.5	5.5	49

, when the interstitial injection velocity increased from 0.117 ft/day to 0.583 ft/day, the incremental recovery contributed by CO₂ rose from 1.2% to 5.5%, and the total recovery factor increased correspondingly from 44.7% to 49%. Laboratory results indicate that, in a depleted tight gas reservoir, CO₂ flooding can effectively enhance natural gas recovery, with the cumulative recovery factor gradually improving as the CO₂ injection rate increases (Figure 11). This improvement is attributed to enhanced flooding efficiency and improved sweep volume at higher injection rates, which help overcome capillary resistance and access smaller pores [21,22]. The increased flow rate also reduces viscous fingering and promotes a more stable flooding front, thereby improving macroscopic recovery performance.

6.2.3. Effect of Injection Volume

The effect of different CO₂ injection volumes (ranging from 0.5 PV to 2.5 PV) on the cumulative recovery factor after depletion development is shown in Figure 12. Experimental results indicate that the total recovery factor gradually increases with higher injection volumes, but the rate of increase in the cumulative recovery factor slows down after approximately 2.0 PV of injection. This behavior is attributed to the two primary mechanisms of CO₂ injection for enhanced recovery: partial pressure maintenance and competitive adsorption displacement [30]. In the initial stages, injected CO₂ effectively increases reservoir pressure and displaces CH₄ molecules adsorbed on the rock surface, converting them into free gas that can be produced. Consequently, the recovery factor shows a significant improvement during this phase. However, the adsorption capacity of tight sandstone for CO₂ is limited, as described by adsorption isotherm models for similar tight rocks [6,31,32]. When the injection volume reaches about 2.0 PV, the adsorption sites on the rock surface become nearly saturated, and the adsorption–desorption process between CO₂ and CH₄ approaches a dynamic equilibrium. Beyond this point, additional injected CO₂ primarily exists in a free state, contributing more to displacement than to adsorption exchange. As a result, the incremental recovery declines slightly compared to the trend before 2.0 PV—for instance, the recovery factor at 2.5 PV is only 0.7% higher than that at 2.0 PV (as shown in

Table 13. Total recovery factor under different injection volumes.

Injection Volume (PV)	Recovery Before Injection (%)	Enhanced Recovery (%)	Total Recovery (%)
0.5	43.5	2	45.5
1	43.5	4.5	48
1.5	43.5	6.8	50.3
2	43.5	8.5	52
2.5	43.5	9.2	52.7

).

6.2.4. Effect of Permeability

As shown in Figure 13, a higher permeability (e.g., 1.82 × 10⁻³ μm²) leads to an earlier CO₂ breakthrough (at 1.1 HCPV), yet it achieves a higher ultimate recovery (73.1%,

Table 14. Total recovery factor under different permeability.

Permeability (×10−3 μm2)	Breakthrough Time (HCPV)	Total Recovery (%)
0.81	1.6	60.58
1.2	1.3	65.54
1.82	1.1	73.1

) due to enhanced diffusion and dissolution capacity. In contrast, a lower-permeability core (0.81 × 10⁻³ μm²) exhibits delayed breakthrough and lower ultimate recovery (60.58%). These results indicate that, although increasing injection volume promotes CO₂ diffusion and dissolution, reservoir permeability remains a key constraining factor.

In high-permeability cores, the more connected pore network and larger pore-throat pathways (Figure 14) reduce flow resistance, allowing CO₂ to form continuous flow channels and channelize rapidly, resulting in earlier breakthrough (defined here as the CO₂ mole fraction reaching 5% at the outlet). This better connectivity also enables CO₂ to contact and displace residual natural gas more effectively across a larger pore volume, leading to higher macroscopic displacement efficiency and ultimate recovery. In low-permeability cores, narrow pore throats and strong microscopic heterogeneity increase flow resistance, restricting CO₂ penetration into smaller pores and causing flow to be confined to tortuous pathways, which reduces sweep efficiency and ultimate recovery. For all cores, increasing injection volume improved recovery; however, the recovery increase in low-permeability cores remained significantly lower than in high-permeability cores due to inherent physical constraints.

7. Conclusions

(1)

The tight gas reservoirs in the central Shenfu area are characterized by ultra-low porosity and permeability, strong water-wet properties, and high irreducible water saturation (40–60%). Water blocking damage during production leads to a sharp decline in gas relative permeability, severely constraining well productivity.

(2)

In the artificial core experiments, the effectiveness of CO₂ injection is influenced by key operational and core parameters. Experimental results show that higher injection pressure (up to 8 MPa) and interstitial injection velocity (up to 0.583 ft/day) improve sweep efficiency and recovery. An optimal injection volume of approximately 2.0 PV was identified, beyond which the incremental recovery declines slightly. Core permeability significantly affects performance, with higher-permeability cores achieving up to 73.1% recovery compared to 60.58% in lower-permeability cores.

(3)

This study systematically evaluated the potential of CO₂-EGR under controlled conditions using artificial core experiments. The quantitative relationships between injection parameters and recovery provide fundamental data for understanding CO₂ flooding behavior in such reservoirs and serve as an important laboratory-scale reference for designing and interpreting field pilot tests.

(4)

It is recommended that future studies conduct pore-scale simulations or microfluidic experiments to deepen the understanding of the underlying mechanisms. Additionally, research should prioritize the use of natural core samples or systematic comparative experiments between artificial and natural cores to improve the reliability of extrapolating experimental results to field conditions.

(5)

Based on insights from these laboratory experiments, the integration of CO₂ injection with managed pressure production and optimized fracturing practices is conceptually proposed as a synergistic development strategy focused on energy replenishment, damage mitigation, and water control. This conceptual framework requires further validation through field pilots but offers a preliminary technical pathway for consideration in enhancing recovery in the challenging reservoirs of the central Shenfu area.