Evolution Mechanism of Permeability Characteristics of Shale Reservoirs During Supercritical Fluid Fracturing and Displacement

Abstract

Supercritical CO₂ (ScCO₂)-enhanced shale gas recovery technology offers dual advantages: improving shale gas recovery while reducing CO₂ emissions. The permeability of shale reservoirs during CO₂ displacement of CH₄ is a crucial issue in evaluating the efficacy of shale gas production and CO₂ sequestration. In this study, ScCO₂ fracturing and displacement experiments were carried out for shale samples, and the fracturing and permeability characteristics of shale were analyzed. The findings indicate that ScCO₂ significantly enhances fracturing and permeability, with an overall increase in permeability by three orders of magnitude. Higher injection pressures and lower stress lead to an earlier breakthrough of CO₂. The CH₄ production rate after CO₂ displacement is higher than that under conventional recovery conditions. The cumulative flow of CH₄ initially rises with increasing pressure of injection, but subsequently declines throughout the later phases of displacement, leading to a reduced CO₂ storage rate and CH₄ generation rate. High stress can inhibit CO₂ injection and CH₄ outflow, reduce CH₄ production rate, and promote shale to preferentially adsorb CO₂, resulting in higher CO₂ storage rate.

1. Introduction

Shale gas, a vital unconventional fossil fuel resource, contributes significantly to balancing energy supply and security through its efficient exploitation [1]. However, traditional water-based fracturing techniques face critical challenges: excessive water consumption and reservoir damage caused by fracturing fluids, hindering the sustainable development of shale gas fields [2]. Consequently, the CO₂-enhanced shale gas recovery (CO₂-ESGR) technology has been developed. This technology utilizes the unique physical and chemical properties of ScCO₂, to replace water-based fluids, simultaneously enhancing shale gas recovery and enabling CO₂ storage [3,4,5,6]. Furthermore, CO₂-ESGR offers substantial environmental benefits by reducing greenhouse gas emissions and minimizing ecological disruption, aligning with global climate change mitigation efforts.

Fracturing shale gas reservoir with supercritical CO₂ is essential for efficient shale gas recovery [7,8,9,10]. Zhang et al. [11] comparatively evaluated the effects of ScCO₂, liquid CO₂, and water on shale fracturing. Results indicated that ScCO₂ lowers fracture pressure by 15% and 50% relative to liquid CO₂ and water, correspondingly. The uneven cracks appear in the shale after fracturing, and in contrast to hydraulic cracking, more cracks are produced in the shale after ScCO₂ fracturing [12]. Verdon et al. [13] found that ScCO₂ fracturing achieves efficacy comparable to hydraulic fracturing while requiring significantly lower initiation pressure. Additionally, fracture propagation morphology during ScCO₂ fracturing has been analyzed [14,15,16,17]. Zhou et al. [18] found that the crack propagation process during ScCO₂ fracturing of shale can be divided into four stages: the evolution stage of the damage zone, the crack initiation stage, the post-fracturing instability stage, and the crack arrest stage. Zhao et al. [19] observed fractures extending primarily along natural fractures, bedding planes, and interlayers, with ScCO₂ inducing more fracture branches than hydraulic fracturing. Despite these advances in understanding fracture behavior and post-fracturing permeability changes, the fundamental mechanisms governing CO₂/CH₄ migration within the fractured shale matrix remain inadequately explored.

The dynamic characteristics of shale gas displacement by CO₂ can dynamically characterize the flow patterns of CO₂/CH₄ during CO₂-ESGR process [20,21,22,23,24], which is critical for evaluating gas recovery and storage capacity. Current understanding of this process relies heavily on numerical simulations, supplemented by experimental studies that primarily utilize the column kinetics method [25,26]. Du et al. [27] performed column kinetics tests with CO₂, N₂, and CO₂/N₂ mixtures to displace CH4 in shale powder. Breakthrough curves indicated that N₂ injection results in the lowest injected-gas breakthrough time and CH₄ recovery, whereas CO₂ injection provides the highest breakthrough time and recovery. Liu et al. [28] performed CO₂ displacement experiments on shale cores via nuclear magnetic resonance (NMR), monitoring real-time changes in free and adsorbed CH₄. Results showed that CO₂ injection improves adsorbed CH₄ recovery by 25%. Iddphonce et al. [29] used the displacement kinetics method to conduct pure CH₄ and CO₂-CH₄ mixed gas production experiments on shale samples. In the early phase of production, when pressure was elevated, gas recovery predominantly depended on pressure difference. Nonetheless, in the subsequent phase when the pressure decreased, competitive adsorption became prominent. The gas recovery driving mechanism shifted from relying primarily on reservoir pressure difference to competitive adsorption as the pressure decreases. A significant limitation of these prior experiments is their use of shale powder, which fails to account for the critical influence of confining stress. There are few experimental studies on the kinetics of shale gas displacement by CO₂ under in situ conditions, and it is necessary to further study the kinetics of shale gas displacement by CO₂ under multi-field coupling conditions.

In this study, ScCO₂ fracturing test and displacement test were carried out on shale samples, and the kinetics of CO₂ displacing shale gas and the fracturing properties of shale were analyzed. The variation in shale permeability before and after fracturing was discussed, respectively. The mechanism of ScCO₂ displacing shale gas under different stress and injection pressure conditions was revealed, and its impact on CO₂ storage rate and shale gas recovery during displacement was analyzed. The findings may provide a theoretical foundation for optimizing CO₂-ESGR.

2. Experimental Procedure

2.1. Sample Preparation

Samples of shale were taken from the Changning region of the Sichuan Basin’s Wufeng Formation. One of China’s best areas for the discovery and production of marine shale gas is the Sichuan Basin, which is situated on the northwest edge of the Upper Yangtze Platform. Black siliceous and carbonaceous shale make up the majority of the well-preserved Wufeng Formation, which has thicknesses ranging from 100 to 500 m and reservoir depths between 1500 and 4000 m [30].

For this experiment, outcrop samples of the Wufeng Formation were selected. All shale samples were obtained from intact blocks without visible fractures. Cores were drilled parallel to bedding planes and machined into cylindrical samples (diameter: 100 mm; height: 200 mm). Post-processing dimensional tolerances were controlled within ±1 mm for height/diameter and ±0.02 mm for end-face flatness. To simulate CO₂-ESGR and storage processes, a 14 mm-diameter borehole (depth: 140 mm) was drilled axially in each sample to represent a wellbore. After grinding, a high-strength fracturing pipe was inserted, and the epoxy resin and curing agent were uniformly mixed and sealed [31]. The experimental sample is shown in Figure 1.

2.2. Experimental Method

A self-developed supercritical CO₂ fracturing and permeability experimental device for shale gas reservoir was used (Figure 2). This apparatus enables fracturing and displacement experiments under multi-field coupling. The system includes gas supply system, pressure chamber, triaxial cell, gas detection system, and control/data-acquisition system. For precise flow measurement within the gas supply and detection systems, a D07-11 model flowmeter (Beijing Huacheng Electronics Co., Ltd., Beijing, China) was selected, offering an accuracy of ±1%. To monitor and control pressure within the pressure chamber and triaxial cell, a Keller PAA-33X model pressure sensor (The company Keller Pressure, Winterthur, Switzerland) was employed, providing high accuracy of ±0.1%. For gas composition analysis within the gas detection system, a GC-2060 model gas chromatograph (Shanghai Ruimin Instrument Co., Ltd., Shanghai, China) was utilized, with an accuracy of ±1.5%.

In order to simulate the CO₂-ESGR and CO₂ storage process and analyze the evolution mechanism of shale gas reservoir permeability characteristics during ScCO₂ fracturing displacement process, the fracturing experiments were carried out on each shale sample, and the changes in shale permeability characteristics and fracture propagation before and after fracturing were analyzed. Fracturing shale sample was selected to carry out the experiment of ScCO₂ displacing CH₄ in shale under the stress and temperature.

2.2.1. Fracturing Experiment

ScCO₂ fracturing was carried out under simulated reservoir conditions (axial pressure = 10 MPa, confining pressure = 10 MPa, temperature = 50 °C, injection rate: 30 mL/min). Shale permeability tests (gas: He, pressure: 0–5 MPa) were carried out under the same stress and temperature conditions before and after fracturing, and CT scan was carried out before and after fracturing.

2.2.2. Displacement Experiment

Fractured shale sample was used for CO₂ displacement experiments under different injection pressures and stress conditions. For displacement experiments with variable injection pressures, axial and confining pressures were set to 15 MPa, initial CH₄ pressure to 5 MPa, and CO₂ injection pressures to 6 MPa and 9 MPa, respectively, to explore the effect of different phases of CO₂ on the displacement effect of CH₄. A conventional recovery experiment with 5 MPa CH₄ was carried out as the comparison group. In the displacement experiment under different stress conditions, the initial pressure of CH₄ is set to 5 MPa, the injection pressure of CO₂ is set to 9 MPa, and the axial pressure and confining pressure are set to 10 MPa, 15 MPa and 20 MPa, respectively.

3. Results and Discussion

3.1. Permeability Characteristics of Shale Before and After Fracturing

3.1.1. Pressure Curve Analysis in Fracturing Process

Figure 3 shows the pressure-time curve during the fracturing of shale with supercritical CO₂. The fracture pressure of the shale sample was 31.4 MPa. As the fracturing process progressed, the pressure curve initially increased rapidly, then gradually stabilized, followed by a rapid surge until the sample fractured and the pressure subsequently declined. Based on the changes in pressure, the fracturing process consists of four steps.: (Ⅰ) cavity filling, (Ⅱ) slow pressure accumulation, (Ⅲ) rapid pressure increase, and (Ⅳ) fracturing failure. During stage Ⅰ, the injected CO₂ gas rapidly entered the non-porous cavities and large pores of the shale, leading to rapidly rise in CO₂ pressure. In stage Ⅱ, due to the high compressibility of CO₂, the pressure increased slowly as the gas was gradually injected. In addition, CO₂ in the large pores began to diffuse into the micro-pores of the shale, causing the pre-existing cracks within the shale to gradually open and expand. In stage Ⅲ, as CO₂ continued to be injected, when the CO₂ pressure reached 7.38 MPa, it transitioned into a supercritical state, and CO₂ pressure began to increase rapidly. This is because the phase transition of CO₂ at the supercritical state causes a rapid increase in its density and a significant reduction in its compressibility. The continuous injection of CO₂ led to a rapid increase in pressure and the rapid expansion of cracks until the shale fractured. In stage Ⅳ, the fracturing of the shale created penetrating cracks, increasing the internal volume of the shale and thus rapidly decline the CO₂ pressure, which also resulted in an increase in shale permeability.

The CT scans of the shale samples before and after fracturing are displayed in Figure 4. Prior to fracturing, the shale samples’ cross-sections were uniform, have smooth surfaces, and devoid of visible scanning cracks. The shale had few pre-existing cracks, indicating good sample integrity and extremely low permeability. After fracturing with supercritical CO₂, the shale samples exhibited distinct fractures on both the upper and lower surfaces, with similar crack patterns on the upper and lower surfaces, indicating that the cracks had penetrated from top to bottom. The cracks in the sample all extended perpendicular to the direction of the minimum principal stress. The crack propagation pattern showed that the cracks in the shale mainly extended along the bedding planes.

3.1.2. Analysis of Permeability Characteristics

Figure 5 shows the permeability curves of the shale before and after fracturing under the same stress conditions. Before fracturing, the permeability of the shale samples under different He pressures ranged from 1.38 to 9.54 × 10⁻⁵ mD. After fracturing with ScCO₂, the permeability of the shale samples ranged from 1.32 to 2.47 × 10⁻² mD, representing an increase in three orders of magnitude, indicating a significant enhancement in permeability due to CO₂ fracturing. Figure 5 shows that as the He pressure increased, the permeability of the unfractured shale declined rapidly at first and then gradually plateaued. In contrast, for the fractured shale, the permeability initially declined and then gradually rose with increasing gas pressure. This is primarily because the unfractured shale is tight rock with few natural fractures, and its stress sensitivity is low under external stress. The flow of gas within the shale is mainly dominated by Knudsen flow, transitional flow, and slip flow. As the pressure increases, the mean free path of gas molecules diminishes, the probability of interactions between molecules and pore walls decreases, and the probability of intermolecular collisions increases, leading to a decrease in Knudsen diffusion and slip effects. Although the effective stress gradually decreases as increasing pressure, its low stress sensitivity results in a relatively minor impact on permeability, causing the permeability to decrease with increasing pressure. For the fractured shale, the macroscopic fractures after fracturing leads to the dominance of continuous flow and slip flow in the gas flow within the shale. The macroscopic fractures in the shale close and open, exhibiting high stress sensitivity under the effect of effective stress. As the gas pressure increases, the slip effect gradually weakens, causing the permeability to decrease by approximately 51.0% [7]. However, with a further rise in gas pressure, the effective stress exerted on the shale under constant stress conditions gradually decreases, and this effect plays a dominant role in the permeability, which leads to a partial recovery of permeability by about 18.4% from its lowest value.

3.2. Breakthrough Curves of CO₂ Displacement of CH₄

Figure 6 shows the breakthrough curves of CO₂ displacement of CH₄ under varying injection pressures (a) and stress conditions (b). The changes in the molar fractions of CH₄ and CO₂ over time can be categorized into three primary stages: In the first stage, CO₂ mixes with CH₄ within the shale fractures, leading to dispersion. The presence of CH₄ hinders the movement of CO₂, which migrates towards the outlet under pressure differences, displacing CH₄. In the second stage, CO₂ breakthrough occurs within the shale, and CO₂ is detected at the outlet. A significant amount of free CH₄ is rapidly discharged from the fractures, causing a rapid increase in the molar fraction of CO₂. Simultaneously, CO₂ begins to diffuse into the shale matrix and competes with CH₄ for adsorption. Due to the shale’s preferred CO₂ adsorption, the adsorbed CH₄ gradually desorbed. In the third stage, the growth rate of CO₂ mole fraction and the decline rate of CH₄ gradually decrease. Since CH₄ in the shale fracture is discharged in large quantities in the second stage, the monitored CH₄ is mainly CH₄ desorbed in the matrix, so the change in gas mole fraction of CO₂ and CH₄ gradually slows down.

From Figure 6a, it can be observed that as the CO₂ injection pressure increases, the breakthrough curves become steeper. At an injection pressure of 6 MPa, the breakthrough time of CO₂ is 34.9 min, which decreases to 14.9 min at 9 MPa. Under higher injection pressures in the second stage, the increase rate in the molar fraction of CO₂ is higher, and the time to reach the third stage is 171.7 min at 6 MPa and 71.7 min at 9 MPa. This is primarily due to the higher-pressure difference between the inlet and outlet under the same stress conditions, along with reduced effective stress on the shale, which accelerates CO₂ migration. Additionally, the diffusion rate and dispersion coefficient of CO₂ increase with pressure, enhancing CO₂/CH₄ mixing and facilitating displacement [27].

From Figure 6b, it is evident that as stress increases from 10 MPa to 20 MPa, CO₂ breakthrough times are 8.6, 14.9, and 16.76 min, respectively. Under higher stress in the second stage, the increase rate in CO₂ molar fraction is lower. The time to reach the third stage is 56.6, 71.7, and 92.8 min as increasing stress. This occurs because increased effective stress compresses internal fractures, reducing CO₂ flow rate under identical injection pressure. Reduced fracture width also decreases CO₂/CH₄ diffusion rates, slowing displacement.

3.3. Flow Curve of CO₂ Displacing CH₄

Figure 7 shows the flow rate curves under varying injection pressures (a) and stress conditions (b). The CH4 flow rate declined sharply initially before decelerating gradually, while the CO2 flow rate rose rapidly upon breakthrough and then began to level off. At 240 min, the CO₂ flow rate increased by 38.71% with rising injection pressure, while it decreased by up to 33.33% under increasing stress. In the initial displacement stage, CH₄ in the shale fracture is largely displaced by high-pressure CO₂, and the CH₄ flow rate is high. With the mixing of CO₂ and CH₄, CH₄ in the fracture gradually decreases. Through continuously injecting CO₂ into CH₄, the CH₄ flow rate decline precipitously, while the CO2 flow rate rises correspondingly. As the CH₄ in the fracture is discharged, the flow curves of CH₄ and CO₂ gradually slow down. At this time, the flow of CH₄ is mainly contributed by the desorbed CH₄. By comparing Figure 6 and Figure 7, it can be found that the time from the second stage to the third stage also has a good consistency. In the third stage, with the continuous adsorption of CO₂ by shale, the permeability gradually decreases, so the flow of CH₄ and CO₂ also gradually diminish.

Figure 7a shows that the CH₄ flow curves under the three conditions. During the initial stage of conventional recovery and CO₂ displacement, the CH₄ flow rate gradually rises in response to higher CO₂ injection pressure, while in the later stage of displacement, the flow of CH₄ is higher under the conditions of conventional recovery and lower displacement pressure. This is because the CH₄ flow in the initial stage of displacement is mainly dominated by free CH₄ in the fracture, the flow of CH₄ and CO₂ at the outlet of the shale is higher under higher displacement pressure, and the decrease rate of free CH₄ in the shale fracture is also higher. Therefore, in the middle stage of displacement, the CH₄ under conventional recovery and lower displacement pressure conditions is higher. In the later stage, compared with the conventional recovery conditions, the flow of CH₄ under CO₂ displacement conditions is lower, which may also be caused by the further swelling of shale adsorption of CO₂ [27]. From Figure 7b, it can be found that the CH₄ and CO₂ flow rates decline with increasing stress, it is induced by the alteration of effective stress response resulting from the variation in external stress. The closure of the fracture will hinder the injection of CO₂ and the displacement of CH₄.

3.4. Parameters of CO₂ Displacement of CH₄

Table 1. Parameters of CO₂ displacement CH₄ under different injection pressure and stress.

Condition		CH4 Injection (L)	CH4 Production (L)	CH4 Production Rate (%)	CO2 Injection (L)	CO2 Storage (L)	CO2 Storage Rate (%)
Injection pressure	0 MPa	6.47	3.09	47.75	-	-	-
	6 MPa	6.16	4.56	73.96	6.75	2.20	32.66
	9 MPa	5.99	4.22	70.45	13.12	3.95	30.11
Stress	10 MPa	6.13	4.63	75.51	15.90	4.01	25.17
	15 MPa	5.99	4.22	70.45	13.12	3.95	30.11
	20 MPa	5.69	3.58	62.83	11.62	3.76	32.38

shows the parameters of CO₂ displacement of CH₄ under varying injection pressures and stress conditions. Compared to the CH₄ production rate under conventional recovery conditions, the CH₄ production rate after CO₂ displacement is higher, indicating that CO₂ displacement of CH₄ within the shale effectively increases CH₄ production. Additionally, it can be observed from Table 1 that as the injection pressure increases, the CH₄ production rate and CO₂ storage rate decrease, even with a higher total injection of CO₂. As stress increases, the recovery rate of CH₄ decreases, whilst the storage rate of CO₂ increases. Figure 8 shows the cumulative flow rate curves of CH₄ under different injection pressures and stress conditions during CO₂ displacement. It is evident that in the initial stage of displacement, the cumulative flow rate of CH₄ is higher as increasing injection pressure, while in the later stages of displacement, the cumulative flow rate of CH₄ is lower. This is primarily because, in the initial stage of displacement, the higher injection pressure leads to a large amount of CH₄ being discharged from the fractures, resulting in a higher cumulative flow rate of CH₄ at this time. As the CH₄ within the fractures continues to be discharged, in the later stages of displacement, the higher injection pressure leads to a decrease in the mass transfer coefficient between the shale matrix and fractures, i.e., the diffusion rate of gas from the matrix to the fractures decreases. Therefore, the role of CO₂ in displacing and desorbing CH₄ decreases [25], leading to a slower rate of increase in the cumulative flow rate of CH₄ in the later stages, which is also a reason for the decrease in the CH₄ production rate and CO₂ storage rate. The fractures within the shale are further compressed under high stress conditions, leading to a decrease in the fluidity of CH₄ within the fractures and a decrease in the production rate. Additionally, high stress promotes the selective adsorption of CO₂ by the shale, which may also be a reason for the increase in the CO₂ storage rate. Therefore, it is of great significance to select appropriate injection pressure according to reservoir conditions to ensure CH₄ recovery and CO₂ storage rate. Although excessive injection pressure can greatly increase CH₄ production in the short term, it is not conducive to the recovery of CH₄ in shale matrix in the later stage.

4. Conclusions

In this study, ScCO₂ fracturing tests and displacement tests under multi-field coupling conditions were carried out innovatively, and the kinetics of CO₂ displacing shale gas and the fracturing properties of shale under different stress and pressure conditions were analyzed, which filled the relevant research gaps. The specific conclusions are as follows:

(1) The pressure curve of the ScCO₂ fracturing process showed a trend of rapid increase first and then gradually stabilized, followed by a rapid increase until the sample was fractured and then decreased. According to the pressure change, the fracturing process consists of four steps: (I) cavity filling, (II) slow pressure accumulation, (III) rapid pressure increase, and (IV) fracturing failure.

(2) The permeability of unfractured shale is extremely low. The permeability of shale samples before fracturing is 1.38–9.54 × 10⁻⁵ mD, while the overall permeability increases by three orders of magnitude after fracturing, indicating that ScCO₂ has a good fracturing effect. As the gas pressure increases, the permeability of unfractured shale decreases, while that of fractured shale decreases first and then increases gradually. This primarily results from the enlargement of pore size in shale during fracturing, which leads to the dominance of internal continuous flow and slippage flow.

(3) Higher injection pressures and lower stresses cause CO₂ to break through earlier. Compared to the CH₄ production rate under conventional recovery conditions, the CH₄ production rate has increased after CO₂ displacement. In the initial stage of displacement, as the injection pressure increases, the cumulative flow rate of CH₄ is higher, but in the later stage of displacement, the cumulative flow rate of CH₄ is lower, leading to a decrease in the CH₄ production rate and CO₂ storage rate. High stress can inhibit CO₂ injection and CH₄ outflow, reducing the CH₄ production rate. However, high stress also promotes the preferential adsorption of CO₂ by shale, concluding in a higher CO₂ storage rate.