Investigation on Flowback Efficiency and Permeability Damage Characteristics in Coal Reservoirs: A Case Study of the Midong Block, Xinjiang

Abstract

The Midong Block is currently a primary target for coalbed methane (CBM) exploration and development in Xinjiang. However, fracturing operations in this region generally exhibit low flowback rates, which escalate the risk of reservoir damage and ultimately suppress daily gas production. To elucidate the impact of various geological and engineering factors on flowback efficiency and permeability damage, as well as their underlying mechanisms, this study conducted fracturing fluid flowback simulation experiments. The pulse-decay permeability measurement and weighing methods were employed to quantify the variations in flowback rates and permeability damage intensities under different conditions. Experimental results indicated that the permeability damage rate in the Xishanyao Formation coal samples ranged from 3.12% to 92.86% after flowback, with 92% of the samples exhibiting a flowback rate of less than 10%. This significant impairment was primarily attributed to the synergistic effects of stress-induced fracture closure, clay mineral hydration swelling, and coal fines migration. Specifically, elevated confining pressures and prolonged soaking times exacerbated reservoir damage. A low flowback pressure differential intensified the water locking effect, hindering fluid recovery. Notably, the flowback velocity displayed a U-shaped velocity sensitivity profile. In the low-temperature regime, damage characteristics fluctuated, controlled by competitive thermal–hydro–mechanical (THM) coupling mechanisms.

1. Introduction

With estimated coalbed methane (CBM) resources of 3.83 × 10¹² m³, the Junggar Basin ranks as the third-largest CBM-bearing basin in China, following the Qinshui and Ordos Basins. Breakthroughs in CBM development have already been achieved in areas such as Fukang and Baijiahai [1,2]. Specifically, the Midong Block is situated in the piedmont thrust belt at the northern foot of Bogda Mountain, on the southern margin of the Junggar Basin, covering an area of 109 km² (Figure 1). From a tectonic perspective, the northward subduction of the Indian Plate since the Late Cretaceous (Yanshanian period) eventually led to its collision with the Eurasian Plate. Influenced by the far-field effects of this collision, the Bogda Mountain gradually uplifted. During the Middle-Late Jurassic, intense thrusting along the northern marginal reverse faults caused the overall uplift of the Bogda Mountain, placing it in a wedge-top position. At this stage, the northern structural belt functioned as a foredeep depression, facilitating the deposition of thick Jurassic coal-bearing lacustrine-deltaic systems. The Middle-Lower Jurassic Badaowan and Xishanyao Formations serve as the primary coal-bearing strata in this region (Figure 2). Since the Pliocene, intensified far-field compression from the India–Tibet collision has driven continuous, strong uplift of the Bogda Mountain, forming a highly deformed thrust structure along its northern margin. Consequently, the strata are flexured, subsiding, and exhibit high-steep, near-vertical attitudes (Figure 2). The coal seam dip angles in the Midong Block decrease from south (steep, 60–80°) to north (gentle, 40–50°), with maximum dips approaching 90°, forming an asymmetrical syncline.

Currently, the proven geological reserves of recoverable CBM in the Midong Block stand at 100.26 × 10⁸ m³, making it a primary focal point for CBM exploration and development in Xinjiang. Seams No. 42–43 and No. 45 are identified as the primary target seams. The combined thickness of Seams No. 42–43 ranges from 10 to 55 m (average 31.4 m), while Seam No. 45 ranges from 20 to 55 m (average 37.1 m). The roof and floor lithologies are dominated by mudstone and silty mudstone, with localized development of argillaceous siltstone and siltstone. Gas content varies significantly: Seams No. 42–43 range from 0.17 to 12.35 m³/t (average 6.08 m³/t), and Seam No. 45 ranges from 0.19 to 14.22 m³/t (average 5.6 m³/t). Macroscopically, the coal is primarily semi-bright, followed by semi-dull coal, with an organic content of 83.62–91.34% and an ash content of 11.65–21.84%.

Field operations reveal that the coal bodies in the Midong Block are predominantly of primary structure, with localized cataclastic to granulated structures. Gas production is influenced by a complex interplay of factors, including reservoir damage, primary geological conditions, and stimulation intensity. A positive correlation has been observed between fracturing fluid flowback rate and cumulative gas production; explicitly, excessively low flowback rates escalate the risk and severity of reservoir damage, thereby reducing permeability and daily gas output. Field statistics indicate average flowback rates of 3.9% for dip angles of 0–30°, 12.2% for 30–60°, and 7.0% for 60–90°. These non-linear variations suggest that high-steep structural features are not the sole determinant of flowback efficiency. Instead, actual flowback performance is governed by a complex synergy of geological, fracturing, and flowback parameters. Given the impending demand for large-scale fracturing in this block, there is an urgent need to optimize high-efficiency post-fracturing flowback strategies. Therefore, it is critical to elucidate the variation patterns and underlying mechanisms of flowback efficiency and permeability damage in the coal reservoirs of the Midong Block.

Following fracturing operations in CBM wells, timely flowback of the fracturing fluid is imperative to minimize its residence time within the coal seams, thereby mitigating reservoir damage. Under external stress, coal exhibits high susceptibility to deformation and failure, generating coal fines. The migration behavior of these fines within cleats and hydraulic fractures evolves with changing fluid flow regimes. The redistribution of coal fines subsequently alters the spatial connectivity of the porous media, impairing reservoir permeability and fracture conductivity [3,4,5,6,7]. Considerable research has focused on the Jamin effect induced by fluid retention and methods for its mitigation [8,9,10]. It is generally posited that fractured coal samples are more sensitive to the degree of fluid retention regarding permeability and flowback efficiency [11]. Furthermore, the hydrophilicity and natural fracture networks of coal reservoirs can induce water, velocity, alkali, and acid sensitivities, leading to a significant decline in permeability [12]. Tao et al. (2017) [13] observed that while permeability damage increases with fluid flow velocity and injection volume, the rate of damage increment gradually diminishes. Additionally, the presence of clay minerals in the coal matrix makes the reservoir prone to hydration swelling, which reduces porosity and permeability [14,15]. The interaction between fracturing fluid migration and clay minerals triggers particle migration, plugging, and swelling, further exacerbating permeability reduction and reservoir damage [16].

In summary, the synergistic effects of flowback processes, geological conditions, clay hydration, and coal fines migration significantly impact the natural cleats and pore throats of coal reservoirs. This synergy often results in irreversible permeability damage and compromised flowback efficiency. Inefficient flowback leads to gas production falling below expectations or total cessation of production, causing substantial economic losses. Despite existing studies on CBM reservoir damage, research specifically addressing the flowback rate and associated damage characteristics in the Midong Block remains scarce. Moreover, there is a notable lack of analysis regarding the quantitative correlation between flowback efficiency and permeability damage rates. To clarify the influence of geological and engineering factors on these parameters within the complex structural setting of the Midong Block, and to elucidate the underlying mechanisms, this study conducted laboratory fracturing fluid flowback simulation experiments. The findings provide a critical theoretical basis for designing high-efficiency flowback strategies and optimizing CBM development in the Midong Block.

2. Materials and Methods

2.1. Sample Preparation

Coal samples were collected from the outcrops of the Xishanyao Formation in Tiechanggou Town, Midong District, Urumqi, Xinjiang. Subsequent to retrieval, the coal blocks were machined into standard cylindrical core plugs with dimensions of ϕ25 mm × 50 mm using a diamond wire cutting machine to minimize mechanical damage. The representative samples and the preparation workflow are illustrated in Figure 3. Furthermore, to investigate the mechanisms underlying hydration-induced permeability damage in the target block, X-ray diffraction (XRD) analyses (Model Ultima IV) were performed on the Xishanyao coal samples to characterize both the whole-rock mineralogy and clay mineral compositions.

2.2. Experimental

Based on preliminary exploration and well logging data, the vertical burial depth of coal seams in the Midong Block ranges from 524.26 to 1820 m. The formation temperature varies between 18.7 and 39.2 °C, and the bottomhole pressure (BHP) ranges from 12.53 to 22.08 MPa. Given the significant dimensional disparity between laboratory core plugs and the actual field reservoir, experimental parameters were scaled down to account for size effects. The soaking time was converted based on a 24:1 scaling ratio; specifically, a 24-h field shut-in period was equivalent to a 1-h laboratory soaking duration. Similarly, the flowback velocity was scaled to 1/200 of the field choke flowback rate [17,18]. Conversely, the flowback pressure differential was maintained consistent with field operational settings. The specific ranges for all experimental variables are detailed in

Table 1. Parameter settings for fracturing and flowback simulation factors.

Confining Pressure	Temperature	Soaking Time	Flowback Pressure Differential	Flowback Rate
MPa	℃	h	MPa	mL/min
14	20	0.5	6	0.01
16	25	1.0	9	0.05
18	30	1.5	12	0.10
20	35	2.0	15	0.50
22	40	2.5	18	1.00

. The experimental fracturing fluid was formulated to simulate the field slickwater system, consisting of distilled water, 2% potassium chloride (KCl), and a red tracer. Distilled water was employed as the simulated flowback fluid.

2.3. Experimental Procedures

The detailed experimental workflow is illustrated in Figure 4. Initially, prior to fracturing fluid injection and shut-in, the initial permeability of the coal core (K₀) was measured using a pulse-decay permeameter. Subsequently, the simulation of fracturing fluid invasion and shut-in soaking was conducted within a thermostatic chamber. Upon fluid breakthrough at the outlet end, the soaking time (t_soak) and the invasion volume (V₁) were recorded. Following the soaking period, the core was retrieved, and surface moisture was carefully removed using absorbent paper. A reverse displacement flowback test using distilled water was then performed. The flowback start time was synchronized with the activation of the high-precision injection pump, and the test duration was set to 1.0 h. Upon completion, the flowback volume (V₂) was recorded. Finally, the post-flowback permeability (K_f) was measured. To minimize stress-induced damage to the core sample during permeability measurements, the confining pressure was maintained at a conservative 3 MPa. The study adopted the control variable method; to mitigate experimental error, volume readings and permeability measurements were repeated three times at each step, and the average values were utilized for analysis.

To quantify the impact of fracturing fluid invasion and flowback processes on reservoir properties under various experimental conditions, the permeability damage rate and flowback efficiency were calculated using Equation (1) and Equation (2), respectively:

$$D_K={\displaystyle \frac{K_0-K_f}{K_0}}\times 100\%$$

(1)

$$\eta ={\displaystyle \frac{V_1-V_2}{V_1}}\times 100\%$$

(2)

where D_K denotes the permeability damage rate (%); K₀ represents the initial permeability of the core sample (mD, 1 mD = 10⁻¹⁵ m²); K_f represents the permeability after flowback (mD); η denotes the flowback efficiency (%); V₁ is the volume of fracturing fluid invasion (mL); V₂ is the volume of fracturing fluid flowback (mL).

3. Results

3.1. Analysis of Mineral Compositions

Mineral composition and distribution are intrinsic factors governing the hydration-induced deformation and mechanical strength of rock. To investigate the mechanisms underlying hydration-induced permeability damage in the target block, X-ray diffraction (XRD) was employed to perform whole-rock analysis and clay mineral characterization on the coal samples. This analysis aimed to determine the mineralogical assemblage and content, thereby elucidating their influence on permeability evolution.

Figure 5 illustrates the mineral composition of the coal samples. The mineral assemblage was dominated by calcite and ankerite, which collectively accounted for 60% of the total mineral content. Minor amounts of siderite, clay minerals, and quartz were also detected. Among these, the hydration swelling and dispersion of clay minerals play a pivotal role in permeability variations. Specific analysis of the clay fraction revealed that the clays primarily consisted of illite, illite/smectite (I/S) mixed-layers, and kaolinite, accompanied by trace amounts of chlorite. No discrete smectite was detected. Notably, the I/S mixed-layer constituted a substantial proportion (48.8%) of the total clay content. Due to its specific layered structure and large specific surface area, the I/S mixed-layer exhibits strong swelling potential upon contact with water. This swelling behavior is identified as the primary internal factor contributing to the deterioration of coal permeability.

3.2. Effect of Confining Pressure

Figure 6 illustrates the influence of confining pressure on the permeability and flowback efficiency of the coal samples. As depicted in Figure 6a, the coal permeability suffered varying degrees of damage following fracturing fluid soaking and flowback. Overall, the permeability damage rate exhibited a positive correlation with confining pressure, increasing progressively as the pressure rose. Correspondingly, Figure 6b indicates that flowback efficiency also increased with confining pressure; however, the overall recovery remained poor, with all values falling below 6%.

Coal reservoirs function as dual-porosity media consisting of a matrix and a network of cleats or fractures. Because of a generally low elastic modulus, these reservoirs exhibit significant stress sensitivity. Increasing confining pressure compresses and reduces the aperture of primary flow channels (i.e., macropores, cleats, or fractures) [19]. According to the Young–Laplace equation, this aperture reduction elevates capillary resistance within the coal core. This elevated resistance impedes fluid mobility. Consequently, fluid retention causes distinctly more severe permeability damage under high confining pressure than under low-pressure conditions.

Conversely, flowback efficiency follows a different mechanistic trend. Low confining pressure amplifies spontaneous imbibition. Fracturing fluid penetrates deep into the matrix micropores and hinders fluid recovery. In contrast, high confining pressure compresses pores and increases imbibition resistance. This compression restricts fluid invasion into the matrix. Capillary forces weakly bind the fluid retained in larger flow channels, such as macropores or fractures. The displacement pressure differential readily expels this loosely bound fluid [20,21].

3.3. Effect of Temperature

Figure 7 illustrates the variation laws of permeability damage and flowback efficiency with respect to temperature. As shown in Figure 7a, the coal permeability suffered varying degrees of damage following fracturing fluid soaking and flowback; however, the impact of temperature on the permeability damage rate did not exhibit a distinct or monotonic pattern. Correspondingly, Figure 7b indicates that flowback efficiency also lacked a clear correlation with temperature. Nevertheless, an inverse relationship was generally observed between flowback efficiency and permeability damage rate; specifically, coal samples with minimal permeability damage yielded the highest flowback efficiency, reaching 16.67%.

Competitive mechanisms and sample heterogeneity explain the lack of a linear temperature trend. Liu et al. (2011) [22] demonstrated that within a low-temperature range, thermal expansion of coal matrix grains primarily drives permeability reduction. Under confined conditions with fixed pressure, the matrix expands inward. This inward expansion compresses the effective aperture of macropores, cleats, or fractures and induces permeability damage.

Visual inspection of the tested core samples corroborated this mechanism. Samples exhibiting severe permeability damage contained distinct natural fractures. Conversely, samples with minor damage lacked macroscopic cracks. This observation suggests that natural fractures dominate the response. Furthermore, synergistic hydration swelling of clay minerals further plugs these macropores or fractures [23]. Regarding flowback efficiency, the blockage of primary flow channels elevates capillary resistance. This elevated resistance “locks” a portion of the fluid within the pore structure. The resulting fluid immobilization ultimately reduces the overall recovery rate [24].

3.4. Effect of Soaking Time

Figure 8 presents the effects of soaking time (simulating shut-in periods) on permeability and flowback efficiency after the core was fully displaced by the fracturing fluid. As observed in Figure 8a, the coal permeability incurred varying degrees of damage following fracturing fluid soaking and flowback. Overall, the permeability damage rate increased gradually with the extension of soaking time, eventually tending towards stabilization (or equilibrium) after 2 h. Correspondingly, Figure 8b shows that the flowback efficiency for all samples remained below 8%. The flowback efficiency decreased gradually with increasing soaking time and also reached a plateau. The declining trend of flowback efficiency showed a strong inverse correlation with the increasing permeability damage.

Because the fracturing fluid is water-based, hydration swelling of clay minerals dominates the damage mechanism. Swelling represents a time-dependent process. Water molecules gradually diffuse into the clay crystal layers and specifically invade the illite/smectite (I/S) mixed layers. Prolonged fluid exposure exacerbates this swelling. This expansion induces the detachment and migration of coal fines, which subsequently plug pore throats. Furthermore, retained polymers or surfactants from the fracturing fluid system cause physical plugging and further aggravate permeability damage.

Regarding flowback efficiency, extended soaking time promotes greater spontaneous imbibition of fluid into the coal matrix. This imbibition renders the trapped fluid difficult to recover during the flowback phase [25]. Chen et al. (2022) [26] demonstrated that excessive shut-in periods trigger severe water blocking (the Jamin effect). This effect drastically reduces both gas permeability and flowback rates. Permeability damage and flowback efficiency stabilized after 2 h. This stabilization indicates that clay mineral hydration swelling and fluid imbibition reached their peak capacities within the standard core plugs.

3.5. Effect of Flowback Pressure Differential

Figure 9 illustrates the effects of the flowback pressure differential on permeability and flowback efficiency after the core was fully saturated with fracturing fluid. As observed in Figure 9a, the coal permeability suffered varying degrees of damage following fracturing fluid soaking and flowback. Overall, the permeability damage rate increased significantly as the flowback pressure differential decreased. Notably, when the pressure differential dropped below 12 MPa, the permeability damage rate surged to over 90%. Correspondingly, Figure 9b indicates that flowback efficiency is positively correlated with the pressure differential. However, when the pressure differential was less than 12 MPa, the flowback efficiency remained negligible and stable.

The extremely small radii of pore throats in coal reservoirs generate substantial capillary resistance. Furthermore, the Jamin effect creates additional resistance to fluid flow. Fluid mobilization occurs only when the flowback pressure differential exceeds this cumulative resistance [24,27]. Driving pressures close to or below this resistance threshold expel only a minimal fluid volume. The water locking effect traps the majority of the fluid and causes severe permeability damage. The synergistic effect of clay mineral swelling further exacerbates this damage.

Because of the ultra-low permeability of coal reservoirs, fluid flow deviates from linear Darcy’s law. Instead, it follows a non-linear flow regime characterized by a threshold pressure gradient (TPG). A flowback pressure differential only marginally higher than the TPG causes sluggish or stagnant fluid flow within micro-fractures and micro-pores. This stagnation reduces flowback efficiency [27]. Moreover, the pressure differential dictates the sweep radius of the pressure drop funnel. A low pressure differential limits the pressure propagation distance. This limited reach fails to mobilize fluid trapped in distal micro-pore throats and ultimately diminishes flowback efficiency.

3.6. Effect of Flowback Velocity

Figure 10 illustrates the variation laws of permeability and flowback efficiency with respect to flowback velocity after the core was fully saturated with fracturing fluid. As shown in Figure 10a, the coal permeability suffered varying degrees of damage. Overall, as the flowback velocity increased, the permeability damage rate exhibited a trend of initial decrease followed by an increase (a typical U-shaped curve). The maximum permeability damage rate recorded was 65.63%, while the minimum was 5.15%. Correspondingly, Figure 10b indicates a negative correlation between flowback efficiency and permeability damage rate. With the increase in flowback velocity, the flowback efficiency initially increased and subsequently declined, though it maintained an overall increasing trend compared to static conditions.

As flowback velocity increases from low to moderate, the fluid progressively overcomes capillary resistance. This fluid action partially mitigates the water locking effect. Consequently, the flow clears specific pore channels and reduces the permeability damage rate [28]. The fragile coal matrix contains abundant coal fines and clay minerals. Increasing velocity generates a hydrodynamic drag force that mobilizes and flushes out a portion of these fines. At a flowback velocity of 0.50 mL/min, coal fine deposits clearly adhered to the inner wall of the outlet graduated cylinder.

Conversely, the transition from moderate to high velocity intensifies the flow and mobilizes a massive volume of coal fines or particulates. These migrating particles enter narrow pore throats and accumulate. This accumulation physically plugs the throats and causes severe permeability damage [5,29]. Simultaneously, synergistic clay mineral swelling further obstructs the primary flow channels. This combined obstruction significantly aggravates permeability damage. Regarding flowback efficiency, lower permeability damage reduces flow resistance and naturally elevates fluid recovery. However, high flow velocities completely cut off the fluid flow channels through particle plugging. This sudden blockage restricts fluid drainage and decreases flowback efficiency. Overall flowback efficiency remained below 10%. This low recovery indicates that the synergistic interaction between clay mineral swelling and pore throat plugging exerts the dominant influence on the reservoir.

3.7. SEM Image Analysis

To further verify the plugging of fluid flow channels by coal fines and clay mineral swelling, this study conducted SEM image analysis on the coal samples following the flowback simulation experiments. Figure 11 displays the results, where Figure 11b,c provide locally magnified views of Figure 11a. Figure 11b reveals that fine particles accumulated at specific pore throat locations within the coal matrix. Figure 11c illustrates the interlayer expansion of layered clay minerals following water-induced swelling. The simultaneous occurrence of fine particle accumulation and clay mineral swelling at the same flow location highly facilitates channel plugging. Furthermore, Figure 11d shows weakly cemented areas within the coal matrix. Under external forces, these cements fragment and generate fine particles. Flowing fluid mobilizes and transports these particles. This migration can subsequently cause particle accumulation and completely plug the flow channels.

4. Discussion

Synthesizing the experimental results, it is evident that the coal reservoirs of the Xishanyao Formation in the Midong Block are characterized by extremely low permeability (0.03–2.65 mD) and pronounced post-flowback damage, with damage rates ranging from 3.12% to 92.86% and 92% of samples exhibiting a flowback efficiency of less than 10%. The mechanisms driving these phenomena are multifaceted. Specifically, confining pressure influences the observed “high damage yet relatively higher flowback” phenomenon primarily through the dual effects of stress-induced compression and the inhibition of fracturing fluid leak-off. Regarding soaking time, the formation of trapped fluid, induced by the time-dependent hydration swelling of clay minerals and spontaneous capillary imbibition, constitutes the dominant mechanism for damage accumulation. Simultaneously, flowback performance is significantly governed by the Threshold Pressure Gradient (TPG) and velocity sensitivity; a low flowback pressure differential fails to overcome capillary resistance, resulting in severe water locking characterized by high permeability damage, while the migration of coal fines implies the existence of an optimal flowback velocity to balance fluid mobilization and pore plugging. Additionally, within the low-temperature range, the competitive coupling of matrix thermal expansion and clay hydration further drives the high-damage, low-flowback response.

During actual field operations, various factors do not act in isolation; rather, they collectively drive the transition of dominant damage mechanisms. Initially, a stress-dominated compression mechanism leads to the closure of natural cleats and fractures, thereby restricting the primary flow channels. As the shut-in (soaking) time extends, the mechanism gradually shifts towards a time-dependent mechano-chemical coupling effect. Because the coal matrix is constrained by high external stress, clay minerals are prevented from expanding outward upon hydration swelling. Instead, they are forced to expand inward, causing severe plugging of the already compressed pore throats. Consequently, upon the initiation of flowback, the applied pressure differential and flow velocity must overcome the damage induced by this mechanism. A low pressure differential is insufficient to overcome the high capillary resistance, resulting in a severe water locking effect. Even when the pressure differential is sufficiently high, an optimal flowback velocity must be maintained to avoid secondary plugging caused by the migration of low-strength, hydrated coal fines. Overall, the low flowback efficiency and high permeability damage rate observed in the Midong Block are macroscopic manifestations of a unified mechanism encompassing stress confinement, hydration swelling, and hydrodynamic constraints.

The actual fracturing flowback process in coal reservoirs is synergistically influenced by multiple factors, involving more complex mechanisms. The laboratory experiments conducted in this study have inherent limitations regarding small sample sizes and short simulation durations. First, compared to in situ downhole coal seams under original complex stress states, outcrop coal samples have inevitably undergone weathering and stress relaxation, which may have altered their natural fracture networks, mechanical strength, and inherent wettability. Furthermore, small-scale cylindrical cores cannot fully capture the macroscopic heterogeneity, varying structural dip angles, and large-scale fracture distribution characteristics of the actual Midong Block reservoirs. Second, the simplification of fracturing fluid chemistry in the laboratory may lead to an underestimation of actual reservoir damage. In contrast, field-applied fracturing fluids contain a complex suite of chemical additives, such as surfactants. The current experimental scope fails to fully encompass the retention, adsorption, and physical plugging effects induced by these chemical agents, as well as their complex physicochemical interactions with the coal matrix. Future research should transition toward large-scale, true-triaxial physical simulations utilizing well-preserved downhole cores. This should be coupled with dynamic in situ X-ray Computed Tomography (CT), Scanning Electron Microscopy (SEM), and Energy Dispersive Spectroscopy (EDS) to achieve real-time continuous monitoring during the shut-in and flowback phases. Such approaches will provide a more direct verification of clay mineral hydration effects and coal fine migration plugging at both micro and macro scales.

5. Conclusions

In this study, standard core plugs were prepared from outcrop coal samples collected from the Xishanyao Formation in the Midong Block, Xinjiang. Fracturing fluid displacement, soaking (shut-in), and reverse displacement experiments were systematically conducted to simulate the field fracturing and flowback processes. The study clarified the influence of engineering and geological factors on flowback efficiency and revealed the underlying mechanisms responsible for the low flowback rates observed in coal reservoirs. The primary conclusions are drawn as follows:

• Experimental data indicate that the initial permeability of coal reservoirs in the Xishanyao Formation of the Midong Block ranges from 0.03 to 2.65 mD. Notably, 76% of the samples exhibit an initial permeability below 1 mD. Post-flowback permeability damage rates span from 3.12% to 92.86%. Furthermore, 92% of the samples yield a flowback efficiency of less than 10%. This high heterogeneity necessitates optimizing shut-in times or fracturing fluid systems according to localized permeability profiles. For this specific block, the recommended shut-in time is approximately 1.0 day. The flowback pressure differential must exceed 12 MPa. Additionally, the optimal flowback velocity should remain around 100 mL/min.
• Confining pressure exacerbated permeability damage through stress-induced compression of pores and natural fractures. Simultaneously, this pressure inhibited the deep leak-off of fracturing fluid into the matrix. This mechanism resulted in a “high damage, relatively high flowback” phenomenon. Conversely, prolonged soaking time induced clay mineral hydration swelling and strong capillary imbibition. These processes trapped fluid within the core and produced a “high damage, low flowback” response.
• Dual mechanisms of the Threshold Pressure Gradient (TPG) and velocity sensitivity govern the flowback process. Severe water locking damage occurred when the flowback pressure differential failed to overcome the capillary resistance threshold. Furthermore, an optimal flowback velocity exists. Excessive flow velocity triggered the migration of coal fines and particulates, which caused secondary damage to the coal matrix.
• In the low-temperature regime (20–40 °C), competitive thermal–hydro–mechanical (THM) coupling mechanisms control reservoir behavior. The synergistic effects of matrix thermal expansion and clay hydration blocked macropores and closed fractures. These mechanisms competed against the flow-enhancing impact of reduced fluid viscosity. Consequently, flowback efficiency proved highly sensitive to pore throat connectivity and maintained a strict negative correlation with the permeability damage rate.