Impacts and Countermeasures of Present-Day Stress State and Geological Conditions on Coal Reservoir Development in Shizhuang South Block, Qinshui Basin

Abstract

This study investigates the reservoir physical properties, present-day stress, hydraulic fracturing, and production capacity of No. 3 coal in the Shizhuang south block, Qinshui Basin. It analyzes the control of in situ stress on permeability and hydraulic fracturing, as well as the influence of geo-engineering parameters on coalbed methane (CBM) production capacity. Presently, the direction of maximum horizontal stress is northeast–southwest, with local variations. The stress magnitude increases with burial depth, while the stress gradient decreases. The stress field of strike-slip faults is dominant and vertically continuous. The stress field of normal faults is mostly found at depths greater than 800 m, whereas the stress field of reverse faults is typically found at depths shallower than 700 m. Permeability, ranging from 0.003 to 1.08 mD, is controlled by in situ stress and coal texture, both of which vary significantly with tectonics. Hydraulic fracturing design should consider variations in stress conditions, pre-existing fractures, depth, structural trends, and coal texture, rather than employing generic schemes. At greater depths, higher pumping rates and treatment pressures are required to reduce fracture complexity and enhance proppant filling efficiency. The Shizhuang south block is divided into five zones based on in situ stress characteristics. Zones III and IV exhibit favorable geological conditions, including high porosity, permeability, and gas content. These zones also benefit from shorter gas breakthrough times, relatively higher gas breakthrough pressures, lower daily water production, and a higher ratio of critical desorption pressure to initial reservoir pressure. Tailored fracturing fluid and proppant programs are proposed for different zones to optimize subsequent CBM development.

1. Introduction

The capacity of coalbed methane (CBM) wells is a crucial indicator for evaluating CBM projects. Geological factors, such as in situ stress, reservoir properties, sedimentary conditions, burial depth, and hydrological conditions, significantly influence CBM productivity [1,2,3,4,5,6]. Engineering factors, including completion techniques, well placement, hydraulic fracturing design, drilling, and production regulation, also play vital roles [7,8,9,10,11]. Among these, reservoir properties, tectonic stress, and hydraulic fracturing design are paramount for CBM production [12].

In China, the complex tectonic movements across various coal-bearing basins result in diverse in situ stress distributions and CBM reservoir properties [13,14,15,16,17]. This complexity necessitates distinct hydraulic fracturing schemes for effective development. In situ stress comprises overburden pressure and tectonic stress. While vertical stress gradients remain relatively constant due to gravity, tectonic stresses are variable and spatially heterogeneous [18]. Different stress states—normal fault, reverse fault, and strike-slip fault—are distinguished by the magnitudes of horizontal and vertical stresses [19]. Regional plate movements typically dictate the dominant stress state and orientation [20].

The orientation, state, and magnitude of stress vary across geological units [21,22,23,24]. Researchers employ borehole measurements, geophysical surveys, and tectonic–geological studies to examine present-day stresses [25,26,27,28]. Identifying in situ stress distributions is critical for assessing coal permeability variations and CBM zonation [29,30,31]. Present stress regimes, magnitudes, and orientations affect in situ permeability by influencing the connectivity, length, and width of natural fracture systems [32]. In CBM gas development, horizontal stress differentials and orientations are crucial for configuring hydraulically induced fractures and ensuring borehole stability [33]. Higher horizontal stress differentials lower breakdown pressure, leading to simpler hydraulic fracture shapes, while lower stress differentials favor complex fracture networks [34,35]. Natural fractures in coal reservoirs can also impact hydraulic fracture propagation under varying stress conditions [36,37].

The Shizhuang south block in the Qinshui Basin, China, with over 1300 production wells, provides substantial data for analyzing the present-day stress state and coal reservoir characteristics and their impacts on CBM development and hydraulic fracturing [38,39,40]. This study comprehensively collects geological, engineering, and production data from the Shizhuang south block. Inversion models are used to systematically analyze the distribution of in situ stress and coal reservoir parameters. The study discusses how these factors influence coal reservoir properties and hydraulic fracturing in the context of tectonic trends. Finally, it offers engineering optimization suggestions for the Shizhuang south block.

2. Geological Settings

Situated in northern China, the Qinshui Basin is a sizable syncline basin with a symmetrical, double-sided structure, encompassing an area of 23,500 km² [41] (Figure 1a). The Shizhuang south blockis located in the southern part of the Qinshui Basin and can be divided into five structural units, and the data used for the modeling in this study came primarily from Zones 2, 3, and 5 (Figure 1b). The primary coal-bearing strata are the Taiyuan Formation of the Upper Carboniferous and the Shanxi Formation of the Lower Permian, consisting mainly of coal seams, mudstone, limestone, sandstone, and siltstone [38] (Figure 1c). The most consistent recoverable coal seams in the basin are coal seam No. 3 (3–9 m) from the Shanxi Formation and coal seam No. 15 (2–8 m) from the Taiyuan Formation, which are the main focus for CBM exploration and extraction. This study analyzes the Shizhuang south block, an area that has been extensively explored with comprehensive data available.

The basin has experienced various tectonic movements since the Carboniferous–Permian period, including the Indosinian, Yanshanian, and Himalayan phases [42]. During the Indosinian movement, the basin underwent north–south tectonic compression without significant geological structures forming. In the Yanshanian period, a SEE-NWW compression stress field caused broad, flat folds and a set of small-scale normal faults oriented NE-NNE. In the early Himalayan period, the tectonic stress shifted from a reversed to a tension stress field in the SEE-NWW orientation, later transitioning to compression in the NEE-SWW direction during the mid–late Himalayan period, resulting in a series of faults [43].

Since the Quaternary neotectonic period, the strata have been under a horizontal compressive force oriented NE-SW, aligning with the Taihang and Huoshan Mountains. This tectonic stress pattern remains constant today. The prevailing stress influencing the Qinshui Basin mainly originates from the Pacific Plate subducting beneath Western Eurasia and the Philippine Plate subducting under the Eurasian landmass. Consequently, the orientation of the maximum horizontal stress (σ_H) in the basin (NE 40~70°) aligns with the principal stress trajectory of China [44] (Figure 2).

3. Methodology

Data on gas content, in situ stress, core samples, hydraulic fracturing, 3D seismic information, production data, porosity, permeability, fracture monitoring, and logging curves were obtained from CBM wells in the region, courtesy of the China United Coalbed Methane Corporation. According to China National Standard GB/T 24504-2009 [46], 16 pore pressure and 16 permeability data points were measured at depths of 558 to 1227 m using the injection/fall-off well test. Multi-loop hydraulic fracturing, following China Industry Standard DB/T 14-2018 [47], was performed on 95 CBM wells to obtain shut-in pressure (p_s) and breakdown pressure (p_f) data in megapascals. Additionally, 53 porosity data points were measured at depths of 451 to 1154 m according to China National Standard GB/T 29172-2012 [48]. A total of 447 gas content data points, measured using the natural desorption method, were collected at depths of 451 to 1349 m according to China National Standard GB/T 19559-2021 [49]. Coal texture discrimination was conducted on 428 core samples from 28 wells, following China National Standard GB/T 30050-2013 [50]. Since the number of data points was insufficient to cover the entire work area, inversion of coal reservoir parameters is required for comprehensive modeling.

The water injection/well drop test recorded the change in bottomhole pressure over time, and parameters such as initial reservoir pressure and permeability were calculated using linear analysis and plate matching methods. Four cycles of in situ stress measurements were performed, recording the p_f in each cycle, and the pressure drop data were obtained by shutting down the well and calculating p_s using the square root of time method.

Stress regimes are commonly represented by σ_H, with the minimum stress (σ_h) and the vertical stress (σ_v). The p_s denotes the minimum bottomhole pressure necessary to maintain the openness of pre-existing fractures, analogous to the normal stress exerted on the vertical fracture surface of rocks [51]:

$${\sigma }_h=p_s$$

(1)

For a vertical borehole, the estimation of σ_H can be achieved through the following equation, assuming the rocks demonstrate impermeability, homogeneity, isotropy, and elasticity [52]:

$${\sigma }_H=3p_s-p_f-p_o$$

(2)

where p_o represents the reservoir pressure.

Multi-loop hydraulic fracturing is an effective approach for assessing in situ stress within deep rock formations [53]. The Kaiser effect is also a reliable technique for identifying stress conditions through acoustic emission (AE) tests and uniaxial compression conducted on drilling cores [54,55]. Chen et al. demonstrated that multi-loop hydraulic fracturing yields outcomes comparable to Kaiser effect stress tests, verifying the method’s reliability [1]. The σ_v is influenced by the thickness and density of overlying layers, with a nearly linear relationship between its magnitude and depth:

$${\sigma }_v={\int }_0^H\rho \left(H\right)g{d}_H$$

(3)

where ρ represents the density, kg/m³ and g represents the gravitational acceleration, m/s².

If density logging data are unavailable, a vertical stress gradient of 0.025 MPa/m can approximate σ_v in the Qinshui Basin, aligning with findings from stress relief measurements in underground coal mines in China [56].

Data on hydraulic fracturing from 95 CBM production wells at depths of 549 to 891 m were gathered from the Shizhuang south block. This information includes details on p_f, p_s, fracturing fluid volume, proppant concentration, and displacement, along with data on coal depth and thickness:

$${\sigma }_h={\displaystyle \frac{v}{1-v}}\left({\sigma }_v-{\alpha P}_o\right)+{\displaystyle \frac{{E\xi }_h}{1-v^2}}+{\displaystyle \frac{v{E\xi }_H}{1-v^2}}+{\alpha P}_o$$

(4)

$${\sigma }_H={\displaystyle \frac{v}{1-v}}\left({\sigma }_v-{\alpha P}_o\right)+{\displaystyle \frac{E{\xi }_H}{1-v^2}}+{\displaystyle \frac{v{E\xi }_h}{1-v^2}}+{\alpha P}_o$$

(5)

$${\xi }_h={\displaystyle \frac{{\sigma }_h-{\alpha P}_o-v\left({\sigma }_H+{\sigma }_v-2{\alpha P}_o\right)}{E}}$$

(6)

$${\xi }_H={\displaystyle \frac{{\sigma }_H-{\alpha P}_o-v\left({\sigma }_h+{\sigma }_v-2{\alpha P}_o\right)}{E}}$$

(7)

where $v$ represents the Poisson’s ratio; $\alpha$ represents the Biot coefficient; ${\xi }_H$ represents the maximum horizontal tectonic strain; ${\xi }_h$ represents the minimum horizontal tectonic strain factor; and $E$ represents the Young’s modulus.

Based on the measured horizontal principal stress, the horizontal tectonic strain is determined. The findings indicate a positive relationship between the horizontal tectonic strain factor and burial depth (Figure 3). A linear conversion equation between burial depth and the horizontal tectonic strain factor is established to calculate in situ stress values for each well in the study area.

$${\xi }_H=0.000 003\times Depth-0.000 6$$

(8)

$${\xi }_h=0.000 000 6\times Depth-0.000 4$$

(9)

Micro-seismic monitoring was conducted on eight wells, ranging in depth from 672 to 982 m, to observe hydraulic fracturing development. Prior to fracturing operations, six high-sensitivity seismic sensors were positioned around the well to detect and capture micro-seismic wave signals generated by fractures within the coal seam. These signals were transformed and used to determine the fracture source’s position, with the fracture patterns, directions, and sizes characterized by analyzing the spatial arrangement of seismic source locations.

Fractured coal reservoirs can be classified into three ideal models: a collection of sheets (Model I, Figure 4a), a bundle of matchsticks (Model II, Figure 4b), and a collection of cubes (Model III, Figure 4c) [57]. Model I is particularly suitable for depicting high-rank coals, such as anthracite [58]. The fracture permeability of Model I can be calculated using the equation proposed by Hou [59]:

$$k_f=8.50\times {10}^{-4}{w}^2{\phi }_f$$

(10)

where $k_f$ represents fracture permeability; $w$ represents fracture width; ${\phi }_f$ represents fracture porosity.

Using logging data, permeability inversion of the coal reservoir in the Shizhuang south block was conducted. The fracture width calculation utilized the improved formula introduced by Li et al. [60]:

$${\displaystyle \frac{1}{R_{LLS}}}-{\displaystyle \frac{1}{R_{LLD}}}={\left({\displaystyle \frac{w}{\pi }}\right)}^m\left[{\displaystyle \frac{1}{R_{mf}{\left(d_1+r_w\right)}^m}}-{\displaystyle \frac{1}{R_w{\left(d_2+r_w\right)}^m}}\right]$$

(11)

where $R_{LLS}$ and $R_{LLD}$ represent shallow and deep lateral resistivity, respectively; $m$ represents the cementation index; $R_{mf}$ and $R_w$ represent the resistivity of mud and formation water, respectively; $d_1$ and $d_2$ represent the investigation radius of shallow and deep lateral logs, respectively; $r_w$ represents the radius of the wellbore.

The fracture porosity is calculated using Archie’s law and the method proposed by Chatterjee and Pal, with a cementation index of 1.6 and R_mf set at 0.65 Ω·m [61]:

$${\phi }_f={\left({\displaystyle \frac{R_{mf}}{R_{LLS}}}\right)}^{{\displaystyle \frac{1}{m}}}={\left({\displaystyle \frac{0.65}{R_{LLS}}}\right)}^{{\displaystyle \frac{1}{1.6}}}$$

(12)

The overall bulk density of coal is determined by the coal skeleton density and the presence of fluids such as water and hydrocarbons. The impact of fluids on the total density is directly linked to coal porosity. Thus, the density (DEN) log response can measure coal porosity. The effective porosity can be determined using the formula provided by Asquith et al. [62]:

$${\phi }_D={\displaystyle \frac{{\rho }_{ma}-{\rho }_b}{{\rho }_{ma}-{\rho }_{fl}}}$$

(13)

where ${\phi }_D$ represents the density-derived porosity; ${\rho }_{ma}$ represents the matrix density; ${\rho }_b$ represents the formation bulk density; ${\rho }_{fl}$ represents the fluid density.

Various physical properties display distinct characteristics in logging responses. For instance, low DEN, high caliper (CAL), and high acoustic time difference (AC) typically indicate fracture development, while high gamma (GR) usually indicates high clay content [63,64,65]. Generally, GR and DEN measurements decline as coal deforms, whereas LLD increases [66,67]. The correlation between logging curves and coal texture is utilized to establish a discriminant equation based on the Fisher discrimination criterion of IBM SPSS Statistics version 26.0 software:

$$F_{undeformed}=205.502\times DEN-0.069\times GR+0.002\times LLD-155.346$$

(14)

$$F_{cataclastic}=195.953\times DEN-0.119\times GR+0.003\times LLD-143.129$$

(15)

$$F_{granulated}=182.551\times DEN-0.103\times GR+0.003\times LLD-120.767$$

(16)

$$F_{cataclastic}=266.255\times DEN-0.037\times GR+0.002\times LLD-265.722$$

(17)

Geological, property, and geomechanical models of the coal reservoir in the Shizhuang south block were developed using Schlumberger’s Petrel software (version 2021). Detailed steps for software modeling and parameter settings are referenced [68].

4. Results

4.1. Stress Magnitudes

The No. 3 coal seam in the Shizhuang south block ranges from 491 m to 1175 m in depth. The σ_v (or p_f) ranges from 10.02 to 31.72 MPa, with a gradient of 2.00 to 3.16 MPa/100 m. The σ_h (or p_s) ranges from 5.29 to 18.47 MPa, exhibiting a gradient of 0.89 to 3.14 MPa/100 m. The σ_H ranges from 8.43 to 30.81 MPa, with a gradient of 1.46 to 5.14 MPa/100 m. These stress parameters ($p_o$, σ_H, and σ_h) increase linearly with depth. Notably, significant stress gradient values are observed around 550 m depth, where the σ_h gradient surpasses the vertical stress gradient, indicating substantial tectonic stress in the horizontal direction.

The stress regimes, influenced by both the magnitudes and gradients of change, lead to varying stress distributions across different depths. In the Shizhuang south block, the predominant stress regime is characterized by a strike-slip fault, accounting for 66.4% of the total and spanning depths from 491 m to 1175 m. The normal fault stress regime represents 26.1% and is primarily observed at depths greater than 800 m. The reverse fault stress regime, comprising 7.5%, is predominantly observed at depths shallower than 600 m. Shallow depths (<600 m) exhibit a lack of a normal fault stress regime, suggesting high structural stress. A small amount of data (14%) indicates a normal fault stress regime at depths between 600 m and 800 m, dominated by a strike-slip fault stress regime (78%). Beyond 800 m, the magnitudes of horizontal stress diminish, with a minority of data suggesting a reverse fault stress regime and the majority (52%) indicating a normal fault stress regime. The lateral pressure coefficient (k), defined as the ratio of the average of σ_H and σ_h to σ_v, ranges from 0.48 to 1.63, with 40% of the values exceeding 1 (Figure 5e). As depth increases, changes in σ_H/σ_v, σ_h/σ_v, and k typically correspond to shifts in stress regimes, with an overall decreasing trend.

Horizontal stress differentials are crucial for hydraulic fracturing of unconventional reservoirs and are influenced by stress regime variations [69]. Horizontal stress differences in coals, ranging from 5.8 to 13.0 MPa, generally increase with depth (Figure 6a). However, these differences vary significantly across stress regimes. The reverse fault stress regime demonstrates the greatest horizontal stress disparities (7.26 to 13.03 MPa) at the same depth, followed by the strike-slip fault stress regime (6.00 to 12.68 MPa). The normal fault stress regime displays the lowest values (5.83 to 10.32 MPa), indicating the strength of tectonic stress.

In the Shizhuang south block, reservoir pressure ranges from 1.92 to 5.62 MPa, averaging 3.51 MPa. The pressure gradient of the coal reservoirs is 0.34 to 0.57 MPa/100 m, classifying it as an under-pressure reservoir (<0.9 MPa/100 m). Based on fault stress regimes, the Shizhuang south block is divided into five in situ stress zones, all dominated by the strike-slip fault stress type (Figure 7). The fault stress regimes of the CBM wells in each zone show that zones I (Figure 8a) and IV (Figure 8d) have the distribution characteristics of strike-slip fault stress type > normal fault stress type > reverse fault stress type. Zone II (Figure 8b) shows strike-slip fault stress type ≈ normal fault stress type > reverse fault stress type. Zones III (Figure 8c) and V (Figure 8e) are characterized by strike-slip fault stress type > reverse fault stress type > normal fault stress type.

4.2. Geological Parameters

4.2.1. Coal Permeability and Porosity

Figure 9 illustrates the in situ permeability of coal in the Shizhuang south block, which varies between 0.003 and 1.08 mD, with an average of 0.40 mD. Approximately 11.2% of the values are less than 0.1 mD, with a lower limit of about 0.01 mD. Typically, coal in situ permeability decreases with increasing depth. Within the depth range of the coal seams in the Shizhuang south block, permeability varies widely from 0.01 mD to 1 mD (Figure 9c). At depths less than 700 m, permeability rapidly decreases with increasing horizontal stress. Between 800 m and 1200 m, coal seam permeability remains low due to the stress mechanism of highly stressed strike-slip faults. Beyond 1000 m, permeability becomes highly variable with no discernible trend, likely due to the stress-release mechanism of normal faults. The porosity ranges from 2% to 12% (Figure 9b,d), with an average of 7.3%. At burial depths less than 800 m, porosity values exhibit a wider distribution, indicating strong heterogeneity in the coal rock. Beyond 800 m, porosity values become more concentrated, generally falling below 8%, likely due to compaction from increased σ_v. Overall, porosity decreases with increasing burial depth.

4.2.2. Coal Texture

Regionally, coal texture is influenced by both stress and tectonics. In the northwestern part of the Shizhuang south block, where burial depth is large and tectonic activity is significant, granulated coal is highly developed, especially near faults (Figure 10b). The central part of the block, with shallow burial depth and weak tectonic structure, shows a smaller proportion of granulated coal development. Undeformed coal is developed throughout the block and remains relatively stable (Figure 10a). Vertically, as burial depth and tectonic development increase, coal texture transitions from undeformed, cataclastic coal to cataclastic, granulated coal, resulting from increased stress and tectonic deformation (Figure 10c,d).

5. Discussion

5.1. Effects of In situ Stress and Coal Texture on Porosity and Permeability of Coal Reservoirs

Permeability and porosity in coal reservoirs are significantly influenced by in situ stress, with coal texture also playing a critical role [70,71,72,73]. Higher stress typically leads to compaction of the coal seam and closure of macroscopic pores and fractures, resulting in reduced porosity and permeability. At the same depth, compressive stresses under reverse and strike-slip faults lead to fault closure, which reduces pore spaces and fractures in coal reservoirs, decreasing coal seam permeability. Conversely, normal faults, formed under gravity and horizontal tension, are more conducive to the formation of highly permeable coal reservoirs.

Tectonic deformation macroscopically leads to structural fragmentation of coal texture and microscopically affects the macromolecular structure of coal, leading to the development of micropores and microfractures, which in turn affects porosity and permeability [74]. Coal seams located at tectonic high points experience tensile stresses, resulting in a fragile coal texture, whereas those at tectonic low points are influenced by extrusion stresses, resulting in a compact coal texture and reduced porosity and permeability. The coal reservoir in the Shizhuang south block is governed by various factors, as indicated by the limited correlation observed among permeability, porosity, and in situ stress (Figure 11).

The structural topographic map of coal seam No. 3 in the Shizhuang south block (Figure 12) shows the region on a slope dipping toward the northwest, with higher elevations in the southeast and lower elevations in the northwest. In the northwestern part of the block, near-north–south- and near-east–west-trending normal faults are well developed.

Figure 13 presents a cross-sectional view of seven testing wells in the Shizhuang south block, demonstrating variations in stress levels and permeability across various tectonic settings. These wells, less than 800 m deep, belong to shallow coal seams. Although some wells are located at tectonic high points (e.g., TS-1 and TS-5), the degree of tectonic deformation in the southeastern part is much smaller than in the northwestern part, resulting in slight or no deformation of the coal reservoirs. Thus, natural fractures are poorly developed, and the coal texture remains undeformed, leading to low in situ permeability. Conversely, wells TS-2 and TS-4, affected by nearby faults, exhibit cataclastic and granulated coal textures, with a well-developed natural fracture network, resulting in high in situ permeability.

This research examines the impact of tectonics on in situ stress by characterizing vertical in situ stress within the stratigraphy of the study area. The variation in in situ stress with burial depth in the study block can be categorized into three groups: stable increasing, stable–rapid–stable increasing, and stable–rapid increasing. As burial depth increases from shallow to deep, stress variations occur across different tectonic units. In the tectonic slope zone with shallow burial depth, in situ stress increases steadily with minimal fluctuations (Figure 14). At the microtectonic high point with shallow burial depth, stress increases insignificantly due to limited tectonic deformation (Figure 15). At greater burial depths and in areas of intense tectonic deformation, in situ stresses exhibit rapid increases and significant fluctuations (Figure 16).

5.2. The Effect of In situ Stress on Hydraulic Fracturing of CBM

The Qinshui Basin exhibits lower coal permeability than other coal-bearing basins, necessitating hydraulic fracturing to enhance reservoir flow capacity [75]. Understanding present-day stress magnitudes and regimes is crucial for effective hydraulic fracturing. Data from 95 CBM production wells revealed consistent construction parameters—sand-adding volume, fracturing fluid volume, sand concentration, and displacement rates—across different depth intervals (Figure 17). These findings indicate a standardized fracturing scheme, neglecting variations in depth and in situ stresses. This oversight in depth-related stress variations appears to be a significant technical factor contributing to the decline in gas productivity with increasing depth. Additionally, well fracture pressure and shut-in pressure are influenced by the in situ stress regime during fracturing, aligning with the trend of horizontal stress changes with depth (Figure 17d,e).

Micro-seismic monitoring data from eight wells were analyzed to evaluate the orientation and geometry of hydraulic fractures. Predominantly, fractures are oriented northeast to southwest, with some variations northwest to southeast and east to west, as shown in

Table 1. Statistical table of micro-seismic event parameters.

Well Name	Fracture Length (m)	Fracture Width (m)	Fracture Height (m)	Azimuth	Depth (m)
TS-8	290	160	56	N51° E	672.38
TS-9	310	180	42	N70° E	774.76
TS-10	250	180	50	N55° W	758.81
TS-11	300	110	66	N55° W	737.14
TS-12	400	65	35	N57° E	764.92
TS-13	280	240	42	N48° E	691.73
TS-14	155	125	46	N40° E	978.23
TS-15	180	140	32	N42° E	982.38

and Figure 18. This orientation, consistent with the maximum principal stress trace in China, suggests that the current maximum horizontal stress orientation is primarily northeast–southwest, resulting from the combined action of the Pacific and Philippine plate subduction under the Eurasian plate. The effect of horizontal stress variations on hydraulic fracture morphology in fracture-developed reservoirs has been elucidated [76]. A high stress magnitude discrepancy generally leads to simple hydraulic fractures, while minimal discrepancy facilitates hydraulic fracture networks [77,78]. In coal cleats, parallel alignment of face cleats with the σ_H orientation results in longer hydraulic fractures under high stress difference conditions [79]. Fracture lengths in the study area decrease with increasing burial depth, as measured by micro-seismic monitoring wells. This indicates that increased vertical stress limits fracture expansion, making the same fracturing scheme unsuitable for areas with significant burial depth variation.

Hydraulic fracture morphology is contingent upon prevailing stress conditions and pre-existing fractures, influenced by structural trends and coal texture [80,81,82]. Coal texture distribution is strongly associated with structural characteristics. An analysis of a cross-section featuring four wells with coal core images obtained from drilling reveals that cataclastic and granulated coal are predominantly found near fault planes (e.g., TS-2 and TS-4), whereas undeformed coal is observed within folds (e.g., TS-1 and TS-5) [83] (Figure 13). In hydraulic fracturing, there is notable dispersion in micro-seismic events, with no discernible correlation between these events’ distribution and the dominant fracture orientation or maximum horizontal stress. Fracture geometry in cataclastic coals supports this observation. Hydraulic fractures in these circumstances are influenced by a combination of stress and existing fractures, resulting in fractures forming at various angles and orientations (Figure 19).

In wells like TS-13, located near fault planes, micro-seismic data sets exhibit a discontinuous and extensively distributed pattern. The primary fracture exhibits significant angles with its branches, along with parallel fractures. In contrast, in structurally low areas, predominant fracture and branch propagation occur along the maximum horizontal orientation due to elevated differential stresses, leading to a nearly straight arrangement of micro-seismic data, as observed in examples like TS-8 and TS-14. It is crucial to consider various fracturing schemes based on factors, such as burial depth, stress regimes, coal textures, and structural trends, rather than relying on standardized construction parameters. Deeper coal seams exhibit a higher propensity for intricate fractures, posing greater difficulties in sand filling. Mitigating complex fracture geometries in these regions requires higher pumping rates and treatment pressures compared to structural lows.

According to the CBM exploration and development theories during China’s “13th Five-Year Plan” and “14th Five-Year Plan,” the fracturing process for CBM has shifted from conventional fracturing to ultra-large-scale extreme volume fracturing. This transition has seen the operational scale evolve from medium–small displacement rates (7 to 12 m³/min), medium–small fluid volumes (<10,000 m³/well), and medium–small proppant volumes (30 to 70 m³/stage) to large displacement rates (14 to 18 m³/min), large fluid volumes (>20,000 m³/well), and large proppant volumes (300 to 450 m³/stage). The daily gas production from vertical and directional wells increased from 300–2000 m³/d to 3000–20000 m³/d, while the production from horizontal wells increased from 3000–10,000 m³/d to 30,000–100,000 m³/d [84]. In the Ordos Basin, CNPC has experienced a progression in deep CBM development from conventional fracturing (30 to 70 m³/stage of proppant, 7 to 12 m³/min displacement) to large-scale fracturing (170 to 300 m³/stage of proppant, 8 to 14 m³/min displacement), and finally to ultra-large-scale extreme volume fracturing (300 to 450 m³/stage of proppant, 14 to 18 m³/min displacement), with operational pressure increasing from 30 MPa to 60 MPa [85]. The average initial daily gas production per well in the Ordos Basin is 11 × 10⁴ m³. For example, in the Daning–Jixian Block of deep coalbed methane, the average proppant scale in large-scale volume fracturing of vertical cluster wells is six times that of conventional fracturing wells. The average gas production and estimated ultimate recovery are 2.7 times and twice that of conventional fracturing wells, respectively. The Jishen 6–7 Ping 01 horizontal well, which underwent large-scale extreme volume fracturing with a single-stage fluid volume of 3000 m³, a proppant volume of 350 m³, and a displacement rate of 18 m³/min, achieved an average daily gas production of 5.82 × 10⁴ m³, with a peak daily production of 10.1 × 10⁴ m³. In the Zhengzhuang North-Qinnan West Block, where coal seam depths range from 650 to 1500 m and are similar to those in the study area, the fracturing fluid volume in vertical wells was increased from 500–800 m³ to 1300–2000 m³, the displacement rate was increased from 4–6 m³/min to 10–14 m³/min, and the proppant concentration was increased from 8% to 12–15%, resulting in an average single-well production increase of 1190 m³/d. In horizontal wells, large-scale, high-displacement fracturing technology was employed, increasing the single-stage fluid volume from 450–600 m³ to 2000 m³, the single-stage proppant volume from 30–50 m³ to 150 m³, and the displacement rate from 6 m³/min to 15 m³/min, leading to an average daily gas production increase from 8000 m³/d to 18,000 m³/d [86].

5.3. Statistics of Geo-Engineering Parameters in Different Stress Zones and Development Recommendations

Figure 20 highlights the influence of hydraulic fracturing and coal reservoir pore permeability on production capacity. In the Shizhuang south block, the No. 3 coal seam contains 731 vertical CBM production wells and 490 directional CBM production wells, collectively producing an average daily gas production rate of 299 m³/d per well. In contrast, single-branch horizontal wells exhibit a higher average production rate of 1892 m³/d. Horizontal wells are preferred for CBM production due to their ability to significantly alter coal reservoirs, establish intricate fracture networks, stimulate seeps, and ultimately enhance overall coal reservoir permeability.

High-producing wells are primarily found at depths below 800 m. These wells are situated in coal reservoirs with excellent porosity and permeability. In contrast, CBM wells at greater depths show minimal to no methane production, reflecting deteriorating geological conditions. Statistical results indicate that CBM wells in in situ stress zones III and IV have higher average daily gas production (Figure 21) and wells exceeding 1000 m³/d account for 13.2% and 19.4%, respectively. These wells are characterized by shorter gas breakthrough times, relatively higher gas breakthrough pressures, lower daily water production, and higher ratio of critical desorption pressure to initial reservoir pressure. The proportion of coalbed methane wells with gas breakthrough times less than 60 days in in situ stress zones III and IV reaches 33.5% and 31.3%, respectively.

The percentage of daily water production of CBM wells in in situ stress zones III and IV below 3 m³/d stand at 82.2% and 83.4%, while the percentage of gas breakthrough pressures ranging from 1 to 3 MPa are 69.3% and 56.0%. Additionally, the percentage of critical desorption pressure to initial reservoir pressure exceeding 0.6 are 22.1% and 19.0%. A high ratio of critical desorption pressure to initial reservoir pressure accelerates coalbed methane desorption by requiring a smaller reduction in coal reservoir pressure to reach critical desorption pressure. Low water production during drainage and pressure reduction indicates efficient pressure transfer in coal reservoirs, benefiting CBM production. Reduced water content in the coal reservoir enhances stability during the gas production phase.

In terms of geological parameters, in situ stress zones III and IV exhibit higher porosity, permeability, and gas content, with coal textures dominated by undeformed and cataclastic coals (Figure 22). High permeability indicates strong gas transmission capability, while high gas content suggests significant resource potential. The primary and fractured coal structures indicate that the coal reservoirs can be effectively fractured to increase permeability at later stages.

For zones I and II, characterized by high in situ stress and relatively broken coal texture, selecting fracturing fluids with low friction resistance is crucial to improving sand-carrying capacity. Viscoelastic surfactant clean fracturing fluid can prevent reservoir damage during hydraulic fracturing. Alternatively, variable-viscosity slickwater, combining the high bearing capacity of high-viscosity slickwater with the drag-reduction performance of traditional slickwater, can form an extensive proppant fracturing network and enhance production.

Regarding proppant selection, coal, as a low-permeability reservoir, typically has natural microfractures and the potential for additional microfractures during fracturing. Traditional proppants often fail to keep these small fractures open. Injecting nanosized proppant into the reservoir can fill microfractures along the main fracture before injecting conventional fracturing proppant, effectively supporting the microfractures. For zones III and IV, low-density proppants with decreased density or hollow structures can be used to enhance fracture creation. Zone V, with lower gas content, is less economical to develop but can be considered a potential future development area.

6. Conclusions

In the southern section of the Shizhuang area within the Qinshui Basin, in situ stresses within coal deposits increase in magnitude with depth, while the gradient and lateral pressure coefficients decrease. Due to the large depth range of the coal seams, complex stress regimes exist. In the Shizhuang south block, the strike-slip fault stress regime is predominant, with normal fault stress regimes mainly distributed at depths greater than 800 m and reverse fault stress regimes at depths less than 600 m. Horizontal stress differences vary by stress regime, being largest for reverse fault stress, followed by strike-slip fault stress, and smallest for normal fault stress. The horizontal stress difference is positively correlated with burial depth. Coal permeability ranges from 0.003 to 1.08 mD, averaging 0.4 mD, while porosity ranges from 2% to 12%, averaging 7.3%. Both porosity and permeability generally decrease with increasing stress but are enhanced by coal texture and tectonics (faulting).

Micro-seismic occurrences associated with hydraulic fracturing indicate that the primary orientation of σ_H in the Shizhuang south block is northeast–southwest, with some localized variations in the northwest–southeast and east–west directions. The formation of fractures through hydraulic fracturing is influenced by tectonic strike, coal quality, and pre-existing fractures. Conventional small-scale fracturing techniques are less effective in deep-seated CBM development or tectonic low points, as proppant-supported profiles are inadequate. Fracture length, width, and height measured by micro-seismic monitoring wells decrease with increasing burial depth, indicating that the same fracturing scheme is not applicable across areas with significant depth variation. Enhancing proppant dosage and pumping rate has proven successful in CBM development. The study area is divided into five stress zones, with geo-engineering parameters for each zone documented and recommendations for fracturing fluids and proppants provided.