The Gas Production Characteristics of No. 3 Coal Seam Coalbed Methane Well in the Zhengbei Block and the Optimization of Favorable Development Areas

Abstract

The characteristics and influencing factors of gas production in CBM wells are analyzed based on the field geological data and the productivity data of coalbed methane (CBM) wells in the Zhengbei block, and then the favorable areas are divided. The results show that the average gas production of No. 3 coal seam CBM wells in the study area is in the range of 0~1793 m³/d, with an average of 250.97 m³/d; 80% of the wells are less than 500 m³/d, and there are fewer wells above 1000 m³/d. The average gas production is positively correlated with gas content, critical desorption pressure, permeability, Young’s modulus, and Schlumberger ratio, and negatively correlated with fracture index, fault fractal dimension, Poisson’s ratio, and horizontal stress difference coefficient. The relationship between coal seam thickness and the minimum horizontal principal stress is not strong. The low-yield wells have the characteristics of multiple pump-stopping disturbances, unstable casing pressure control, overly rapid pressure reduction in the single-phase flow stage, sand and pulverized coal production, and high-yield water in the later stage during the drainage process. It may be caused by the small difference in compressive strength between the roof and floor and the coal seam, and the small difference in the Young’s modulus of the floor. The difference between the two high-yield wells is large, and the fracturing cracks are easily controlled in the coal seam and extend along the level. The production control factors from strong to weak are as follows: critical desorption pressure, permeability, Schlumberger ratio, fault fractal dimension, Young’s modulus, horizontal stress difference coefficient, minimum horizontal principal stress, gas content, Poisson’s ratio, fracture index, coal seam thickness. The type I development unit (development of favorable areas) of the Zhengbei block is interspersed with the north and south of the block on the plane, and the III development unit is mainly located in the east of the block and near the Z-56 well. The comprehensive index has a significant positive correlation with the gas production, and the prediction results are accurate.

1. Introduction

Coalbed methane (CBM), celebrated for its clean and efficient energy profile, has captured the attention of the global community. The significance of CBM in the energy sector is underscored by recent studies, which highlight its potential as a sustainable alternative to conventional fossil fuels [1,2]. The development of CBM resources in China holds profound strategic importance, as it not only diversifies the nation’s energy portfolio but also aligns with the global shift towards sustainable energy solutions [3]. China, with its numerous CBM-rich basins, is leading the way in leveraging this resource to fulfill its burgeoning energy requirements and to advance environmental sustainability. Most of the commercial development of CBM is in the southern part of the Qinshui Basin and some areas in the eastern part of the Ordos Basin [4]. The development area is limited and the number of gas-producing coal seams is small. The commercial development area of CBM in the south of Qinshui Basin is less than one-fifth of the whole basin. The Zhengbei block in the south of Qinshui Basin, as an important coal production base in China, is one of the earliest commercially developed blocks of high-rank coal-bed methane in China. The geological profile is characterized by a high gas content, robust sealing properties, intricate fault structures, significant variations in burial depth, low permeability, and pronounced heterogeneity. At present, the focus of commercial development is on the No. 3 coal seam of Shanxi Formation, and the early development is mainly of vertical wells and directional wells [5]. The mature technology of the Fanzhuang block, with relatively simple structure and geological conditions and high permeability, was copied in the early stage. The vertical well spacing and conventional fracturing were adopted. The overall developmental efficacy of open-hole multi-branch horizontal wells was suboptimal, with inefficient wells emerging consecutively. The average daily gas production from vertical wells was suboptimal, with the production rate of the combined production and construction scheme falling below 30% [6,7].

Given the aforementioned issue, prior research on the Zhengbei block has predominantly concentrated on the attributes of the coal reservoir and the enrichment patterns of CBM [8,9], CBM well drilling technology research [10,11], CBM well gas production difference and favorable area prediction [5,12], fracturing and reformable line evaluation [13,14], lack of systematic and in-depth research on gas production and its influencing factors, and lack of understanding of favorable areas for geological development and main controlling factors of production control, which seriously restricts the development of CBM resources in the Zhengbei block.

The gas production of CBM wells is closely related to the enrichment degree of CBM, reservoir permeability, reservoir modifiability, and other factors. This paper seeks to identify the factors and mechanisms influencing gas production by examining the geological conditions of CBM development in the No. 3 coal seam of the Zhengbei block. The entropy method is used to clarify the relationship between each influencing factor and gas production, and the distribution of favorable development areas is clarified, which provides theoretical support and practical guidance for the efficient development of CBM.

2. Geological Background

The Zhengzhuang block is located in the structural slope zone in the southern part of the Qinshui Basin. The southeast and Fanzhuang blocks are bounded by the Sitou fault, and there is no obvious boundary between the north and the west (Figure 1a). The overall structural form is a nearly NW–NNW-trending horseshoe-shaped inclined monoclinic structure. NE-trending normal faults are mainly developed in the block, with a small amount of NNE- or NEE-trending normal faults. The larger faults include the Zheng 1 fault, Zheng 2 fault, Houchengyao fault, and Sitou fault [15] (Figure 1b). All the data in the paper are from CBM Branch Company, Huabei Oilfield of PetroChina, Changzhi, China. The contour map is drawn by DFDraw4.0 (Beijing, China), the scatter plot is drawn by Origin2018 (Northampton, MA, USA), and the structural geological map and histogram are drawn by Coreldraw 2018 (Ottawa, ON, Canada).

The northern strata of the Zhengzhuang block are stable and gentle. From oldest to newest, they include the Fengfeng Formation, Benxi Formation, Taiyuan Formation, Shanxi Formation, Lower Shihezi Formation, Upper Shihezi Formation, Triassic, and Quaternary [14] (Figure 1c). The No. 3 target coal seam is located in the middle and lower section of Shanxi, which is stable in distribution and belongs to the delta plain swamp facies deposit. The buried depth of the coal seam is 601.3~1336.9 m, the thickness is 3.2~7.2 m, and the average thickness is 5.8 m. The maximum vitrinite reflectance is 3.29~3.98%, which belongs to anthracite. The well test permeability is between 0.011 mD and 0.75 mD, with an average of 0.164 mD. The macroscopic coal rock types are mainly semi-bright coal and bright coal. The micropores and small pores in the coal seam are more developed, and the CBM reservoir capacity is strong; the roof is mainly mudstone, the floor is mudstone or sandstone, and the sealing condition is good. The gas content of the coal seam is 11.09~29.68 m³/t, the average gas content is 21.12 m³/t, and the gas content is good.

3. CBM Well Productivity Characteristics

It is found that the average gas production of CBM wells is low, 80% of the wells are less than 500 m³/d, and there are few wells more than 1000 m³/d according to the drainage data of 75 CBM wells in the Zhengbei block. The water production is mostly concentrated at about 4 m³/d, and the local level is higher than 20 m³/d. The drainage time of CBM wells in the block is longer, and 64% of the wells have a drainage time of more than 10 years (Figure 2). The average gas production and cumulative gas production of coal seam drainage wells in the study area are mainly analyzed. The average gas production is between 0 and 1793 m³/d, with an average of 250.97 m³/d; the cumulative gas production ranges from 0 to 3,072,182 m³, with an average of 254,264.67 m³. The highest points of average gas production and cumulative gas production are mainly concentrated in the northern, central, and southeastern parts of the block, and the rest are low (Figure 3).

4. Control Factors of CBM Well Productivity

4.1. Gas-Bearing Enrichment Factors

The enrichment degree of CBM is mainly controlled by four aspects, CBM content, coal seam thickness, fault fractal dimension, and critical desorption pressure. The thickness of the coal seam and its gas content form the foundation of CBM resources. The degree of resource enrichment is embodied in CBM saturation [16]. Furthermore, the fault fractal dimension serves as an indicator of structural strength and is associated with the dissipation of CBM. The fault zone is usually accompanied by the formation of cracks, which will change the permeability of the formation and affect the reservoir capacity of CBM [17]. The critical desorption pressure is usually used to describe the release capacity of CBM [16].

4.1.1. Gas Content

The gas content of No. 3 coal seam is in the range of 11.09~29.68 m³/t, with an average of 21.12 m³/t. The enrichment area is located in the west and south of the block and near the Z-95 well. The gas content is the lowest in the east, and the lowest point is near the Z-14 well (Figure 4a). The relationship between gas content and average gas production was analyzed. The study revealed that as the gas content increased, so did the gas production, and the correlation between these two variables was strong (Figure 4b).

4.1.2. Coal Seam Thickness

The No. 3 coal seam is prevalent throughout the entire area, with a thickness ranging from 3.2 to 7.2 m. The average thickness of the coal seam is approximately 5.80 m, although in certain localized areas, it can exceed 6.5 m. The high-value area of more than 6 m is mainly located in the northwest of the block and near the Z-78 well. The thin coal seam is mainly distributed near the Z-90 well, and the distribution of the remaining areas is relatively uniform. The relationship between coal seam thickness and average gas production is relatively discrete, which may be related to the difference of CBM well drainage and reservoir physical properties [18] (Figure 5).

4.1.3. Critical Desorption Pressure

The CBM wells facilitate the production of coal seam water and reduce coal seam pressure by generating surface suction and expanding the production pressure difference. This process aims to maintain coal seam pressure below the critical desorption pressure, thereby ensuring continuous and stable gas production in the coal seam. Through the analysis of gas content, Langmuir volume, Langmuir pressure, and reservoir pressure, the critical desorption pressure of different well positions was further calculated (Equation (1)). Some well positions did not undergo isothermal adsorption experiments. Therefore, combined with the drainage data of CBM wells, the formation pressure at the time of gas breakthrough or a certain time before gas breakthrough (usually one day) was selected as the critical desorption pressure [19]. The average gas production in the study area is positively correlated with the critical desorption pressure (Figure 6). The critical desorption pressure of low-yield wells (<200 m³/d) is mostly lower than 4 MPa, and high-yield wells are accompanied by higher critical desorption pressure. Researchers have demonstrated that, given the same pressure, an increase in Langmuir volume corresponds to a higher degree of gas desorption and subsequently greater gas production [20]. The critical desorption pressure represents the driving energy of the coal reservoir after the gas production begins, affecting the time of CBM production.

$$P_{cd}={\displaystyle \frac{V_s{P}_L}{V_L-V_s}}$$

(1)

P_cd is the critical desorption pressure (MPa), vs. is the measured gas content (m³/t), P_L is the Langmuir pressure (MPa), and V_L is the Langmuir volume (m³/t).

4.1.4. Fault Fractal Dimension

The fault structure serves as a crucial conduit for both CBM and water within the study area. To accurately and quantitatively represent the inherent complexity of this fault structure (Equation (2)), we employ similar dimension parameters for evaluation. The fractal dimension of the fault is determined using the grid covering method, as proposed by Wang in 2023 [21]. In the case of a research subject exhibiting self-similarity, if it can be segmented into N units, each of which maintains similarity to the whole at a ratio r, then the similarity dimension is defined accordingly,

$$D_{\mathrm{s}}=-{\displaystyle \frac{\lg N\left(\mathrm{r}\right)}{\lg \left(\mathrm{r}\right)}}$$

(2)

D_s is the similarity dimension, N(r) is the number of grids containing fault traces, and r is the similarity ratio.

The fractal dimension of faults in the study area is 0~2.493, with an average of 0.89. The faults are concentrated in the middle of the block, and the high-value area is in the west of the block. When integrated with the actual fault distribution, the results demonstrate consistency and reliability (Figure 7a). The relationship between the fractal dimension of faults and the average gas production shows that there is a negative correlation between them (Figure 7b). Tectonic action easily causes the fracture deformation of the formation, resulting in the development of faults and the destruction of the preservation conditions of CBM. At the same time, the local area is affected by the fracture structure’s communication with the aquifer, the water abundance is enhanced, and the difficulty of coal seam pressure reduction is also increased accordingly.

4.2. Permeability Factors

The permeability of the coal seam is the main influencing factor of CBM production. Permeability refers to the conductivity of a coal seam. The distribution of fractures within the coal seam is influenced by in situ stress, with the fracture index serving as an indicator of fracture enrichment. The permeability of the coal seam determines the strength of CBM transportation capacity [22,23].

4.2.1. Permeability

The permeability data in the study area are mainly from the injection pressure drop test. The permeability of the No. 3 coal seam is in the range of 0.011~0.75 mD, with an average of 0.164 mD. The plane distribution characteristics of permeability are shown in Figure 8a. The overall permeability shows that the southern and central parts of the block have higher values, and the northern part of the block is a low-permeability area, at less than 0.1 mD, which may be closely related to the monoclinic structure with high north and low south in the block. The well test permeability in the area is positively correlated with the gas production of CBM wells (Figure 8b).

4.2.2. Fracture Index

Previous studies have shown that rock mechanics parameters such as Young’s modulus can reflect the degree of fracture development of rock. The fracture index formula proposed by predecessors [24] is used to characterize the development of coal reservoir fractures from the perspective of the coal seam itself (Equation (3)). The larger the fracture index is, the more developed the fracture is, and the higher the degree of coal fragmentation. The fracture index of the No. 3 coal seam in the study area is between 0.28 and 0.35, with an average of 0.3. The high-value area is mainly located in the middle of the block on the plane, and the rest is low-value (Figure 9a). Overall, the fracture index is negatively correlated with the average gas production(Figure 9b). The reason for the result may be that the excessive development of fractures will lead to the premature dissipation of coalbed methane, and the increase of fractures will increase the risk of formation water invading the coal seam, especially in the case of the underlying or overlying aquifer connected to the coal seam.

$$Y={\displaystyle \frac{E_{\mathrm{ma}}-E}{E_{\mathrm{ma}}}}$$

(3)

Y is the fracture index, E_ma is the dynamic Young’s modulus of coal rock skeleton (GPa), and E is the Young’s modulus of the coal seam (GPa).

4.2.3. Minimum Horizontal Principal Stress

The minimum horizontal principal stress is an important basic datum for fracturing design, fracture height control, and post-fracturing effect evaluation of unconventional oil and gas reservoirs. It is closely related to the closure pressure of fractures during fracturing [22,25]. Based on the collected logging data, the Huang’s model [26] is used to calculate Equations (4) and (5),

$$S_H=({\displaystyle \frac{\mu }{1-\mu }}+\beta )(S_V-\alpha P_p)+\alpha P_p$$

(4)

$$S_h=({\displaystyle \frac{\mu }{1-\mu }}+\gamma )(S_V-\alpha P_p)+\alpha P_p$$

(5)

S_H is the maximum horizontal principal stress (MPa), S_h is the minimum horizontal principal stress (MPa), S_v is the vertical column stress (MPa), v is Poisson’s ratio (dimensionless), α is the Biot’s coefficient, P_p is the reservoir pressure (MPa), and β and γ are the structural coefficients in the horizontal direction.

The minimum horizontal principal stress is between 8.48 MPa and 26.66 MPa, with an average of 18.13 MPa. On the plane, it shows a distribution pattern of low in the south and high in the north, among which Z-95 is higher and Z-80 is lower. The distribution of three-dimensional principal stress is similar to that of coal seam burial depth. The correlation between CBM production and minimum horizontal principal stress in the study area is poor, indicating that gas production is greatly affected by other factors (Figure 10).

4.3. Favorable Fracturing Factors

4.3.1. Young’s Modulus and Poisson’s Ratio

The Young’s modulus (E) (Equation (6)) and Poisson’s ratio (μ) (Equation (7)) of coal rock can be obtained according to the elastic wave theory of rock, combined with density logging and array acoustic logging data. The Young’s modulus is in the range of 4825~13,397.5 MPa, with an average of 6921.4 MPa, and the Poisson’s ratio is in the range of 0.221~0.243, with an average of 0.23. The Young’s modulus is positively correlated with the average gas production, and the Poisson’s ratio is negatively correlated with the average gas production. The higher the Young’s modulus and the lower the Poisson’s ratio, the greater the brittleness of the rock, and the easier it is to form complex fractures during the fracturing process [27]. However, the high-value areas of Young’s modulus and Poisson’s ratio in the study area are in the middle of the block, which is different from the traditional understanding (Figure 11). Therefore, the gas production may be less affected by these two factors.

$$\mu ={\displaystyle \frac{1}{2}}\ast {\displaystyle \frac{\Delta t_s^2-2\Delta t_s^2}{\Delta t_s^2-\Delta t_p^2}}$$

(6)

$$E={\displaystyle \frac{\rho }{\Delta t_s^2\ast 9.29\ast {10}^4}}\ast {\displaystyle \frac{3\Delta t_s^2-4\Delta t_s^2}{\Delta t_s^2-\Delta t_p^2}}$$

(7)

μ is the Poisson’s ratio of rock (dimensionless), ρ is rock density (g/cm³), Δt_s is the time difference of longitudinal wave (μs/m), Δt_p is the P-wave time difference of the stratigraphic framework (μs/m), and E is Young’s modulus (Gpa).

4.3.2. Schlumberger Ratio

The Schlumberger ratio is often used to characterize whether sand is produced during conventional reservoir mining. Here, the Schlumberger ratio is applied to coal seams to characterize the amount of pulverized coal produced in coal reservoirs [28]. The smaller the Schlumberger ratio, the more pulverized coal is produced. According to the array acoustic logging data, the mechanical characteristic parameters of the coal reservoir are extracted and the Schlumberger ratio is calculated (Equation (8)). The Schlumberger ratio is in the range of 0.06~0.51, with an average of 0.14. The high-value area of the study area is mainly located in the middle of the block, and the eastern region is the lowest-value (Figure 12). The average gas production is positively correlated with the Schlumberger ratio, and 200 m³/d drainage wells. The overall Schlumberger is relatively small and relatively concentrated.

$$S={\displaystyle \frac{\left(1-2\mu \right)\left(1+\mu \right){\rho }^2}{6\left(1-\mu \right)\Delta t_s}}\ast {(9.94\ast {10}^8)}^2$$

(8)

μ is the Poisson’s ratio of rock (dimensionless), ρ is rock density (g/cm³), and Δt_s is the time difference of longitudinal wave (μs/m).

4.3.3. Horizontal Stress Difference Coefficient

In addition to overcoming the tensile strength of rock, the initiation and extension of fracturing cracks must also overcome the constraints of in situ stress in the stratum. The difference in in situ stress will have a greater impact on the formation of cracks. The smaller the horizontal principal stress difference is, the more favorable it is to form network fractures, and the more easily the reservoir is fractured, the better the rework ability is [29]. The horizontal stress difference coefficient refers to the ratio of the two-phase horizontal principal stress difference to the minimum horizontal principal stress. The horizontal stress difference coefficient of the Zhengbei block is between 0.01 and 1.31, with an average of 0.18. The gas production of coal seam in the study area is negatively correlated with the horizontal stress difference coefficient (Figure 13).

4.4. Control Factors of CBM Well Productivity Engineering

The gas production of vertical wells in the Zhengbei block is generally lower than 1000 m³/d. According to the previous productivity classification of the block, it is divided into three levels. The daily production of high-yield wells is ≥2000 m³/d, the daily production of medium-yield wells is 2000 > stable production ≥ 1000 m³/d, and the daily production of low-yield wells is <1000 m³/d (Figure 14). Overall, there are many low-yield wells. By analyzing the drainage performance of several low-yield wells in the block, it is found that the drainage time of CBM wells in the Zhengbei block is the longest, the peak gas production is low, and the gas production after stable production is low. In the process of drainage, there are many times of pump-stopping disturbance. The casing pressure control is unstable, and the pressure reduction speed in the single-phase flow stage is too fast, which is not conducive to the expansion of pressure drop. It is easy to cause coal seam excitation, sand production, and pulverized coal production. The pressure reduction speed of some wells is stable in the early stage, and it is easy to reach the peak value of gas production quickly. However, in the later stage, there is high water production, and the flow pressure increases after the shutdown, resulting in shutdown or low production.

Further combined with the rock mechanics parameters of the roof and floor and the coal seam, it is found that the difference in the compressive strength ratio between the roof and floor of the low-yield well (Z-86/Z-81/Z-96) and the coal seam is small (Figure 15). At the same time, it is found that the compressive strength ratio of the roof and floor to the coal seam is generally lower than 5 (Figure 16). At present, the research area mainly adopts the small- and medium-scale fracturing of vertical wells and the staged fracturing of horizontal wells [30]. The hydraulic fracturing cracks easily extend to the roof and floor of the coal seam, which may communicate with the aquifer and cause the difficulty of drainage and pressure reduction. Therefore, the reason for the high yield of water in some wells is consistent with the previous understanding [31]. Comparing the Young’s modulus of the floor with the coal seam, it is found that the two are relatively close, the crack is not easy to extend along the coal seam, and the crack extension is shorter. In contrast to the high-yield wells, it is found that the compressive strength and Young’s modulus of the roof and floor of the high-yield well (Z-103) are quite different from those of the coal seam, and the cracks are easily controlled in the coal seam. At the same time, the roof and floor limit the expansion of the cracks, and the cracks are easy to extend along the level. The cracks are in the form of a ‘T’, so the yield is higher.

5. Prediction of Favorable Development Unit of CBM

5.1. Optimization Method of Favorable Area Development

Upon conducting a thorough analysis of various factors and clarifying the concept of development unit division, we employed the entropy weight method to assign weights to the controlled factors associated with gas-rich areas, high-permeability zones, and favorable fracturing regions. Finally, the favorable area optimization index is calculated, and then the favorable development area is divided.

The entropy weight method is a statistical method to judge the degree of dispersion of different indicators of the sample. The larger the entropy value, the smaller the degree of dispersion. At the same time, the entropy weight method can also calculate the weight of each index in the overall index, which is of great significance to the comprehensive evaluation. The specific steps are as follows:

(1)

Sample data normalization

The sample data are normalized so that all the indexes in the sample are under the same dimension, to eliminate the analysis error caused by the large difference between the indexes.

(2)

Normalized data volume translation

In the entropy weight method, when x_mn = 0, the entropy value is meaningless. Based on this, this paper shifts all normalized data to the right by 0.0001 units, where m is the number of samples and n is the number of indicators.

(3)

Entropy weight calculation

After the data preprocessing is completed, the entropy value and the weight of each index in the coalbed methane in the study area can be calculated (Equations (9) and (10)). The entropy calculation formula is:

$$Q_b={\displaystyle \frac{-1}{\ln m}}{\displaystyle \sum _{i=1}^m{f}_{ab}}\ln f_{ab}(a=1,2,\dots ,m;b=1,2,\dots ,n)$$

(9)

$$f_{ab}=r_b(x_a)/{\displaystyle \sum _{i=1}^m{r}_b(x_a)}$$

(10)

Q_b is the information entropy of each index. The weight of each index is calculated according to the entropy value (Equation (11)),

$${\epsilon }_b={\displaystyle \frac{1-Q_b}{n-{\displaystyle \sum Q_b}}}(b=1,2,\dots ,n)$$

(11)

ε_b is the weight of each index.

The control factors affecting the gas production of CBM according to the comparison results of correlation degree in the study area from strong to weak are critical desorption pressure, permeability, Schlumberger ratio, fault fractal dimension, Young’s modulus, horizontal stress difference coefficient, minimum horizontal principal stress, gas content, Poisson’s ratio, fracture index, and coal seam thickness (

Table 1. Weight calculation results.

Item	Information Entropy Value	Information Utility Value	Weight (%)	Item	Information Entropy Value	Information Utility Value	Weight (%)
Permeability	0.932	0.068	15	Critical desorption pressure	0.922	0.078	17.247
Young’s modulus	0.956	0.044	9.754	Fracture index	0.992	0.008	1.854
Schlumberger ratio	0.936	0.064	14.25	Poisson ratio	0.978	0.022	4.866
Coal seam thickness	0.993	0.007	1.542	Diversity factor	0.962	0.038	8.486
Minimum principal stress	0.966	0.034	7.535	Fault fractal dimension	0.94	0.06	13.215
Gas content	0.972	0.028	6.251

). In the development of CBM, factors such as critical desorption pressure, coal seam permeability, Schlumberger ratio, and fault fractal dimension can be given priority to achieve efficient development.

5.2. Development Unit Division

The above calculation method is used to divide the development units in the study area based on the comprehensive analysis of the parameters of the productivity control factors of CBM wells. The results show that the comprehensive evaluation index of the study area is between 0 and 1, with an average of 0.64. The type I development unit in the plane Zhengbei block is stripped and interspersed with the north and south of the block. The III development unit is mainly located in the east of the block and near the Z-56 well (Figure 17). It is found that the evaluation index is positively correlated with the average gas production, indicating that the prediction results are accurate (Figure 18).

6. Conclusions

(1)

The characteristics of CBM production in the Zhengbei block have been identified. The average gas production of CBM wells in the study area is between 0 and 1793 m³/d, with an average of 250.97 m³/d. Of the wells, 80% are lower than 500 m³/d, and there are fewer wells above 1000 m³/d. The highest points of average gas production and cumulative gas production are mainly concentrated in the northern, central, and southeastern parts of the block.

(2)

The average gas production is positively correlated with gas content, critical desorption pressure, permeability, Young’s modulus, and Schlumberger ratio, and negatively correlated with fracture index, fault fractal dimension, Poisson’s ratio, and horizontal stress difference coefficient. The correlation with coal thickness and minimum horizontal principal stress is poor.

(3)

The low-yield wells in the study area have the characteristics of multiple pump-stopping disturbances, unstable casing pressure control, and overly rapid depressurization in the single-phase flow stage. CBM wells have higher sand, pulverized coal, and water production. Compared with the roof and floor rock mechanics experiments, it is found that this may be caused by the small difference in compressive strength between the roof and floor and the small difference in Young’s modulus of the floor. The difference between the two high-yield wells is large, and the fracturing cracks are easy to control in the coal seam and extend along the layer.

(4)

The production control factors from strong to weak are as follows: critical desorption pressure, permeability, Schlumberger ratio, fault fractal dimension, Young’s modulus, horizontal stress difference coefficient, minimum horizontal principal stress, gas content, Poisson’s ratio, fracture index, coal seam thickness. On the plane, the type I development unit of the Zhengbei block is stripped and interspersed with the north and south of the block, and the type III development unit is mainly located in the east of the block and near the well Z-56. The comprehensive index is positively correlated with gas production, and the prediction results are accurate.