The Qinshui Basin is the main production base of high-rank coalbed methane in China. High-rank coal reservoirs in this region exhibit diverse conditions for coal formation and reservoir development, complex geological structures, low permeability, pronounced reservoir heterogeneity, and significant challenges in reservoir stimulation, which led to early issues such as a low effective resource utilization rate, low gas production per well, and low development profits. By analyzing the characteristics of high-rank coal reservoirs and the development patterns of coalbed methane, this study identifies three key constraints to the efficient development of high-rank coalbed methane: (1) poor precision in selecting areas for efficient development; (2) limited adaptability of development technologies; (3) a mismatch between stimulation processes and coal reservoirs. Investigations into microstructures, coal body structures, in-situ stresses, and fractures—combined with an evaluation of various geological factors’ impact on production—enabled a multidimensional division of development units to identify the geological features of each unit. Consequently, a “five-element” evaluation index system for production potential in efficient development areas was established, and an optimization method for selecting efficient development areas for high-rank coalbed methane was formulated. Analysis suggests that due to the low permeability and strong heterogeneity of high-rank coal, horizontal wells can connect more coal seam fractures, thereby expanding the drainage and pressure-relief areas and reducing the flow resistance of gas and water. This possesses advantages such as high per-well gas production and improved economic benefits. For different geological zones and development stages, in accordance with the principle of “maximizing controlled reserves, maximizing gas production rate, and optimizing economic benefits”, an optimized horizontal well layout technology for high-rank coalbed methane was developed. On this basis, with the objective of “initiating a fracture network, creating new fractures, and controlling reserves”, key technologies were devised—primarily including energy-focused directional perforation, stepwise hydraulic fracturing for incremental production enhancement, a combined application of fine-powder sand, and synchronous well-group interference. At the same time, the process technologies of bridge-plug-and-perforation using active water as the main body and well-group synchronous interference operations were refined, leading to the establishment of a linear fracture network system conducive to gas production, achieving efficient hydraulic fracturing. The application of these research outcomes in the Qinshui Basin has enabled the efficient development of high-rank coal, with daily gas production per horizontal well doubling, the ultimate recoverable reserve per well increasing by 50%, and the productivity attainment rate of newly-built blocks surpassing 90%. When extended to other high-rank coalbed methane blocks in China, these advantages provide technical support and a demonstrative model for strengthening the coalbed methane industry.

Based on the analysis of the coal-forming environment of the Carboniferous Taiyuan Formation in Xunyi exploration area, southern Ordos Basin, and combined with paleogeomorphological analysis and sedimentary facies research, the coal accumulation characteristics of Taiyuan Formation were identified. By using experimental analysis methods such as industrial analysis, scanning electron microscopy, and isothermal adsorption, along with well-logging modeling evaluation, the characteristics of coal petrology and coal quality, reservoir physical properties, and gas content were investigated. The key controlling factors for deep coalbed methane accumulation and reservoir formation characteristics were analyzed and summarized, identifying favorable zones for further exploration. Integrated with coalbed methane exploration practice, it was confirmed that deep coalbed methane had promising exploration potential. Research showed that: (1) the development of coal seams in the Carboniferous Taiyuan Formation in the Xunyi exploration area was influenced by two coal-forming environments: tidal flat peat bogs and lagoon peat bogs. Due to the influence of coal-forming environments and sedimentary paleogeomorphology, the coal seam distribution exhibited a “thin in the west and thick in the east” coal accumulation pattern. (2) The coal lithotypes were primarily bright coal and semi-bright coal, with the coal body structures mainly characterized by primary and fractured types. The types of reservoir space included plant cell lumen pores, intercrystalline pores of pyrite and clay minerals, and cleat fractures. (3) The gas content of coal seams ranged from 15.8 to 25.6 m³/t, indicating moderate to good gas-bearing properties. The enrichment of coalbed methane was controlled by factors such as the coal-forming environment, tectonic evolution, and preservation conditions. (4) The northwest slope area was characterized by underdeveloped faults, normal formation pressure, weak formation hydrodynamics, and large coal seam burial depth, making it a favorable zone for deep normal-pressure coalbed methane exploration. The southeast fault slope area had relatively developed faults, low formation pressure, strong formation hydrodynamics, and moderate coal seam burial depth, making it a favorable zone for medium-to-deep low-pressure coalbed methane exploration. The PZ1 well, located in the southeast fault slope area, produced a low gas flow during coal seam fracturing tests, demonstrating the promising exploration potential of deep coalbed methane in the structurally complex margin of the Ordos Basin.

The Sichuan Basin is abundant in coal resources and has achieved breakthroughs in coalbed methane exploration wells in recent years. To explore the feasibility of establishing a coalbed methane production base in the Sichuan Basin, this study reviews the stratigraphic development of coalbed methane reservoirs in the Sichuan Basin, as well as the geological and dynamic characteristics of coalbed methane development blocks in the southeastern and southern regions of Sichuan. The first coalbed methane production base in the Sichuan Basin, the Junlian-Mu’ai mining area, has more than 450 surface extraction wells, with an annual gas production of over 1.00×10⁸ m³ for five consecutive years. In the Shunan mining area, there are 328 production wells, with an annual gas production of 0.79×10⁸ m³. However, in the basin, the average daily production of coalbed methane wells targeting coal seams is less than 700 m³, while pilot exploration wells that apply general fracturing to coal seams and adjacent sandstone layers can achieve production rates of 5 000 to 8 000 m³/day. This indicates that the production dynamics of coalbed methane in the Sichuan Basin differ significantly from those in other domestic coalbed methane production bases. This difference is attributed to the widespread development of thin coal seams and the structural coal layers interbedded with tight sandstone. Consequently, it is not appropriate to apply the “sweet spot” evaluation and development methods used for typical thick coal seams in basins such as the Qinshui Basin and Ordos Basin. There is an urgent need to shift away from the approach of considering only coal seams as the sole target layer for coalbed methane wells. Practice shows that coal seams in the Sichuan Basin are primarily developed in transitional marine-continental strata. Although the lateral development of coal seams is not stable, a stable combination of “coal, sandstone, and mudstone” has formed. This special lithologic combination can create “coal-sand-coal” hydrocarbon source storage boxes, which is of significant importance for the development and production capacity of thin interbedded coal seams in the Sichuan Basin. Moreover, a large number of coal mines in the Sichuan Basin have been shut down in recent years, and the coalbed methane accumulated in the abandoned mines urgently requires secondary development using surface drilling techniques. In conclusion, based on the geological resources and existing extraction technologies in the Sichuan Basin, it is feasible to establish the third coalbed methane industry base, following the Qinshui Basin and the eastern edge of the Ordos Basin.

The Sichuan Basin is rich in coalbed methane resources, and shallow coalbed methane in the Junlian area has been commercially developed. In the adjacent Changning area, multiple drilling wells have tested and obtained gas in the Permian coal seam, revealing significant potential for coalbed methane in the Sichuan Basin. With significant breakthrough in the exploration and development of deep coalbed methane in China, and drawing from experiences in the Qinshui Basin and the Ordos Basin, a comprehensive study was conducted to assess the resource potential of deep coalbed methane in the Changning area. This study utilized data from logging, coal seam coring, and experimental testing to analyze the geology of the coal seams, evaluate gas-bearing properties, and investigate the main factors influencing reservoir formation and favorable zones. The study found that the 7th and 8th coal seams in the study area are thick, regionally stable, and high-quality, mainly composed of primary structural coals with high rank and high fixed carbon content. These seams are at the peak of pyrolysis gas generation, suggesting significant hydrocarbon generation potential. Coal seams have characteristics of high porosity, high permeability, and high cleat density, providing ample storage space, while the coal seam roof and floor—predominantly mudstone—offer excellent preservation conditions. Compared to the shallow coalbed methane in Junlian, the deep coalbed methane in the Changning area features a more stable structure, a higher proportion of free gas, and a more intact coal matrix. Coalbed methane reservoirs are formed in the target area far from erosion boundary and Class Ⅰ fault zones. The abundant free gas is more conducive to subsequent development. Based on geo-engineering conditions, a dual geo-engineering “sweet spot” index system for evaluating coalbed methane in the Changning area has been established. A favorable deep coalbed methane development area of 1 300 km² has been identified, with a calculated resource volume of 1 700×10⁸ m³, primarily located in the Luochang and Jianwu synclines. The research results have effectively guided the deployment of coalbed methane wells in the region, contributing to the high-quality development of unconventional natural gas in the Sichuan Basin.

In recent years, the Ordos Basin has achieved significant breakthroughs in the exploration and development of coal measures symbiotic gas reservoirs, whereas the Qinshui Basin continues to focus primarily on coalbed gas methane reservoirs. Notably, in the northern Qinshui Basin’s Shouyang block, Late Carboniferous to Early Permian the 3rd coal seam of the Shanxi Formation and the 9th and 15th coal seams of the Taiyuan Formation exhibit a high degree of thermal evolution, providing an excellent hydrocarbon source. The marine-continental transitional facies sedimentary environment promotes the development of various reservoir-cover combinations, demonstrating that the area has the essential geological conditions for the formation of coal measures symbiotic gas reservoirs. Drawing on data from 108 CBM exploration wells and previous studies on the depositional environment, the sedimentary characteristics of the Late Carboniferous-Early Permian coal measures have been meticulously investigated. Using a “point-line-surface” approach, the Taiyuan Formation is divided into three depositional units: the first unit (hereafter referred to as Tai-1) represents delta front deposition, the second unit (Tai-2) represents lagoon and tide flat deposition, and the third unit (Tai-3) again represents delta front deposition. The Shanxi Formation is classified into one depositional unit, namely, delta plain deposition. Based on these studies, eight typical lithofacies associations were identified, and a comprehensive analysis yielded three types with four categories of coal-measure gas reservoir covers. The study finds that in the northern part of the study area, only a single coalbed methane reservoir is developed, whereas the eastern part exhibits a combination of coalbed methane and conventional limestone fractured gas reservoir. In the central region, coalbed methane combined with tight sandstone gas predominates, while the northern-central zone is characterized by a mix of tight sandstone gas, coalbed methane, and shale gas.

The deep coalbed methane resources in the eastern Ordos Basin are abundant, and comprehensive development of coal measure gas can enhance resource utilization and improve single well gas production. To precisely identify the “sweet spot layer,” this study compares the pore development characteristics of coal measure mudstone, coal rock and tight sandstone in the Shan 2 Section of the Shanxi Formation in the eastern Ordos Basin using organic geochemical analysis, dual-beam scanning electron microscopy, high-pressure mercury intrusion, low-temperature N₂ adsorption, and low-temperature CO₂ adsorption tests. The results show that clay mineral content is the main factor influencing pore development in coal measure mudstone and tight sandstone. The microscopic pore structure of coal measure reservoirs exhibits significant variations: mudstones and tight sandstones are characterized by mesopores (2-50 nm) within clay minerals, with their mesopore-specific surface area and pore volume being roughly equal. Coal develops abundant micropores (<2 nm) in organic nanopores, with a micropore-specific surface area far exceeding the mesopore-specific surface area of mudstone and tight sandstone. Tight sandstone also develops numerous macropores (>50 nm) in clay mineral pores and microfractures, exhibiting better connectivity than mudstone. Tight sandstone provides substantial storage space for free gas, while the pores in mudstone and coal can adsorb a large amount of natural gas. The sand-mud-coal and sand-coal combinations are the main exploration targets for coal measure strata.

The differences in pore-fracture structures between deep and shallow coal reservoirs significantly affect coalbed methane extraction. Research on these structural differences provides theoretical support for exploring their physical properties and identifying favorable zones for coalbed methane exploration and development. This study analyzed coal samples from deep and shallow coal reservoirs in the Junggar Basin. These samples were tested using scanning electron microscopy, low-temperature N₂ adsorption, high-pressure mercury injection, and CT scan. The results showed that, from shallow to deep coal samples, the permeability, total pore volume, and distribution frequency of micropores and macropores gradually decreased. The shallow coal samples exhibited well-developed pores and fractures, with low fractal dimensions in the mesopore and macropore stages, strong homogeneity in pore development, and interconnection between macropores and microfractures. In contrast, the deep coal samples showed relatively isolated pore-fracture development, more complex pore development in the mesopore and macropore stages, and significant mineral filling within pores and fractures. A pore network model for the samples was established using the maximal sphere algorithm to analyze the distribution pattern, morphology, and three-dimensional structural development of the connected pores and fractures. The equivalent pores, throat parameters, and other structural parameters, along with the connectivity, were statistically analyzed. The results revealed that shallow coal samples showed higher connectivity and total porosity compared to the deep samples. The shallow samples exhibited more pores and fractures, with a dominance at the microfracture scale. Additionally, they exhibited shorter throats, larger pore-throat radii, denser pore development, higher coordination numbers, and better connectivity, which facilitated gas flow in the reservoir. The research findings provide experimental data support for the development of deep and shallow coalbed methane in the Junggar Basin using adaptive technologies, and offer valuable guidance for on-site development.

In order to establish a systematic evaluation of deep tight coal reservoirs and ensure the efficient, economic and safe implementation of moderate in-situ gasification projects in deep tight coal reservoirs, a feasibility evaluation method based on fuzzy analytic hierarchy process was developed. The methodology comprises: (1) the establishment of an evaluation index set of 3 first-level indicators, including resource conditions, reservoir conditions and preservation conditions, and 18 second-level indicators, including parameters such as coal rank, coal rock reservoir thickness, and coal rock reservoir pressure coefficient, along with a graded comment set categorizing outcomes as “feasible”, “basically feasible”, and “infeasible”; (2) the determination of indicator weights through the analytic hierarchy process; (3) the calculation of each indicator’s membership degree using a trapezoidal membership function to construct an evaluation matrix; and (4) the synthesis of the evaluation and weight matrices to ascertain the membership degrees corresponding to “feasible”, “basically feasible”, and “infeasible” for candidate areas, thus determining the feasibility based on the principle of maximum membership degree. The evaluation method was applied to the feasibility evaluation of moderate in-situ gasification for the deep No. 8 tight coal reservoir in the M block of the Ordos Basin. The evaluation results show that the membership degrees of “feasible”, “basically feasible” and “infeasible” for moderate in-situ gasification of No. 8 coal reservoir in the deep part of M block are 0.413, 0.425 and 0.162 respectively, with the maximum being 0.425, thus determining the feasibility as “basically feasible”. The comprehensive quantitative feasibility evaluation method of moderate in-situ gasification of deep tight coal reservoir, which places particular emphasis on the evaluation of preservation conditions, provides scientific guidance for the implementation of moderate in-situ gasification projects in deep tight coal reservoirs.

Coalbed methane resources are extensively developed using vertical wells, with controlled-pressure and controlled-water drainage systems. The flowing bottom hole pressure is a crucial parameter in the design of drainage schemes and equipment selection. Therefore, it is of great significance to predict the flowing bottom hole pressure for vertical coalbed methane wells. To conveniently and accurately forecast the flowing bottom hole pressure of vertical coalbed methane and guide their pressure control and drainage, a Backpropagation Neural Network (BPNN) algorithm from the field of machine learning was introduced. Additionally, the Sparrow Search Algorithm (SSA) was improved. These were coupled to establish a forecasting model for flowing bottom hole pressure based on the improved SSA-BPNN approach. Five routinely measured parameters that influence flowing bottom hole pressure were selected as the input parameters for the prediction model, with corresponding bottom hole pressure values as the output parameters. A total of 600 sets of field-measured data were partitioned into training, validation, and testing datasets to develop and validate the forecasting model for vertical coalbed methane wells. The validation set showed that the mean absolute percentage errors for the BPNN model and the Improved SSA-BPNN model on the validation set were 3.10% and 0.53%, respectively. This demonstrated that coupling the Improved SSA and BPNN effectively overcame the propensity of BPNN to converge to local optima, thereby improving the prediction accuracy of flowing bottom hole pressure in a vertical coalbed methane well. Furthermore, the improved SSA-BPNN model was compared with the Genetic Algorithm-Support Vector Regression (GA-SVR) method and the physical model-based analytical method. The results revealed that the mean absolute percentage errors for these three different models were 1.318%, 4.971%, and 18.156%, respectively. The Improved SSA-BPNN model had the lowest error, and its prediction accuracy significantly improved when the flowing bottom hole pressure was low, demonstrating its higher accuracy and strong applicability. The Improved SSA-BPNN model requires only five input parameters, reducing the complexity of input and calculation parameters. It does not require consideration of the fluid distribution within the wellbore and can cover all stages of drainage, maintaining high accuracy across different pressure ranges.

In order to clarify the gas production characteristics of medium and low rank coalbed methane wells in different regions of the Baode block of the Ordos Basin, and to guide strategy development, methods such as the Arps decline analysis, production accumulation method, and flowing material balance method were applied in conjunction with actual production data from the block to establish a calculation method for recoverable coalbed methane reserves applicable to different stages of development. Through the comprehensive application of data statistics, production dynamic analysis, and other methods, the recoverable reserves and gas production characteristics of three development units (Development Unit 1 to Unit 3) in the block were systematically studied. By comparing geological and development parameters, the influence of geological condition differences on gas production characteristics was clarified. The results showed that from north to south (Development Unit 1 to Unit 3) in the Baode block, the daily gas production during the stable production period decreased from 3 314 m³ to 864 m³, the gas recovery rate declined from 3.82% to 0.99%, the recoverable reserves reduced from 1 391×10⁴ m³ to 399×10⁴ m³, and the recovery factor dropped from 48.50% to 16.99%. Meanwhile, the gas breakthrough time extended from 99 days to 228 days, and the stable production duration increased from 981 days to 1 553 days. Correlation analysis showed that daily gas production during the stable production period was significantly correlated with the temporary storage ratio, critical desorption pressure, and the thickness of the 8+9 coal seam, while recoverable reserves were highly correlated with the thickness of the 8+9 coal seam and the gas content of the 4+5 coal seam. A comparison of geological parameters indicated that the main coal seam thickness, gas content, and temporary storage ratio in Development Unit 1 were superior to those in Development Unit 2 and Unit 3, and the preservation conditions were also better. The study concludes that the north-south differences in gas production characteristics of the Baode block are primarily influenced by geological conditions. The northern Development Unit 1 has superior resource conditions, with thicker coal seams, higher gas content, and a larger temporary storage ratio, resulting in higher stable gas production and higher recovery rates. The southern Development Unit 3 has poorer resource conditions, leading to lower stable gas production but longer stable production periods. The findings provide a scientific basis for the efficient development of medium and low rank coalbed methane fields and the optimization of different unit drainage systems in the Baode block.

The coalbed methane (CBM) blocks in the southern Qinshui Basin exhibit strong reservoir heterogeneity, resulting in challenges for accurate productivity prediction of gas wells. Furthermore, the absence of tailored fracturing designs has caused substantial variations in post-fracturing production performance among adjacent wells. To address these issues, a predictive model for well production capacity was developed based on geological, well logging, fracturing, and production data from 187 vertical CBM wells in the southern Qinshui Basin. The model employs a random forest algorithm integrated with a multi-task learning strategy and utilizes a particle swarm optimization (PSO) algorithm to optimize fracturing parameters. A deep convolutional autoencoder-decoder was applied to unstructured data (e.g., well logs), and the integration of random forest with multi-task learning strategies effectively addressed limited sample sizes and poor generalization, ensuring high prediction accuracy under small-data conditions. The results indicate that well depth, fracturing fluid volume, and small-sized proppant dosage are the dominant factors affecting productivity. Geological conditions determine long-term productivity, whereas fracturing parameters predominantly affect peak production performance. The multi-task random forest algorithm achieved high accuracy on small datasets, with R² values of 0.883 for 30-day peak cumulative production and 0.887 for 5-year cumulative production in the test set. Furthermore, the R² for 5-year cumulative production predictions of six new wells reached 0.901, confirming the model’s robustness and reliability in field applications. The PSO-optimized fracturing parameters significantly improved the productivity classification and overall productivity levels of the gas wells. The optimized parameters increased single-well productivity by 153-188% compared to original designs, demonstrating substantial practical efficacy. The combined multi-task learning and PSO framework successfully resolves productivity prediction and fracturing optimization challenges under small-data constraints. The proposed model and fracturing parameter optimization algorithm provide theoretical support and practical references for efficient CBM development in the southern Qinshui Basin.

As waterflooding reservoirs continue to be developed, the conflicts in water flooding become more pronounced, with significant differences in the underground flow field, pressure field, and remaining oil saturation field. Conducting quantitative evaluation of flow field differences can effectively guide the optimization and control of underground flow fields, mobilize and exploit various types of remaining oil, and enhance the waterflooding recovery efficiency of the reservoir. The study analyzed the factors influencing flow heterogeneity, including static reservoir heterogeneity and dynamic factors such as fluid viscosity, well pattern, and artificial fractures. It highlighted the complexity of flow heterogeneity evaluation and emphasized the necessity of quantitative evaluation. Next, various methods for characterizing heterogeneity were compared, and the Lorenz coefficient was selected as a key parameter for characterizing flow heterogeneity. This coefficient is applicable to non-normally distributed data, ranging from 0 to 1, and can quantitatively characterize flow variability. Additionally, flow velocity, as the most intuitive representation of the flow field, was chosen as the computational indicator to develop a method for evaluating heterogeneity. From the parameter calculation results graph, the diagonal line with a slope of 1, where the Lorenz coefficient was 0, was referred to as the “completely homogeneous line,” indicating the absence of heterogeneity in the evaluated object. Conversely, the largest triangle formed by this diagonal line and the x or y axis, where the Lorenz coefficient was 1, was termed the “completely heterogeneous line.” To make computation faster, simpler, and more intuitive, a plate model was developed to characterize the flow in the fracture and reduce the simulation workload of hydraulic fractures in numerical simulations. By integrating the pressure distribution data from numerical simulation with MATLAB programming, the pressure was converted into flow velocity, enabling the calculation of the Lorenz coefficient using flow velocity as the evaluation criterion. Consequently, a method for characterizing flow heterogeneity was established. Furthermore, the paper designed experimental plans for triangular well patterns and semi-inverse seven-spot well patterns considering factors such as the presence or absence of high-permeability zones and fractures, fracture angles, and permeability of high-permeability zones to investigate the relationship between the Lorenz coefficient and recovery coefficient. Among them, 17 schemes were designed for the triangular well pattern, while 21 schemes were developed for the inverted seven-spot well pattern. The analysis revealed that for triangular well patterns, a linear relationship was observed when the Lorenz coefficient was below 0.94. However, once the Lorenz coefficient exceeded 0.94, the recovery factor decreased exponentially with the increasing Lorenz coefficient. For inverted seven-spot well patterns, this transition occurred when the Lorenz coefficient reached 0.96. The thresholds distinguishing strong and weak seepage field differences were determined to be 0.94 for the triangular well pattern and 0.96 for the semi-inverse seven-spot well pattern. Specifically, for triangular well patterns, when the Lorenz coefficient exceeded 0.94, the recovery factor dropped sharply, indicating excessive flow heterogeneity. In such cases, flow field adjustments were necessary to improve development performance. Similarly, for inverted seven-spot well patterns, optimization and adjustment of the flow field were required when the Lorenz coefficient reached 0.96. Finally, the G7 reservoir was evaluated using the above method and adjustments were implemented to reduce seepage diversity. The evaluation yielded Lorenz coefficients of 0.949 6 for and 0.954 0 for two sand bodies, identifying these two sand bodies as areas with significant seepage disparities within the block. Further analysis revealed the reasons for the strong seepage disparities for the two sand bodies. In the eastern well area of the first sand body, a localized high-permeability zone was present, whereas the central and western regions exhibited weaker seepage. The causes were attributed to both static and dynamic factors: statically, the reservoir heterogeneity resulted in better physical properties and stronger seepage in the central and eastern parts, while the western part had poorer physical properties and weaker seepage; dynamically, the central region suffered from an incomplete well pattern, whereas the eastern region had a more well-developed well pattern. Although the western region had poorer physical properties, the G7-11 well, after the fracturing stimulation and with a relatively complete well pattern, exhibited locally strong seepage. In the second sand body, the central and eastern regions showed significant seepage disparities. The analysis attributed this to the strong reservoir heterogeneity causing substantial seepage differences statically, while dynamically, the overly dense well pattern and injection-production regime in the central and eastern regions exacerbated seepage disparities. Consequently, flow field adjustments were necessary. Strategies were formulated to address the pronounced seepage heterogeneity in these sand bodies post-evaluation. These strategies include optimizing the well pattern combined with segmented water injection to ameliorate both areal and vertical seepage disparities, adjusting the flow field to balance areal seepage differences, and implementing cyclic water injection to reduce flow heterogeneity. Numerical simulation was conducted to forecast the development trends, and a comparison of relevant indicators before and after the adjustments was carried out. The results showed that the Lorenz coefficient was reduced below the critical threshold, and the oil recovery efficiency increased by 1 percentage point over 10 years, effectively achieving water control and oil stabilization. The findings demonstrate that the proposed method can accurately evaluate seepage heterogeneity and help explore the residual oil, offering significant guidance for improving oil recovery efficiency. Meanwhile, this study determines the critical thresholds for strong and weak fluid flow heterogeneity in triangular and semi-inverse seven-spot well patterns, which are commonly found in Subei fault-block reservoirs. In practical applications, these threshold criteria should be re-evaluated based on specific well pattern configurations.

The development of cleat fractures in coal rocks leads to reduced strength, and the influence of drilling fluids during drilling further escalates the risk of borehole instability. By combining laboratory experiments, theoretical analysis, and numerical simulations, this study elucidates the mechanisms of instability in cleated coal rocks under the influence of drilling fluids: (1)the clay minerals in the coal rock are predominantly composed of kaolinite, which is resistant to hydration, with little to no montmorillonite present, and a low proportion of illite/smectite(I/S) mixed layers. Consequently, both hydration expansion (averaging 0.35%) and rolling dispersion (averaging 89.64%) are minimal, indicating the instability of coal rocks is primarily driven by mechanical factors. (2) Vertically intersecting face and end cleats create flow channels that allow drilling fluid to intrude into the coal strata. Since the dimensions of face cleats are generally larger than those of end cleats, face cleats are more susceptible to fluid intrusion, leading to borehole instability. (3) The intrusion of drilling fluid into the cleat fractures leads to an increase in formation pressure around the well and a reduction in radial stress, thereby raising the risk of borehole instability. Notably, for high-permeability face cleats and cross-cutting cleats that intersect the boreholes, deeper fluid intrusion further elevates formation pressure and diminishes radial stress, exacerbating the risk of instability. (4) Additionally, the characteristics of the cleats also affect the depth to which drilling fluid intrudes into the coal strata. In cleats with greater widths and higher densities, the drilling fluid penetrates deeper and generates higher pressures near the borehole wall, thereby increasing the likelihood of instability. Therefore, plugging particles should be added into the drilling fluid according to the size of the cleats and the density of the drilling fluid should be maintained within a reasonable range, in order to minimize borehole instability caused by fluid intrusion. The study provides a new perspective to understand the instability mechanism of cleats under the action of drilling fluid, and provides theoretical guidance for the analysis of coal rock wall stability.

In order to address the technical challenges in equipment configuration for hybrid oil-electric fracturing in deep coalbed methane reservoir modification, this study used the configuration of hybrid oil-electric fracturing equipment for deep coalbed methane at the Jishen 11-7A platform in the Daning-Jixian block on the eastern edge of the Ordos Basin as a case study. Specific configuration requirements were proposed in aspects such as the calculation of fracturing pump group power, power grid capacity calculation considering power loss in transmission lines and auxiliary system power, the capacity of transportation and sand mixing equipment, calculation of the liquid supply capacity for the low-pressure manifold system, and the functions of the high-pressure manifold system and instrument skid. A method for calculating the configuration of hybrid oil-electric fracturing equipment for deep coalbed methane was proposed by integrating fracturing operation requirements with equipment performance and applied to three wells on the platform. The application results showed that the developed configuration method met the requirements for high pressure, large displacement, high sand ratio, large sand volume, and 24-hour continuous fracturing operations in deep coalbed methane. With a pump power reserve factor of 1.3, the power redundancy factor was 1.46. The applied capacity of 19 000 kVA exceeded the total line demand of 18 269 kVA, meeting power demand. The capabilities of sand transportation, sand mixing, and low-pressure liquid supply equipment also met operational requirements. Fracturing operations at the Jishen 11-7A platform began on March 10, 2024, and concluded on March 31, 2024. The operating pressure ranged from 55 to 75 MPa, with a displacement of 19 to 20 m³/min and 14 to 16 m³/min in risk zones. The sand ratio ranged from 6% to 24%, with a maximum single-pump displacement of 2.0 m³/min. The three wells had a total liquid volume of 73 926.7 m³, including 36 458.1 m³ from the electric pump, with a total electricity consumption of 719 200 kW⋅h. A total of 34 fracturing sections across 3 wells were finished, completing the reservoir reconstruction of the horizontal wells of China’s First Hybrid Oil-Electric Deep Coalbed Methane Platform. The findings provide a method for configuring fracturing equipment in deep coalbed methane operations and offer insights for fracturing equipment configuration in other oil and gas blocks in China.

The Ordos Basin is rich in deep coalbed methane resources, with block X of the Shenmu gas field being a key exploration and development area for the Jidong Oilfield in the basin. The deep Benxi Formation the 8th coal seam is an important production resource in this block, mainly produced through horizontal well drilling and large-scale fracturing operations. The Benxi Formation the 8th coal seam is characterized by complex local structures, brittle and soft coal layers, fast drilling rates, and a tendency for collapse, making trajectory control of the horizontal section difficult and posing a challenge to achieving a high rate of reservoir drilling encounter. Therefore, improving the high drilling encounter rate of coalbed methane horizontal wells and achieving rapid drilling and completion have become key technical challenges in the exploration and development of this domain. To address these challenges, multidisciplinary technical research, including geology, seismic analysis, logging, mud logging, and drilling, were conducted. This research led to the development of a deep coalbed methane horizontal well geological guidance technology, which included fine seismic structural interpretation as the foundation and near-bit orientation gamma imaging analysis as the core. This technology involved several key aspects: precise coal seam structural characterization, coal seam feature prediction, landing trajectory control, overall coal seam determination, geological guidance for the horizontal section, and control of drilling engineering parameters. Through the effective integration and proper application of these technologies, precise well landing and fine-tuning of the horizontal trajectory in real time were achieved. In geological guidance practices in the exploration and pilot test wells of this block, the horizontal well geological guidance technology demonstrated significant results, increasing the coal seam drilling encounter rate from 70.4% in the initial risk exploration well to the current average of 94%. Additionally, this technology ensured smooth and seamless wellbore trajectory, facilitating the successful implementation of casing and cementing operations and shortening the drilling and completion cycle. The efficient drilling and completion of deep coalbed methane horizontal wells have laid a solid resource foundation for subsequent large-scale fracturing and economic production, providing valuable insights for geological guidance in deep coalbed methane exploration in other blocks of the Ordos Basin.

China’s deep coalbed methane demonstration base has been preliminarily established and is gradually entering an important stage of large-scale exploration and development. This breakthrough has brought new opportunities and challenges to the energy sector. With ongoing development, traditional 3D static models have proven inadequate for predicting the dynamic in-situ stress evolution of coupled seepage-stress interaction in strongly heterogeneous reservoirs under large-scale horizontal well fracturing conditions. In response, this study takes the deep coalbed methane reservoir in the Daning-Jixian block as an example to conduct in-depth investigation of the dynamic stress field during reservoir fracturing. This study adopts an integrated geological engineering fracture network model for coalbed methane reservoirs to simulate the horizontal well platform fracturing process, comprehensively considering both geological conditions and engineering factors, thereby more accurately reflecting the actual situation. A time-dependent simulation study of the dynamic stress field during large-scale fracturing for horizontal well platform S was carried out. The results indicate that after multiple rounds of fracturing-induced stress superposition, the present in-situ stress distribution has undergone significant alterations. In order to quantify this impact, a key indicator—the horizontal principal stress difference coefficient, defined as the ratio of the two horizontal principal stresses—was introduced. When this coefficient approaches 1, it indicates an optimal fracturing effect. The simulation results show that the range of the horizontal principal stress difference coefficient in the post-fracturing area gradually decreases from 1.15-1.25 to 1.05-1.15, with most areas around the well exhibiting a value of less than 1.10, demonstrating that the large-scale fracturing in horizontal wells is effective. This research achievement not only provides a more reasonable simulation method for the large-scale fracturing development of deep coalbed methane, but also offers a scientific basis for optimizing fracturing design and improving coalbed methane recovery. Through an integrated geological engineering method, it is possible to more accurately predict and assess the dynamic stress field changes during the fracturing process, thereby guiding the fracturing operations in actual production.

Waste oil-based drill cuttings are one of the most severe environmental pollutants generated during oil and gas field exploitation. They are hazardous wastes characterized by high production volume, elevated oil content, complex composition, and extreme difficulty in proper disposal. Among various methods such as centrifugal separation, solvent extraction, surfactant hot washing, pyrolysis, etc., the thermal treatment method that removes volatile and semi-volatile pollutants (such as hydrocarbons) by pyrolysis is widely favored due to its short processing time and high removal efficiency. However, conventional pyrolysis methods operate at high temperatures, consume significant energy, and exhibit high material selectivity, which makes them prone to coking and ultimately results in low treatment efficiency. Based on conventional pyrolysis techniques, the required pyrolysis temperature can be significantly lowered by adding catalysts and anti-coking agents to pretreat oil-based drill cuttings. The removal efficiency of oil in oil-based drill cuttings was studied using three different catalysts, CA, CB, and CC (representing catalysts A, B, and C), at temperatures of 200, 250, and 300 ℃. The CA and CC catalysts with superior performance were then compounded, and it was found that a compounding ratio of 2∶1 (CA∶CC) significantly improves the treatment effect. Screening of anti-coking agents JA, JB, and JC (representing coking agents A, B, and C) revealed that JB effectively reduces the adhesion of solid residues on the inner wall of the reactor. Utilizing central composite design (CCD) and response surface methodology (RSM) ensures the accuracy of the results while reducing the number of required experiments. The response surface methodology (RSM) model results indicate that the optimal treatment parameters are as follows: for 300 g of oil-based drill cuttings, a composite catalyst addition ratio of 4.417% (with a CA∶CC atio of 2∶1), a reaction temperature of 285.43 ℃, and a reaction time of 97.17 min, under which the oil content of the drill cuttings is reduced from 14.76% to 0.20%. Analysis of the products after treating the oil-based drill cuttings under the optimal conditions, in reference to the Sichuan Provincial Local Standard of the People’s Republic of China “Standard for the Utilization and Disposal of Residual Solid Phases after Comprehensive Utilization of Oily Sludge in Natural Gas Exploitation: DB51/T 2850-2021”, revealed that the heavy metals and other key indicators in the solid phase residues are effectively removed. The resulting solid residue, once treated, can be repurposed to pave the well site, thereby achieving both effective removal of oil-based drill cuttings and waste utilization.

This study focuses on the applicability of the catenary anchor leg mooring (CALM) system subjected to bending effects in the Weizhou sea area of the South China Sea. The survivability of the mooring system under extreme environmental conditions in the Weizhou sea area of the South China Sea was analyzed, and a verification method for ultimate mooring force considering the bending effects was proposed. The joint probability distribution model of significant wave height and mean zero up-crossing period in the Weizhou sea area of the South China Sea was established. Based on this model, the 100-year return period contour of significant wave height and mean zero up-crossing period was calculated and plotted. Combined with the 100-year return period wind condition and the 10-year return period flow condition, the ultimate verification sea state of the Weizhou sea area of the South China Sea was constructed. A time-domain hydrodynamic analysis of the CALM system was conducted based on the Morison Equation, and the most probable maximum mooring tensions of R4S studless mooring chains with diameters of 76.2, 88.9, and 101.6 mm were evaluated using the Gumbel Distribution. Finite element analysis was performed to examine the effects of in-plane and out-of-plane bending of mooring chains caused by the chain stopper and hawse pipe arrangement, and the resulting stress distribution in the mooring chain was analyzed. Finally, the applicability of the CALM system in the offshore Weizhou area of the South China Sea was evaluated. The analysis results showed that when using the mooring arrangement with the chain stopper and hawse pipe, the mooring chains experienced additional stress concentration due to in-plane and out-of-plane bending, requiring a bending safety factor of 1.3. The mooring system with 101.6 mm diameter chains was suitable for deployment in the Weizhou sea area of the South China Sea. The system with 88.9 mm diameter chains met the standard verification requirements but did not satisfy mooring analysis criteria when considering the bending effects between chain links. The system with 76.2 mm diameter chains did not meet the standard verification requirements.