Under the “dual carbon” initiative, geothermal energy is gaining attention as a focus of development due to its stability, high quality, abundant reserves, and green, low-carbon attributes. Petroleum companies have inherent advantages in geothermal energy development, yet effective reference models and experiences for market-oriented and large-scale applications remain limited. Leveraging these advantages to advance geothermal energy development has become a new developmental challenge for petroleum enterprises. PetroChina Jidong Oilfield seized the opportunity to expand its geothermal business by utilizing a comprehensive resource assessment system, scientific planning, efficient project execution, and extensive management experience. The introduction of advanced sandstone reservoir pressure-free reinjection technology has successfully addressed the challenge of large-scale sandstone geothermal reservoir development, establishing a new model for urban district heating and clean energy substitution. This replicable and scalable “Jidong Model” provides a blueprint for traditional petroleum companies in geothermal resource development, fostering a green, low-carbon, and high-quality transformation in the industry through new productivity models.

The global energy structure is undergoing a fundamental shift from a reliance on fossil fuels with clean energy as a supplement, to a focus on clean energy supported by fossil fuels. Clean, renewable geothermal resources are gradually becoming a key energy source for sustainable development. This study focused on Gaocheng District in southwestern Hebei Province, leveraging its unique geological structural characteristics and abundant geothermal reserves. A refined geothermal resource assessment system was established, forming the basis for optimal well placement and spacing for efficient geothermal resource development. Results indicated that the development area had excellent heat source conditions, a highly favorable reservoir-caprock system, and low scaling and corrosion risks from formation fluids, indicating high-quality geothermal resources. Forty extraction and reinjection wells were deployed with a 1:1 ratio（20 extraction wells and 20 reinjection wells）. With a well spacing of 380 m and a projected operational lifespan of 30 years, the setup was expected to support sustainable heat exchange and heating needs. Based on geological structural characteristics, this study provides a valuable reference for the sustained and efficient exploitation of geothermal resources.

With the growing global demand for clean energy, geothermal resources as a renewable energy source have attracted widespread attention. This study evaluated the geothermal resource development potential and application prospects in the Xiangfu District of Kaifeng City. The results showed that the vertical temperature field of the thermal reservoir in the Xiangfu District could be divided into varying temperature zones, constant temperature zones, and increasing temperature zones, with depth significantly influencing the temperature distribution. The geothermal gradient increased with depth above 500 m and gradually decreased below 500 m. Chemical analysis of geothermal fluids showed significant differences in the water chemistry types between thermal reservoirs at different depths, with no significant hydraulic connection between the reservoirs. Based on the maximum allowable depth reduction method and the extracted water volume method, the total exploitable geothermal fluid without reinjection was estimated to be 9,390×10⁴ m³. Under complete reinjection conditions, the total exploitable geothermal fluid was estimated to be 360.7×10⁸ m³, indicating substantial development potential. These research findings provide a scientific basis and guidance for the efficient development and utilization of geothermal resources in the Xiangfu District.

Geothermal energy and petroleum are both vital subsurface energy resources. Numerical simulation of geothermal and reservoir systems is a key technology for evaluating and optimizing the development and utilization of these resources, playing an essential guiding role in the energy sector. By comparing the foundational mathematical models, numerical methods, and case studies of geothermal and reservoir simulations, this study highlights the similarities and differences in their application to the development of these two energy sources. In terms of simulation methods, geothermal numerical simulations focus on heat conduction and geothermal field variation, whereas reservoir numerical simulations emphasize fluid dynamics and the oil extraction process. Regarding simulation results, geothermal simulations are used for geothermal resource development planning and the optimization of key production parameters, while reservoir simulations are primarily applied to reserve estimation, injection-production parameter optimization, and well production management. This comparative analysis provides theoretical and practical guidance for research and applications in geothermal energy and petroleum engineering, promoting the efficient and sustainable utilization of both energy resources.

The Nanpu Sag in the Huanghua Depression of the Bohai Bay Basin is rich in geothermal resources, with multiple geothermal fields identified, including Gaoshangpu-Liuzan, Nanpu, and Matouying. The thermal reservoirs, primarily composed of fluvial sandstone from the Guantao Formation, exhibit advantages such as high temperatures（70-90 ℃）, significant water amounts (100 m³/h), large-scale reservoirs, and thick caprocks. However, their development faces several challenges, including optimal target area selection, sustainability evaluation, efficient drilling and production processes, reinjection into sandstone reservoirs, long-distance centralized thermal water transportation, and intelligent monitoring. To address these challenges, practical exploration in the Gaoshangpu-Liuzan geothermal field has led to the development of five core technologies: 1） optimization and detailed resource evaluation technology for exploration areas; 2） well placement and thermal field simulation technology; 3） geothermal well drilling, completion, and pressure-free reinjection for sandstone thermal reservoirs; 4） multi-well collection and long-distance thermal water transportation technology; 5） intelligent management and control technology for geothermal development. These advancements provide technical support for geothermal heating projects in the Gaoshangpu-Liuzan geothermal field and the geothermal development efforts of Jidong Oilfield.

Drilling medium-deep geothermal wells is costly, but converting existing depleted oil and gas wells into geothermal wells can significantly reduce these costs. This study analyzed heat extraction performance based on the engineering parameters and test data of a geothermal well reconstructed from a depleted oil and gas well in the northern Shaanxi region. Long-term heat extraction performance was simulated numerically to explore the impact of inner pipe design parameters. The study found that improving the thermal insulation of the inner pipe had a more significant impact on geothermal well heat extraction power as depth increased and flow rate decreased. However, the diameter of the inner pipe had a minimal influence on heat extraction performance and was less sensitive to changes in depth and flow rate, resulting in a limited overall impact. Additionally, the study quantified the effect of inner pipe material selection on the system's economic performance throughout its life cycle. Results indicated that reducing the inner pipe's thermal conductivity from 0.2 W/（m·K） to 0.02 W/（m·K） under certain working conditions could increase the outlet water temperature by 0.66 °C during one heating season. However, it also raised the average heating cost by 0.035 RMB/（kW·h） and extended the payback period by 1.83 a. Therefore, considering the limited benefits of using high-insulation inner pipe materials, it is recommended to prioritize temperature and pressure resistance when designing inner pipes for geothermal wells reconstructed from depleted oil and gas wells.

Geothermal energy, as a clean energy source, plays an important role in China's energy transition. Energy companies across the country are actively promoting geothermal development projects. PetroChina Jidong Oilfield Company is a leader in the large-scale development of geothermal resources and has established the largest geothermal heating demonstration base in China, the Caofeidian new town geothermal heating project. As a key project for public welfare, geothermal heating requires cost reduction, quality improvement, and efficiency enhancement for large-scale development. With long construction cycles and stringent requirements, Jidong Oilfield has achieved low-cost, high-efficiency geothermal well drilling through various technological measures, including integrated geological engineering profile design, optimization and simplification of wellbore structure, cementing design optimization, and rapid drilling technology improvements. This research combines practical case studies from the Jidong Oilfield geothermal heating project, analyzing the factors influencing cost and construction progress, identifying construction issues, and detailing countermeasures and implementation effects. This paper offers valuable solutions for optimizing geothermal well design and cost reduction in large-scale geothermal development projects.

Geothermal energy, as a key clean and renewable resource, is abundant in China, particularly in medium- to deep-layer geothermal reservoirs, which hold significant development potential. Promoting the development and utilization of medium- to deep-layer geothermal resources is crucial for optimizing China’s energy consumption structure, achieving energy savings and emissions reductions, and advancing the “Dual Carbon” goals. This study took a geothermal well in Shaanxi as an example and proposed a “lower production and upper reinjection” technical scheme implemented within a single wellbore. By comprehensively considering the dynamic heat exchange processes among the inner pipe, annulus, and surrounding formation, a 3D coupled thermal-fluid-solid model of the horizontal wellbore and reservoir was established. The model was used to investigate the effects of interlayer thickness, formation permeability and porosity, and completion tubing structure on heat extraction efficiency. Results indicated that the interlayer significantly impacted heat extraction. Without an interlayer, the extracted water temperature decreased by as much as 9°C after 30 a of stratified production and reinjection. The optimal heat extraction was achieved with an interlayer thickness of 40 m. While maintaining constant production and reinjection rates, reductions in porosity and permeability of the reinjection layer and interlayer negatively impacted heat extraction, whereas the permeability and porosity of the production layer had minimal influence.

CO₂ enhanced oil recovery（EOR） with carbon capture and storage（CCS） projects offer dual benefits of increasing oil recovery and CO₂ storage, making it one of the most economically viable carbon sequestration methods nowadays. However, EOR-CCS projects typically involve multiple well sites, and the high risk of CO₂ leakage from wellbores poses significant safety and environmental challenges over large areas. To address the limitations of previous atmospheric diffusion studies based on point-source leakage at well sites, a new method for studying surface CO₂ leakage and atmospheric diffusion in EOR-CCS projects based on area-source flux monitoring at well sites was developed. A case study of an oilfield in East China, based on scenario analysis, demonstrated that CO₂ leakage flux monitoring using the eddy covariance method could provide accurate data on area-source leakage fluxes for entire well sites, enabling large-scale computational fluid dynamics（CFD） simulations. Multi-well-site CFD diffusion simulations effectively captured the impact of complex regional topography and multiple well sites on CO₂ leakage, supporting regional safety and environmental risk management for well site leakage.

Low-permeability sandstone reservoirs in the Ordos Basin face significant challenges, such as severe water injection deficiencies and short effective durations of enhanced injection measures, leading to poor water flooding development performance. To improve the injection capacity of deficient wells, geological and injection water quality data from severely deficient areas in the western Ordos Basin were analyzed. The overall injection situation of these areas was examined, and the influence of geological factors and injection water quality on injection deficiencies was explored. Nine factors affecting water injection effectiveness were selected, divided into two major categories. Using the Spearman correlation analysis method, the correlation coefficients between injection deficiencies and these factors were calculated. Results indicated that the interaction between injection water quality and formations exhibited cumulative effects, leading to a gradual increase in injection pressure during prolonged water injection, ultimately reducing reservoir injection rates. Taking the Chang-8 reservoir re-injection area in the western Ordos Basin as an example, the correlation coefficients ranked as follows suspended solids content > oil content > median pore throat radius > variation coefficient > suspended particle size. Based on correlation analysis and field data, targeted recommendations for mitigating injection deficiencies were proposed to improve water injection performance.

Waterflooding characteristic curves are widely used in analyzing oilfield production dynamics. Most existing waterflooding characteristic curves are derived from statistical analyses of production data from sandstone reservoirs, commonly categorized into four types: Type A, Type B, Type C, and Type D. To assess the applicability of these curve types to fractured-cavity carbonate reservoirs, the Tahe fractured-cavity carbonate reservoir was selected as a case study. By analyzing reservoir fracture-cavity structures and oil-water production data, the Type A waterflooding curve was identified as more suitable for the Tahe reservoir. The study of 255 wells with long-term production data revealed six water cut increase patterns and four waterflooding characteristic curve types. Wells controlled by single cavities exhibited single-straight-line waterflooding characteristic curves and slow water cut increase patterns. Wells controlled by dual cavities displayed double-straight-line waterflooding characteristic curves, with water cut increase patterns categorized as slow rise, rapid rise, or fluctuating. For wells affected by water injection in dual-cavity structures, triple-straight-line waterflooding characteristic curves were observed, with water cut increase patterns featuring rapid rise and catastrophic flooding. Wells located in multi-cavity, complex fracture-cavity structures demonstrated irregular waterflooding characteristic curves, with water cut patterns including slow rise, rapid rise, fluctuating, and catastrophic flooding. A comparison with waterflooding characteristic curves of sandstone reservoirs clarified the applicability conditions for fractured-cavity carbonate reservoirs: adherence to the stable waterflooding principle（i.e., the straight-line principle） and the absence of a fixed water cut threshold. This study provides a foundation for predicting production dynamics in fractured-cavity carbonate reservoirs.

The Jurassic formations of the Ordos Basin, with burial depths ranging from 300 to 2,200 m, exhibit numerous horizontal bedding planes within the reservoirs, leading to complex variations in fracture morphology and propagation direction during hydraulic fracturing. Laboratory Brazilian splitting tests were conducted to evaluate the tensile strength of core samples from Jurassic formations, considering the impact of bedding. The tensile strength differences between specimens perpendicular to and parallel to bedding planes were compared. Based on the experimental data, a three-dimensional finite element model using the cohesive element method was developed to characterize hydraulic fracturing in multilayered Jurassic reservoirs, focusing on the effects of bedding strength and in-situ stress differences on fracture morphology and propagation paths. The results indicated that bedding strength and stress differences were the primary factors influencing fracture deflection. High bedding strength and large stress differences reduced the restraining effect of bedding on fractures, enhancing their vertical penetration across layers. Conversely, low bedding strength and small stress differences led to the opening of bedding planes, causing fractures to deviate and propagate along bedding surfaces. These findings provide guidance for optimizing hydraulic fracturing operations in Jurassic reservoirs.

Most mature oilfields in eastern China, particularly medium and high permeability fault block reservoirs, have entered the high water-cut development stage. Enhancing oil recovery（EOR） in such reservoirs is crucial for stabilizing production and extending the economic development period of aging fields. The Chun-47 Block in the Dongying Sag of the Jiyang Depression is a medium and high permeability fault block reservoir. Adaptive well pattern design and differential adjustment strategies tailored to the reservoir characteristics during various development stages have enabled efficient exploitation, with a current recovery factor of 78.5% and an ultimate recovery factor of 84%. Analyzing the mechanisms underlying efficient development and identifying the field’s development patterns have academic and practical significance. This study examines the geological characteristics, reservoir macroscopic and microscopic features, fluid properties, and development strategies. Results highlight that favorable reservoir properties form the foundation for high recovery rates, while high waterflood displacement efficiency and comprehensive stage-specific development strategies serve as the key technical aids. The practical experience, strategies, and methods adopted for the efficient development of this block provide valuable insights for similar oilfields.

The coal seams in the Shizhuang block of the Qinshui Basin are characterized by developed cleats, low permeability, soft coal structures, and strong heterogeneity. In earlier development stages, hydraulic segmented fracturing of horizontal wells resulted in significant variations in gas production per well, with unclear relationships between gas well productivity and fracturing parameters. This led to poor economic performance in coalbed methane（CBM） development, highlighting the need for optimization of horizontal well fracturing parameters. This study established a comprehensive fracability index（CFI） evaluation model based on coal seam brittleness, in-situ stress, and reservoir-seepage characteristics. Considering the impact of stress shadows during horizontal well fracturing, stress shadow and fracture interference charts were generated for different coal seam structures, clarifying the effects of net pressure, fracture length, spacing, and cluster number on induced stress. Based on the economic requirements for CBM development, the fracturing positions and segment design parameters of horizontal wells with different CFI values were optimized by considering the relationship between the internal rate of return (IRR) of single-well investment and daily gas production. A high-efficiency fracturing technology chart for horizontal wells was developed, aimed at improving the fracturing effectiveness in the Shizhuang block of Qinshui Basin and enhancing the quality and efficiency of CBM exploration and development.

The selection of favorable areas for coalbed methane（CBM） development provides critical assurance for reducing investment risks. Taking the No. 4+5 coal seam in the Shanxi Formation and the No. 8+9 coal seam in the Taiyuan Formation of the Yangjiapo block in the eastern margin of the Ordos Basin as research objects, a development potential evaluation system was established by optimizing influencing factors for combined layer development. Based on CBM development characteristics, production capacity equations were used to predict daily gas production. Economic benefit evaluation was conducted considering geological and engineering features, and favorable areas for single-seam and combined layer CBM development were ultimately delineated. The results showed that the favorable areas for combined layer development in the Yangjiapo block were located in the central and northeastern parts of the block. The economic threshold daily gas production for single-seam development of the No. 4+5 and No. 8+9 coal seams and their combined layer development were 982, 1,063, and 1,270 m³, respectively. A small portion in the northwest was suitable for single-seam development, where sequential development of the No. 4+5 and No. 8+9 coal seams could enhance production. The central and southern parts of the block were suitable for combined layer development, where optimizing drainage and production schedules could improve gas yield. For reserve areas, further clarification of geological conditions and optimization of construction techniques were needed before evaluating development feasibility. These findings enrich the methodology for selecting favorable areas in multi-seam CBM zones and provide guidance for future development planning in the study area.

To investigate the failure characteristics of calcite veins with complex morphologies in coal rock under uniaxial compression, thin-section observation was used to examine the calcite vein filling within coal rock. Fractal dimension analysis was applied to quantify the complexity of calcite morphology. Numerical simulations of uniaxial compression tests on coal rock containing calcite veins of varying morphologies were conducted using a two-dimensional real failure process mesoscopic analysis software. The results revealed that the complexity of calcite morphology significantly affected the mesoscopic damage evolution characteristics of coal rock. The peak strength generally increased with the fractal dimension of the calcite veins. A positive correlation between crack rate and peak stress was observed, indicating that higher peak strengths corresponded to higher crack rates at final failure. During uniaxial compression, multiple microcracks initially appeared around the calcite vein particles, with fracture propagation directions closely aligned with the vein orientation, influencing the crack propagation direction in the coal rock. Additionally, coal rock with larger fractal dimensions exhibited more acoustic emission events, signifying more complex failure patterns. These findings contribute to a deeper understanding of how calcite vein distribution affects the mechanical properties of coal rock and provide a novel approach to studying the mesoscopic damage evolution in coal rock containing calcite veins.

Determining the gas source and contribution in coal measure gas commingled production lays the foundation for developing commingled production schemes. Based on coal measure gas exploration and development data from the Wulihu mining area in the Lu’an mining area, carbon and hydrogen isotope tests of CH₄ from the No. 3+4 coal measure strata and the No. 15 coal seam were conducted. Using a binary gas source model, the gas source and proportions of six commingled wells were identified. Additionally, considering factors such as gas content, permeability, and desorption capacity, the production contributions of gas from the No. 3+4 coal measure strata and the No. 15 coal seam in three commingled wells were calculated based on catastrophe theory. The results showed that when isotopic differences in carbon and hydrogen values were observed between multiple gas-producing layers, these differences could be used to determine the source and proportion of gas from each layer. When the No. 3+4 coal measure strata consistently produced gas while the No. 15 coal seam did not desorb gas, the produced gas entirely originated from the No. 3+4 coal measure strata. When both the No. 3+4 coal measure strata and the No. 15 coal seam stably produced gas, the gas productions were 42%-45% and 55%-58%, respectively. The production split coefficients calculated based on catastrophe theory closely matched experimental results, confirming the feasibility of this method. This study provides a method and reference for accurately identifying gas sources and contributions in coal measure gas commingled production for this mining area.

Guizhou Province is rich in coalbed methane（CBM） resources; however, the development of tectonic coal constrains the increase of reserves and production. By studying the reservoir characteristics of tectonic coal in Guizhou, adaptable exploration and development technologies are proposed, providing a theoretical basis for the safe and efficient development of tectonic coal reservoirs in the province. Under the control of the heterogeneous mechanical properties of coal seams and the uneven distribution of tectonic stress fields, the phenomenon of stratification in tectonic coal is more prevalent. Taking the No. 11 coal seam in the Dahebian syncline of the Liupanshui Coalfield as an example, isothermal adsorption, mercury intrusion, low-temperature liquid nitrogen adsorption, and low-temperature CO₂ adsorption experiments were conducted to study the physical properties of each stratified reservoir. The formation mechanism of tectonic coal stratification in thick coal seams and the CBM enrichment pattern were discussed. The adaptability and applicability of exploration and development technologies for CBM in thick coal seams with complex coal structures were compared. The results showed that:1） The average thickness of the No. 11 coal seam in the Dahebian syncline was 4.48 m, and the formation of thick coal seams was the result of a balance between basin subsidence rates and sedimentary supply. Under subsequent compressional and thrust tectonic activities, the No. 11 coal seam underwent compression, fracturing, and even interlayer sliding, leading to the development of stratification in tectonic coal. Stress was concentrated in the middle stratification, where the mechanical properties of the coal were weaker. 2） The No. 11 coal seam exhibited a “sandwich” structure in the vertical direction, consisting of primary structural coal on top, mylonitic coal in the middle, and fragmented coal at the bottom. 3） The middle coal reservoir had the highest proportion of micropores and the strongest adsorption capacity. The Langmuir volume of maximum adsorption followed the trend: middle stratification（16.55 cm³/g） > lower stratification（14.69 cm³/g） > upper stratification（13.96 cm³/g）. 4） The No. 11 coal seam in the study area formed a lithology-fault-hydraulic seal gas reservoir. Based on the stratified characteristics of the coal structure, three different development technology routes were compared, and the most applicable direction for CBM development was identified as constructing cavities in the soft stratification of tectonic coal using horizontal wells to achieve pressure relief and CBM extraction.

Liquid CO₂ phase transition fracturing（LCPTF） technology is a novel water-free fracturing technique that can enhance coalbed methane recovery. To study the changes in coal adsorption characteristics before and after CO₂ phase transition fracturing, the No. 3 coal seam from the Yuwu coal mine was selected for experimentation. High-pressure mercury intrusion, low-temperature liquid nitrogen adsorption experiments, and CH₄ isothermal adsorption tests were conducted to analyze the impact of liquid CO₂ phase transition fracturing on coal adsorption. The results showed that after liquid CO₂ phase transition fracturing, the pore volume and specific surface area of adsorption pores in coal decreased; the specific surface area of seepage pores decreased while the pore volume of seepage pores increased. The liquid CO₂ phase transition fracturing technique could influence the change in the Langmuir adsorption constant of coal by altering the pore structure. After liquid CO₂ phase transition fracturing, the Langmuir adsorption constant “a” value decreased and the “b” value increased, indicating that the fracturing process reduced the coal’s adsorption capacity and enhanced the desorption rate. This study provides theoretical guidance for the improvement and optimization of liquid CO₂ phase transition fracturing technology for field applications.

Injecting CO₂ into depleted gas reservoirs can simultaneously achieve enhanced oil recovery and CO₂ geological storage, offering broad application prospects under the "dual carbon" background. Currently, CO₂-EGR（CO₂ enhanced gas recovery） is still largely in the theoretical research phase. To address the unclear mechanisms, this review summarizes the mechanisms of CO₂-EGR in different gas reservoirs. For conventional gas reservoirs, the mechanisms include pressure restoration and displacement effects, gravity segregation, viscosity-difference-assisted displacement, and dissolution-enhanced reservoir modification. For condensate gas reservoirs, pressure-maintained production is possible, along with viscosity reduction, dissolution expansion, and extraction-deblocking effects. For shale gas, coalbed methane, and tight gas reservoirs, the adsorption displacement effect is more significant. In water-bearing gas reservoirs, injecting CO₂ can effectively inhibit water invasion. The contributions of each enhanced recovery mechanism to different types of gas reservoirs vary. CO₂-EGR has been proven feasible at the theoretical level, but to achieve field application, further breakthroughs are needed in several areas, including gas phase characteristics of mixed gases, diffusion and gas mixing mechanisms, enhanced recovery potential evaluation, and characterization of enhanced recovery mechanisms. Research shows that injecting CO₂ into depleted gas reservoirs can restore formation pressure and replenish formation energy. Due to physical property differences, a stable displacement process is formed, achieving enhanced recovery under the combined action of multiple mechanisms. It is a highly promising method for increasing production.

Under the “Dual Carbon” goals, achieving a green and low-carbon transformation in offshore oil and gas has become a significant challenge for enterprises. Based on an analysis of the current status of low-carbon development in the domestic and international oil and gas industries, and considering the characteristics of offshore oil and gas development in China, this study first examines the main measures and technologies adopted for green and low-carbon transformation in recent years from three aspects: establishing standards and source intensity analysis to strengthen source control, implementing clean energy substitution and energy efficiency improvement for process management, and end-of-pipe management through CO₂ geological storage, CO₂-EOR（Enhanced Oil Recovery）, and CO₂ hydrate storage. The emissions reduction effectiveness of various low-carbon technologies is clarified. Secondly, by analyzing the development level and roadmap of each technology, the study forecasts emissions reduction contributions of source carbon control, process management, and end-of-pipe storage technologies, and explores a low-carbon transformation pathway for offshore oil and gas to achieve carbon neutrality by 2050. Finally, the study proposes future directions for low-carbon development in offshore oil and gas, including collaboration between marine oil and gas and new energy, construction of new offshore oil and gas power systems, digital and intelligent offshore oil and gas development, large-scale offshore CCUS（Carbon Capture, Utilization, and Storage）, and marine carbon sinks. The findings can serve as a reference for the low-carbon development pathway of offshore oil and gas and provide insights for the green and low-carbon transformation of energy enterprises.

The desorption production patterns of deep coalbed methane（CBM） vertical cluster wells, as well as the transition timing between free gas and desorbed gas, remain unclear. The dominant factors causing productivity differences are still uncertain, which hinders productivity improvement. To further evaluate the primary factors controlling productivity, a new method for assessing productivity-influencing factors was developed, based on the production dynamic parameters of 36 vertical cluster wells and using neural networks to predict bottom-hole flowing pressure. This method centered on the initial meter gas production index and integrated multiple machine-learning algorithms. The results showed that: 1） The Beggs & Bill model and Gray model exhibited poor applicability for predicting the bottom-hole flowing pressure of deep CBM wells, while the single-phase gas model demonstrated reduced overall error as water production declined. Predictions using the neural network method were more accurate, with a relative error of less than 10% compared to measured values. 2） Using Kendall's tau-b correlation analysis, the discrete dominant factor was identified as the microstructural position, primarily located in uplifted positive structural zones, with the secondary factor being fracture development, categorized mainly as “well-developed” or “developed.” 3） By combining lasso regression-random forest- decision tree algorithm to iteratively eliminate irrelevant factors, the continuous dominant factors influencing productivity were ranked in descending order as: ash content, average construction discharge rate, total sand volume pumped, flowback rate at gas breakthrough, net pay thickness, acoustic travel time, gamma ray log value, average construction pressure, percentage of 100-mesh sand, and average gas measurement value. Engineering factors were found to have a significant impact on gas well productivity and cannot be overlooked. This method leverages the advantages of multiple machine-learning algorithms, demonstrating strong operability and improving the accuracy of CBM dynamic predictions. It aids in optimizing fracturing design parameters and provides a scientific basis for enhancing post-fracturing productivity in CBM wells.