The elastic two-phase method, also known as the pseudo-steady-state method or reservoir limit testing method, is a pivotal dynamic technique for estimating the original gas in place（OGIP）in well-controlled scenarios. This method is primarily employed in the initial testing of gas wells and for the OGIP assessment in varied lithologies, fault blocks, and fracture types of gas reservoirs. Since 1994, the pressure squared variant of this method has been recognized in the Chinese national oil and gas industry standards across four editions: SY/T 6098—1994，SY/T 6098—2000，SY/T 6098—2010，SY/T 6098—2022. This method, based on the pressure squared calculation, offers a robust approximation compared to its pseudo-pressure counterpart. The theoretical derivation of the elastic two-phase equation for pseudo-pressure, originally proposed by AL-HUSSAINY（1966）, and further simplified using WATTENBARGER's（1968）study on the relationship between μ_gZ and p, allows for representations using both pressure to the first and second powers. Notably, while the pressure to the first power method tends to under-estimate OGIP, the pressure squared method is inclined to over-estimate, as evidenced by practical applications. Currently, there is a lack of substantial literature on the pseudo-pressure elastic two-phase method both domestically and internationally.

The transition from depletion mining to gas flooding in deep low permeability condensate gas reservoirs poses significant adaptability challenges. To address these, a series of evaluation studies were conducted using the Pressure-Volume-Temperature（PVT）analyzer, long core displacement physical simulation technology, and numerical simulation calculations. This research specifically examines the impacts of CO₂ injection, natural gas（associated gas or pure CH₄）, and nitrogen（N₂）on the high-pressure physical properties of condensate gas systems and their potential to improve condensate oil recovery. Comparative analyses reveal that CO₂, due to its high solubility and favorable gas-oil dissolution ratio in condensate oil, significantly reduces the saturation pressure and dew-point pressure of condensate gas reservoirs, thereby offering the most substantial improvement in oil recovery rates. Further optimization studies using long core physical simulation technology focused on injection timing, modes, and rates for CO₂ flooding. It was determined that pulsed gas injection strategies are particularly effective when implemented above the dew-point pressure. These findings provide essential data to support the formulation of technical policies and field plans for gas injection development in such challenging reservoir conditions.

Shale oil reservoirs present complex pore structures and ultra-low permeability, making the evaluation of flow capacity in both the reservoir matrix and various fracture types after fracturing crucial for developing effective work systems. In this study, the Brazilian splitting method was utilized to simulate different fracture morphologies. We constructed a set of methods for evaluating matrix and fracture flow capacity based on nuclear magnetic resonance（NMR）technology. This evaluation was conducted on shale cores from the second member of Funing Formation of Gaoyou Sag in Subei Basin（referred to as the Fu-2 member）. Techniques including NMR, Brazilian fracturing, and high-pressure saturation were applied to develop these evaluation methods. The experimental results indicate that the minimum flow pore size of the shale reservoirs is 10 nm. Under stress conditions, the flow pattern exhibits a two-stage equation: nonlinear and linear. Factors affecting the fracture system’s conductivity include crack type, opening degree, stress magnitude, and driving pressure difference. Higher stress levels result in greater permeability loss, reaching up to 95%. The more complex the fracture network and the larger the opening, the greater the permeability loss. During production, it is essential to manage the pressure difference between the formation fluid and the bottomhole flow based on the crack development and effective stress characteristics of the overlying strata to ensure stable oil well production and uniform pressure propagation. For the shale oil in Fu-2 member of Gaoyou Sag, it is recommended to maintain an effective stress range of 7 MPa to 10 MPa and a flow pressure difference range of 10 MPa to 15 MPa as optimal for pumping or reservoir energy replenishment. These research findings significantly contribute to the theoretical understanding and practical application of the shale seepage mechanism.

The exploration of Well-Fuye-10 in the Dongyuemiao section has provided valuable characteristic parameters of typical continental shale, revealing a reservoir with well-developed mesopores and macropores and significant heterogeneity. The predominant pore sizes are around 10 nm. Notably, deviations in the critical parameters of the confined fluids alter the condensate gas properties within these nanopores, differentiating them from conventional laboratory results. This study combines indoor phase state experiments, critical parameter migration calculations, and numerical simulations of confined fluids to analyze the phase state characteristics and extraction properties of shale condensate gas. The findings elucidate the phase state transformation and extraction dynamics of the condensate gas. Adjustments in the calculations for condensate gas phase characteristics to account for critical parameter offsets indicate that as pore radius decreases, there is a corresponding reduction in critical temperature and pressure of the system components. This results in a contraction of the phase diagram towards the lower left, a decrease in dew point pressure, reduced gas phase viscosity, an increase in deviation factor, and a gradual decrease in retrograde condensate saturation. Additionally, a mechanism model was employed to assess the impact of critical parameter shifts on depletion extraction effectiveness. Results demonstrate that while the recovery rate of natural gas remains relatively unchanged, the recovery rate of condensate oil shows a significant increase, rising by 9.93% as the pore radius decreases to 10 nm. These insights offer pivotal guidance for the development of shale condensate gas reservoirs, particularly in managing the unique phase behavior and optimizing recovery strategies.

The deployment of horizontal well groups for shale oil development represents an innovative approach to fracturing, addressing the constraints observed in single horizontal wells. This study focuses on the fracturing dynamics within groups of horizontal wells, where the interplay of multiple wells and artificial fractures introduces complex variations in stress around the fractures and the in-situ stress distribution between wells. Such complexities significantly influence the morphology of fracture propagation. A comprehensive investigation into the stress field dynamics under various fracturing methods in horizontal well groups was conducted using a hydraulic fracturing numerical model. This research is crucial for manipulating fracture morphology and enhancing fracture complexity. The study systematically explored the stress distribution during the shale oil reservoir fracturing reconstruction, analyzed fracture morphologies, and quantitatively assessed the fracturing outcomes. Key findings include: ① Synchronous fracturing effectively alters inter-well ground stress, with the staggered pattern inducing a 24% higher stress compared to the opposite pattern, thereby influencing the direction and reversal of ground stress under identical well spacing. ② Staggered layout exhibit superior shape and fracturing effects than those under the opposite layout, significantly increasing the length, width, surface area, and volume of fractures by 4.6% and 21.1%, respectively. ③ Zipper fracturing enhances fracture dimensions more effectively than synchronous fracturing, increasing the total surface area and volume of the fractures by 1.3% and 0.1%, respectively.

The efficient evaluation of the oil properties, capabilities, and compressibility of reservoirs using conventional logging data is essential for the large-scale development of shale oil in northern Jiangsu. Utilizing conventional logging data alongside core experiment data, this study develops a robust model to calculate several critical reservoir characteristics. These include total organic carbon content, effective porosity, bedding fracture density, and mineral composition content. The model employs a variety of mathematical methodologies such as physical concept analysis, optimization, fitting, and both forward and backward numerical simulations. Furthermore, this research classifies the sedimentary structure and lithofacies of the reservoir. Results indicate that the shale within the second member of Funing Formation in Qintong Sag predominantly consists of organic-rich layered/laminated mudstone and block mudstone. Among these, the layered or laminated mudstone represents the favorable lithofacies, intersecting vertically with non-favorable rock types. The “sweet spot” layers identified by the model correlate well with the layers analyzed using specialized logging techniques, and field applications have yielded positive outcomes. This technology has been successfully applied in identifying geological and engineering “sweet spots” within the shale oil reservoirs of the Subei Basin, offering significant guidance for the strategic development of shale oil in the region.

Significant progress has been made in the exploration and development of shale gas within the Lower Silurian Longmaxi formation of the thrust-nappe tectonic belt in the Nanchuan block. By the end of 2022, this area saw the drilling of 170 wells, achieving a cumulative gas production of 51.6 billion cubic meters. As development has progressed, the focus has shifted from the structurally simpler main area to the more complex peripheral regions. Previously, the structural interpretation of the Nanchuan block primarily identified faulted anticlines constrained by major reverse faults, without adequately addressing the structural deformation across the entire belt. Recent evaluations have revealed significant discrepancies between well data and seismic interpretations, leading to numerous drilling failures and hindering further shale gas development. This study revisits these challenges using advanced drilling insights and forward modeling analysis. It suggests that the apparent thrust faults with large displacements and high angles in the seismic profiles of the Longmaxi formation are likely structural misinterpretations, rather than true geological features. Instead, the fault areas are characterized by high-steep knee-fold structures with smaller fault distances and steeply inclined strata. By integrating high and steep structural illusion analysis with fault-related fold theory, the well-seismic joint structural modeling has been refined to better represent the structural characteristics of the Longmaxi formation gas reservoir in the Nanchuan block. This improved understanding has identified the high-steep knee fold zone as a potentially favorable target for further exploration and development, supported by positive results from five recently deployed evaluation well groups.

Distinct sedimentary environments lead to notable disparities between marine-continental transitional shale and purely marine shale. This study develops a numerical model to evaluate the productivity of horizontal wells in vertically multi-lithologic superimposed reservoirs, focusing on the marine-continental transitional shale reservoirs at the eastern margin of the Ordos Basin. The model analyses the dynamic characteristics of single-stage gas well production under various lithologic combination modes. It particularly investigates key parameters such as coal seam permeability, the superposition relationships of reservoirs, and the impact of the production system on output characteristics. The findings indicate that: ① In the early stages of combined extraction from coal-rich shale reservoirs, both gas and water are produced simultaneously. The gas primarily originates from the free gas in the sandstone and shale reservoirs, while the water is predominantly sourced from fracturing fluid and coal seam water. Notably, higher coal seam permeability correlates with increased cumulative gas and water production. ② The optimal spatial stacking sequence for combined layer mining in coal-bearing superimposed reservoirs is identified as page-sand-coal. This sequence minimizes the interference of coal seam water production on the overall mining process. ③ The production from coal seams exhibits significant stress sensitivity, impacting overall gas output.

This study addresses the challenges presented by the reservoirs in He-8 member in SD block of Ordos Basin, characterized by low porosity, low permeability, strong heterogeneity, and conventional fracturing fracture shapes. Utilizing fracture mechanics, this research examines the interactions between temporarily blocked fractures and the initial fracture throughout their entire contact period. Key considerations include fluid pressure drop within the fracture and the rock mechanics parameters of the reservoirs in He-8 member. The study systematically analyzes the influence of various parameters such as fracture strike, well deviation angle, and azimuth angle on fracturing fracture parameters. Notable findings include: Fracturing pressure decreases with increasing well deviation angle and azimuth angle. The initiation angle diminishes as well inclination increases, reaching a nadir before decreasing further with azimuth angle adjustments. Using artificial cement samples and a large-scale experimental system with realistic triaxial physical models, the study simulates the initiation, turning, and propagation behaviors of new fractures in temporary plugging fracturing. The behaviors of initiation, steering and extension of newly formed fractures at different well inclination and azimuth angles were evaluated along with the parameters such as fracture initiation pressure and fracture stimulated area. The experimental results reveal: Both initial and secondary fracture pressures tend to decrease as well inclination increases, making fractures more prone to turning and significantly enlarging the modifiable area. With consistent trap inclination, fracture initiation pressure decreases and the fracture modification area expands as bore azimuth increases. Fractures resulting from azimuthal 90° spiral perforation exhibit greater complexity compared to those from azimuthal 0° spiral perforation. Additionally, fixed surface perforation techniques can regulate fracture pressure and the initial fracture positions in horizontal wells, recommending a perforation angle between 75° and 90°. These findings offer valuable insights for the design of temporary plugs and fracturing strategies in low-permeability tight sandstone oil and gas reservoirs.

This study explores oil-water imbibition dynamics in rock samples of tight sandstone with similar physical properties using a novel NMR signal calibration method. This method can translate the total NMR signal output into oil volume via a regression model, offering enhanced convenience and accuracy compared to traditional approaches. The imbibition process is characterized by two distinct phases: a rapid imbibition stage and a stable imbibition stage. Optimal imbibition times were identified as approximately 68 hours for oil from coal samples and 188 hours for tight oil samples. When imbibition times are sufficient, the recovery ratios for oil from coal and tight oil are comparable. However, with insufficient imbibition time, the recovery ratio for oil from coal is lower than that for tight oil. Within the same stratigraphic layer, samples with identical viscosity exhibit similar imbibition dynamics, with tight oil samples reaching the stable stage more quickly than oil from coal samples. The pivotal radius distinguishing large and small pores is established at 0.5 μm. In low-viscosity crude oil samples, small pores significantly dominate the imbibition process, contributing 83.93% to the recovery, while large pores contribute only 16.07%. The overall mobilization of crude oil is low at 8.50%, frequently resulting in the formation of water locks. In contrast, tight oil samples show a more balanced contribution across all pore sizes during the soaking period. The average utilization ratios of crude oil are 14.82% in small pores and 29.82% in large pores.

Recent exploration within the second member of Funing Formation（hereinafter referred to as Fu-2 member）in Gaoyou Sag of Subei Basin has marked a significant advancement in the understanding of shale oil potential, highlighting its role in enhancing future reserves and production. This study focuses on Well-X1, utilizing a comprehensive suite of analytical techniques, including imaging logging, core examinations, and micro thin section analysis, to investigate the fracture characteristics across different scales. Additionally, statistical analysis of fracture parameters and isotopic studies of stable carbon and oxygen in fracture fillings provide insights into the formation stages of the fracture. The research delves into the dynamic evolution of fractures and their influence on the accumulation of shale oil and gas. Key findings indicate that structural fractures, predominantly brittle shear and tensile shear fractures, are prevalent and characterized by substantial length and excellent transverse connectivity. Non-structural fractures, including bedding fractures and calcite veins, exhibit some areas of abnormal development. These natural fractures have undergone modifications during later stages, with incompletely filled fractures, pore spaces from dissolved fracture fillers, overpressure bedding fractures, and micro fractures identified as particularly favorable reservoir spaces for shale oil. The results of this study not only shed light on the complex fracture dynamics within the shale but also provide a robust theoretical foundation for evaluating deep shale oil prospects in Gaoyou Sag.

This study evaluates the unconventional oil and gas exploration potential of the Cenozoic residual basins in southern Jiangsu, focusing on Jintan Basin. Utilizing a range of data sources, including drilling records, core analyses, logging data, and laboratory tests from Well-J9, we extensively analyzed the geological features of the fourth member of Funing Formation. These analyses encompass rock mineral composition, sedimentary characteristics, organic geochemical properties, and reservoir qualities. Findings indicate that the fourth member of Funing Formation was deposited in a semi-closed to closed saline sedimentary environment, predominantly characterized by shallow to semi-deep lakes. This member is marked by substantial mud shale thickness（exceeding 250 m in deep concave zones）, low organic matter abundance（average total organic carbon（TOC）of 1.02%）, and a moderate degree of thermal evolution（vitrinite reflectance（R_o）ranging from 0.81% to 0.85%）, providing a fundamental basis for shale oil hydrocarbon generation. Additionally, the presence of fractures and porous shale reservoir spaces, coupled with a high content of brittle minerals, suggests favorable conditions for the development of complex fracture networks during subsequent fracturing interventions. Considering the oil and gas shows in existing boreholes, it is posited that the fourth member of Funing Formation, particularly near the Maoshan tectonic push-over zone, holds medium to low maturity shale oil exploration potential in southern Jiangsu.

The lithofacies of shale oil within the Dongying Sag of the Jiyang Depression are distinguished by their complex lithology, strong heterogeneity, and marked regional distribution variances. Current logging methods inadequately identify and evaluate the lithofacial characteristics of shale oil in this region. This study delves into the lithofacies characteristics of the upper submember of Chunhuazhen Formation of the fourth member of the Shahejie Formation in Dongying Sag, employing core calibration logging integrated with core, thin section, experimental analysis, and testing data. Utilizing the “three terminal elements and four elements” shale lithofacies partitioning scheme as a guiding principle, this research selects responsive characteristics of different lithofacies logging and sensitive parameter logging curves to develop an appropriate shale oil logging lithofacies partitioning method. The approach combines stratification, clustering through Agglomerative Hierarchical Clustering（AHC）, Fisher discriminant analysis, wavelet frequency extraction, and genetic optimization neural networks to discern the rock composition, sedimentary structure, rock texture, and organic matter content of different lithofacies. This methodology addresses the challenges posed by complex lithology, limited logging resolution, incomplete special logging data, and inadequate Total Organic Carbon（TOC）model accuracy. By identifying the “four characteristics” of lithofacies, the study establishes a quantitative logging identification method and technology for shale oil lithofacies in Dongying Sag, pinpointing concentrated lithofacies segments. The findings provide a critical geological basis for the large-scale exploration and development of shale oil in the region.

Deep shale gas reserves in southern Sichuan represent a significant opportunity for augmenting China's natural gas reserves and production. One critical factor influencing the permeability and productivity of individual wells in these deep shale gas reservoirs is fault connectivity. Previous research has primarily focused on fault morphology and combination styles, with little systematic quantitative assessment of fault connectivity. This study targets the Wufeng Formation reservoir in the central Luzhou section of the southern Sichuan Basin, initiating a detailed analysis of the fault network structure and connectivity using multiple faults as reference points. Findings indicate that faults in the Wufeng Formation of the central Luzhou area are well-developed, with an average of 1.12 connection points per branch network. These networks potentially form highly permeable channels favorable for shale gas transport. The central and southern parts of the study area exhibit higher fault dispersion, fault length dispersion, and fault density, which contribute to a greater number of connecting nodes and branches. This enhanced connectivity is conducive to the development of high-production wells. The connectivity assessment results from these regions are superior to other studied areas, indicating notable potential for high-yield well development in the Wufeng Formation.

Located in the complex structural area of the southeastern margin of Sichuan Basin, Nanchuan area is characterized by the prevalent development of low-level reverse faults. This study employs a combination of regional structural analysis and fine structural interpretation to explore the formation mechanisms and distribution patterns of these reverse faults. Utilizing seismic fracture-attribute prediction, drilling, fracturing, and gas test data, this research analyzes the impact of low-level reverse faults on shale reservoir performance, preservation conditions, and fracturing transformation, with a specific focus on the Pingqiao Dong-1 Fault. Findings indicate that the formation of lower-level reverse faults in the Nanchuan area, predominantly oriented NE and NNE with a small scale, was mainly influenced by the long-distance transmission of intracontinental orogeny from the Jiangnan-Xuefeng uplift and changes in the regional compressional tectonic stress field during the Middle to Late Yanshan periods. The Pingqiao Dong-1 Fault notably enhances reservoir properties through the presence of abundant natural fractures without compromising the preservation conditions. This fault alignment facilitates hydraulic fracturing processes to form complex fracture networks, leading to high production from individual wells. Further, exploration and development practices demonstrate that shale gas wells located within 400 meters of lower-level reverse faults achieve high yields, identifying these vicinities as favorable zones for target optimization and well deployment. The results from this study offer valuable insights and guidance for the exploration and development of shale gas in structurally complex regions.

Reservoir evaluation serves as a foundational aspect in the development of tight sandstone gas reservoirs, with the accuracy of these evaluations critically influencing potential development analyses. The selection of evaluation methodologies is pivotal in ensuring the reliability of development index predictions and the scientific integrity of adjustments and deployment strategies. Addressing the challenges inherent in evaluating tight sandstone gas reservoirs—such as numerous influencing factors, ambiguous controlling factors, unknown parameter sensitivity, and unquantified evaluation indices—this study develops a quantitative analysis model using the analytic hierarchy process（AHP）. This approach simplifies complex issues and quantifies qualitative aspects, facilitating a more structured evaluation. Utilizing geophysical data, logging interpretation, and geological fundamentals as criterion indices, the study constructs a judgment matrix to establish a quantitative evaluation model. This involves determining index weights, conducting consistency tests, and deriving a weight vector. The model is then validated through correlation analysis between the recoverable reserves, open flow, and evaluation values of actual wells. Findings demonstrate the method's reliability and further refine the criteria for reservoir classification. The evaluation indices defined through this research enhance the understanding of “sweet spots” for tight sandstone gas reservoir development within the same region, improve the precision of reservoir prediction, and aid in the strategic deployment of development activities. Ultimately, this study offers valuable insights and a methodological framework for the efficient development of similar gas reservoirs.

At present Sulige Gas Field holds the distinction of being the largest in terms of natural gas reserves and annual production among tight sandstone gas reservoirs in China. However, as development progresses, there is a noticeable decline in the quality of gas field reserves and an increasing fragmentation of untapped reserves, escalating the uncertainties surrounding future development. This study builds upon a deepened geological and gas reservoir engineering comprehension acquired during earlier phases of gas field development. It methodically identifies the factors influencing the advantageous development of the gas field and formulates technical countermeasures to ensure its sustainable development. Key findings from the research include: ① An empirical analysis, centered on economic production, evaluates the economic benefits of each block within the gas field. This model assesses the current benefit status and directs future overall development strategies. ② To foster the continued advancement of the tight gas industry within the field, the study evaluates the benefits of individual blocks and explores supportive measures for effective development. These measures include classified management and specific technical strategies, derived from geological and gas reservoir engineering perspectives. This approach culminates in the formulation of technical countermeasures aimed at enhancing the effective development of Sulige Gas Field, thereby ensuring its continued economic viability.

The fifth member of Xujiahe Formation（Xu-5 member）in Ziyang-Dongfengchang Block of central Sichuan is characterized by low porosity, low permeability, and strong heterogeneity. This study aims to develop a reliable logging interpretation model and to establish the lower limits of effective reservoirs using well logging, core, and gas testing data. The research focuses on the correlation among four key properties: lithology, physical properties, electrical properties, and gas content following core homing and log normalization. A significant correlation exists between the lithology, physical properties, electrical properties, and gas content. Gamma ray readings increase as particle size decreases, aiding in sediment characterization. Resistivity curves effectively identify calcium-bearing sandstones. A strong positive correlation exists between sonic differential time and porosity. Gas content is positively correlated with physical properties, indicating richer gas zones correlate with specific log signatures. Based on these relationships, a comprehensive interpretation model for porosity, permeability, and water saturation was established, alongside criteria for reservoir identification. The application of these findings in production scenarios demonstrates consistency between reservoir logging, gas testing, and experimental results with the established four-properties relationship diagram. The calculated physical property parameters from the logging interpretation model align well with core test outcomes, and gas production profile testing corroborates the reservoir identification criteria. This study provides critical technical support for designing testing schemes and optimizing resource extraction.

The exploration and development of coalbed methane（CBM）in the Permian Longtan Formation in south Chongqing is in the initial stage. In order to reveal the general geological conditions of coalbed methane in the coal seam C₂₅, by the experimental and geological data obtained from the coal mines and coalbed methane drilling, the geological characteristics such as coal rock and coal quality, coal pore penetration and gas content have been analyzed. The results show that the C₂₅ coalbed methane of Longtan Formation of Permian in the study area is characterized by “stable development, relatively large thickness, low pore permeability, high metamorphism and high gas content”. The development of the coal seam C₂₅ is stable throughout the whole area, showing the trend of “thick in the north and thin in the south”, and the thickness in the northern part of the coalbed is generally larger than 1.5 m. The coal quality belongs to semi-bright coal. The content of vitrinite in the organic component is 51.7%~72.2%; the vitrinite reflectance ranges from 1.8%~2.2%, and the metamorphism degree is high-over maturity. The porosity and permeability of the coal rock are relatively low, with the porosity ranging from 3.46%~8.46% and the permeability of mostly lower than 0.01×10^-3 μm². The gas content of the coal bed is high, generally more than 10.0 m³/t; meanwhile, the top and bottom plates of the coal bed are good sealing layers. Based on the production of Q1 and Y2, it is believed that the coal seam C₂₅ of Permian Longtan Formation in south Chongqing area has good geological conditions for CBM exploration and development.

Nearly abandoned heavy oil reservoirs present significant challenges for effective reserve utilization using conventional development methods. In-situ combustion technology emerges as a promising solution to enhance recovery from such reservoirs, although its widespread adoption is hindered by high investment costs and economic inefficiencies. This study employs a break-even model and sensitivity analysis within a volume-cost-benefit framework to explore the equilibrium between oil production costs and revenues under varying oil price scenarios from a multidimensional operational perspective. This approach clarifies the critical economic indices of fire-flooding operations and aims to optimize production operations and decision-making effectiveness. The findings reveal significant gaps in pre- and post-operation understanding of the reservoir, where inputs often surpass outputs, coupled with a lack of clear control strategies. These factors contribute to the low cost-effectiveness of in-situ combustion and insufficient grasp of sustained development and operational risks, ultimately impacting investment decisions in reservoir development. The study not only directs improvements in operational efficiency for in-situ combustion but also offers technical support and introduces new management strategies for the effective development of nearly abandoned heavy oil reservoirs.

Significant advancements in deep Coal Bed Methane（CBM）development have been achieved through the adoption of reservoir reforming technology, characterized by the utilization of large sand volumes and large fracturing fluid volumes in Yanchuannan CBM Gas Field of Ordos Basin. This study conducts field tests on coal reservoirs with varying fracturing scales to explore the patterns of fracture expansion post-hydraulic fracturing and assesses the resultant reservoir reform areas. The analysis identifies distinct fracture patterns across different types of gas wells and fracturing scales, examines the impacts on gas production post-commissioning, and develops fracturing technology tailored to Yanchuannan CBM Gas Field. Multiple moderate-scale fracturing interventions in inefficient old wells and large-scale fracturing in new wells effectively extend fracture lengths and expand the area of reservoir reconstruction. However, the morphology of the resulting fracture networks varies significantly. Inefficient old wells subjected to multiple medium-scale fracturing develop a “rose-shaped” fracture network with primary and secondary fractures, whereas new wells exhibit a “long elliptical” fracture pattern. Notably, the use of a single ultra-large-scale fracturing fluid achieves greater efficiency, producing longer half-length fractures and larger renovation areas under the same scale. The fracture half-length and renovation area demonstrate a logarithmic increase with the frequency of fracturing, significantly enhancing the efficiency. Economic evaluations of trial production confirm that two large-scale fracturing operations are economically viable, providing a foundation for future well network deployment. Fracturing equipment powered by diesel struggles to adapt to continuous operations at scaled-up levels, suggesting that electric-driven fracturing devices present a reliable alternative for the sustainable development of integrated CBM gas fields. These insights not only enhance understanding of fracture dynamics in deep CBM reservoirs but also guide the optimization of fracturing strategies and equipment choices for future developments.