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.

The Yanchang Formation in the Ordos Basin has deposited a set of mudshales and fine-grained sandy rocks, rich in shale oil resources, with an estimated resource potential exceeding billions of tons. However, shale oil reservoirs exhibit poor mobility, shallow burial depths, the development of bedding, fractures, and faults in horizontal sections, and unknown fracture propagation patterns, making volumetric fracturing challenging. To address this, cement-encased cores of full-diameter tight sandstone-mudstone and shale from the sublayer in the seventh member of the Yanchang Formation (Chang 7) were used in actual triaxial hydraulic fracturing physical model experiments. These experiments revealed hydraulic fracture morphologies and the fracture propagation mechanism under weak stress fields in shale oil reservoirs. The experiments found that shale oil reservoirs had tight layered structures and weak bonding between rock grains, causing fracturing fluid to easily infiltrate along bedding planes. When the difference between vertical stress and minimum horizontal principal stress was less than 2 MPa, hydraulic fractures predominantly formed horizontal fractures, with the fluid primarily infiltrating along bedding planes or horizontal natural fractures. When this stress difference increased to 7 MPa, vertical cross-layer fractures appeared, forming localized steps that eventually became captured by weakly bonded bedding planes, propagating horizontally along the layers. For fracturing operations, regions with a larger difference between vertical stress and minimum horizontal principal stress, such as wellheads at hilltops, are preferred. This facilitates vertical fracture propagation, improves volumetric fracturing effectiveness in reservoirs, enhances shale oil production, and increases economic benefits.

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.

In the deep shale reservoirs of the southern Sichuan Basin, the development of fractures directly impacts the engineering construction and effective production of horizontal shale gas wells. Taking the shale cores in the Wufeng-Longmaxi Formation in the southern Sichuan Basin as a case study, rock physics experiments and numerical simulations were conducted to obtain the acoustic response characteristics of fractures at different scales, orientations, and fillings. The study analyzed the factors affecting the attenuation capability of acoustic waves on fractures and established a set of fracture identification and effectiveness evaluation methods for horizontal shale gas wells. The results showed that the amplitude attenuation of P-waves, S-waves, and Stoneley waves was influenced by both the fracture dip angle and fracture width, with attenuation capacity exponentially increasing with fracture width and decreasing with the dip angle. Stoneley waves were sensitive to fluid-filled fractures and could be used to identify and evaluate gas-bearing and water-bearing effective fractures. P-waves and dipole S-waves were sensitive to calcite-filled fractures, able to identify and evaluate ineffective calcite-filled fractures. The fracture identification results based on reflected wave imaging were consistent with the results obtained from imaging logging and core identification, verifying the reliability of the effectiveness evaluation method. The research findings were applied to the actual data from horizontal shale gas wells, thoroughly evaluating the fracture risk positions in horizontal shale gas wells and effectively ensuring the optimized and tailored design for fracturing segments.

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.

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.

With technological advancements, fibers now serve roles beyond proppant backflow prevention, including proppant transport, plugging, fracture morphology optimization, and other aspects, namely, fiber-network proppant fracturing technology. The fiber-based proppant transport and fiber temporary plugging technologies can effectively address issues currently faced by deep shale gas, such as proppant near-wellbore accumulation and insufficient temporary plugging effectiveness, thereby improving the effectiveness of volumetric fracturing stimulation. To this end, the study was conducted in a deep shale gas block in the southern Sichuan Basin, investigating fiber-based proppant transport and fiber temporary plugging mechanisms, as well as laboratory physical simulations to optimize and evaluate the performance of fiber materials. Based on the regional geological and engineering characteristics of the study area, fracturing software simulations were carried out to determine the hydraulic fracture width for deep shale gas. A field test plan was then developed, and the fracturing construction, flowback, plugging, and fracturing effectiveness of the test wells were monitored and evaluated. The research results indicated that fibers had strong proppant transport assistance and flexible bridging capabilities. By modifying the molecular structure of fiber materials and adding a certain amount of structural stabilizers, discontinuous cluster-like support structures can be formed, significantly enhancing the placement effect and conductivity of proppants. Based on fracture width simulation calculations, the hydraulic fracture width for deep shale gas is between 2 to 5 mm. By optimizing fiber types based on fracture width, proppant grain size, and concentration, full support of fractures can be achieved. Compared to conventional fracturing wells, the test wells with modified fiber + structural stabilizer for sand-carrying fracturing exhibited better production increase and proppant flowback prevention. Fibers can be used for temporary in-fracture plugging. During the construction process, the pressure response is evident, which may lead to excessively high pressure during subsequent operations, making proppant addition difficult. Optimizing the timing of fiber injection is beneficial for the subsequent overall sand addition process. Additionally, fibers can also be used to address the inter-well gas migration issue in deep shale gas wells by strengthening the temporary plugging of fracture openings and sealing natural fractures, thereby preventing further communication between hydraulic fractures and distant natural fractures. The study, based on the characteristics of deep shale reservoirs in the southern Sichuan Basin, has developed a set of performance indicators for fiber materials suitable for deep shale gas, including fiber length, stability, compatibility, and degradation rate. It also proposes a four-in-one fiber injection process and design method, focusing on “entry, distance, height, and prevention”. It provides strong support for the future economic development, technology optimization, and fracturing process adjustments of shale gas.

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.

During the development of middle and deep gas reservoirs in South Sichuan, conventional reservoir engineering methods—such as fracture propagation, stress-induced analysis, and numerical simulation—render productivity prediction of infilling wells laborious and ineffective in addressing variations in production capacity across different production stages, with stringent application conditions. In order to quickly and accurately predict the production capacity of infilling wells, this study classifies the “three-stage” declining trend observed in the production pressure curves of existing wells into: (1) A drastic decline period, regarded as the initial water production stage; (2) a rapid decline period; and (3) a slow decline period, both considered part of the later gas production stage. The Grey Wolf Optimizer(GWO) algorithm, a fast optimization algorithm with adaptive capabilities and an information feedback mechanism, is applied for hyperparameter optimization of the Long Short-term Memory (LSTM) neural network. Two stage-specific models were constructed, with the number of hidden layer neurons, dropout rate, and batch size determined by the optimal solutions obtained via GWO. The number of iterations was selected based on the loss curve and performance metric curve, while a linear warm-up strategy was used to dynamically adjust the learning rate, facilitating high-speed training and the formation of a staged productivity prediction model. Example studies show that the GWO-optimised LSTM neural network model achieves rapid convergence with a preset learning rate of 0.002 and 450 iterations, ultimately reaching a performance index of 0.923. Compared to the conventional LSTM neural network model, the average absolute errors during the early and later stages are reduced by 1.290 m³/d and 0.213 × 10⁴ m³/d, respectively. Compared with numerical simulation fitting results, the average absolute error in gas production prediction is reduced by 0.24 × 10⁴ m³/d. Therefore, the improved LSTM neural network model demonstrates excellent performance in capacity prediction across different production stages, and the stage-specific productivity variations in infilling wells within middle and deep shale gas reservoirs in South Sichuan. This provides a theoretical foundation for productivity prediction methods of infilling wells.

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.

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.

After 20 years of shale gas exploration and development, China has become the third country that achieves commercial shale gas production, following the United States and Canada. However, earlier exploration and development of the layer were limited to the Silurian Longmaxi Formation. With improved theoretical understanding of shale gas exploration, China has made exploration breakthroughs in Permian and Cambrian shales in recent years, demonstrating the great potential of shale gas in Sichuan Basin. Based on a review of the exploration history of shale gas in the two major marine phases—Silurian Longmaxi Formation and Cambrian Qiongzhusi Formation, this study summarizes the three phases of shale gas exploration: research and exploration (2000-2011), discovery and production (2011-2022), and multi-layer breakthroughs (2022-present). This study thoroughly analyzes the process of two theoretical innovations and paradigm shifts in the exploration and research of marine shale gas in Sichuan Basin. (1) After comparing the formation conditions and exploration and development characteristics of shale gas between China and the United States, Chinese researchers abandoned the simple replication of North American experience, and highlighted the critical role of preservation conditions based on the evolution characteristics of China’s multi-phase tectonics. This completed the first paradigm shift and achieved major exploration breakthroughs in the Silurian Longmaxi Formation. (2) Research on the characteristics of low-organic matter and inorganic pores was enhanced. Traditional theories of enrichment and reservoir formation were developed and improved, and a “migration+in situ” reservoir formation mode was established. This completed the second paradigm shift and led to exploration breakthroughs in Cambrian Qiongzhusi Formation. Recent research breakthroughs in low-organic shale, inorganic pores, and other aspects have expanded both the scope and depth of shale gas exploration, leading to a multi-layer exploration pattern of marine shale gas. It demonstrates broad exploration prospects and strategic value for national energy security. Based on a review of the exploration history and paradigm shifts from the Silurian to the Cambrian periods, as well as an analysis of the implications from major breakthroughs, this study reveals an exploration path of shale gas with Chinese characteristics, providing important references for future exploration and development of multi-layer and multi-field shale gas.

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.

Shale gas reservoirs are characterized by high compactness and significant heterogeneity, with naturally low production that necessitates hydraulic fracturing technology for enhanced productivity to achieve industrial gas flow. The key to evaluating the effectiveness of fracturing operations and optimizing process parameters lies in obtaining accurate fracture network parameters. Traditional fracture monitoring techniques, such as microseismic monitoring, are costly and cannot achieve full coverage monitoring of well areas. Numerical simulation prediction models require a large number of engineering geological parameters, leading to poor prediction effects for geological data that are incomplete or missing well sections. There is an urgent need for a new method that is economically efficient in obtaining fracture network parameters. To address this, a shale gas reservoir fracture network inversion method based on deep learning was proposed. The core of this method is to quantitatively analyze the fracturing curve characteristic parameters based on the site fracturing curve data, using strongly correlated indicators of fracture network parameters as inputs and microseismic monitoring fracture network parameters (including length, width, height, and volume) as target outputs. A back-propagation (BP) neural network inversion model was established to achieve accurate inversion of fracture network parameters. The model was trained and optimized using 450 fracturing curve segments from shale gas wells in western Chongqing, with the average relative error of fracture network parameter inversion results in the test set being below 15%, which verified the feasibility of this new method for inversion of shale gas reservoir fracture networks.

With the increasing difficulty in oil and gas development and insufficient replacement of resources, traditional development of oil and gas reservoirs faces multiple challenges, requiring intelligent analysis solutions for enhanced development efficiency. This study focused on the demand and application scenarios for efficient development in conventional oil and gas reservoirs and shale gas reservoirs and proposed an innovative intelligent technology for oil and gas development based on multi-model approaches. It enabled decision-making of production and efficiency allocation, comprehensive abnormal situation awareness, and intelligent balanced injection-production optimization. This effectively promoted the intelligent exploitation of reservoir resources, providing technical support for balanced injection-production and efficient development in multilayered complex waterflood reservoirs. A pressure prediction and capacity factor analysis technology for shale gas reservoirs was developed, along with an abnormality warning mechanism to push alerts about abnormal factors and their root causes. This achieved a transition from post-event analysis to early warning and pre-emptive intervention, thereby supporting the efficient development of gas reservoirs. Breakthroughs were made in establishing a multi-modal self-diagnosis and evaluation technology for oil wells, achieving intelligent diagnosis of pumping well operating conditions, self-diagnosis and intelligent evaluation of electric pumping well conditions, and real-time calculation of dynamic fluid levels in oil wells. These supported measure formulation, enabled refined management of oil wells, and made injection-production adjustments more timely and accurate, effectively improving the production time ratio of oil wells. The integrated technology application supported developing a new operational model featuring “comprehensive awareness, integrated coordination, early warning, and analysis and optimization” for the dynamic management and control of oil and gas reservoirs. These research technologies have been widely promoted among upstream companies of Sinopec, with practical application focusing on multi-model oil and gas development technologies. This study offers new ideas and technical approaches to address key challenges in the efficient development of oil and gas reservoirs, driving the digital and intelligent transformation of the oil and gas sector and facilitating the efficient and high-quality development of oil and gas fields.

To address the issue of interwell interference caused by adjacent well fracturing and development adjustments in shale gas reservoirs, existing dynamic evaluation methods for well groups based on single wells or those ignoring fracture network connectivity are inadequate. A well test analysis model for shale gas well groups, incorporating the connectivity of fracturing network, was developed based on a variable conductivity fracture model. By discretizing the fracture network, the model equation of multi-stage fracturing well groups was transformed into linear equations and the bottom-hole pressure solution of well groups was obtained. The bottom-hole pressure solution of the well groups was compared and validated using the finite volume numerical method. Typical characteristic curve diagrams of bottom-hole pressure, both with and without connected fractures, were established. Application examples of four wells on two platforms in the Fuling shale gas field were provided. The results showed that: ① Production wells had bilinear flow (1/4 stage), linear flow (1/2 stage), unsteady crossflow, and boundary quasi-steady flow stages, while non-production wells rarely had bilinear or linear flow stages. ②Under both connected and unconnected fractures, the bottom-hole pressure solution of the well group calculated by the finite volume numerical method was entirely consistent with that calculated by the method proposed in this paper. ③ The interpretation and evaluation results of measured data from four wells on two platforms in the Fuling shale gas field were consistent with field observations, verifying the reliability and practicality of the proposed method. The findings provide technical support for calculating shale gas reservoir parameters and fracturing parameters, and evaluating interwell connectivity.

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 Subei Basin is characterized by a complex structure and well-developed faults. The shale in the second member of the Funing Formation has relatively low organic matter abundance, with a total organic carbon (TOC) generally below 1.5%. This shale exhibits diverse lithofacies types, complex pore structures, strong reservoir heterogeneity, and significant lateral variations in pressure coefficients. Using the shale oil reservoir in Block H of the second member of the Funing Formation in the Subei Basin as an example, this paper analyzed the characteristics of regional logging responses based on the results of rock physics experiments. By integrating conventional and specialized logging methods, a logging interpretation model was developed to evaluate the lithology, reservoir properties, oil content, mobility, and fracability of the shale oil reservoir. The model’s calculations aligned well with core analysis results. Building on this, sensitive parameters were optimized to establish evaluation and classification standards for the shale oil reservoirs in the block, and a comprehensive “sweet spot” evaluation of the reservoir was conducted. Exploration practices involving multiple wells have verified that this logging evaluation technology is regionally adaptable. It effectively classifies shale oil reservoir types, supports the optimal selection of “sweet spots”, and provides reliable technical support for the exploration and development of shale oil in the Subei Basin.

The Upper Triassic Xujiahe Formation in the western Sichuan Depression, Sichuan Basin is an important area for the increase in reserves and production of tight sandstone gas (hereinafter referred to as “tight gas”) in the Sichuan Basin. In practical production, high-yield and stable production wells are highly correlated with the dense development of fractures. Fractures provide pathways and spaces for gas migration and storage, and whether fractures develop is a key factor restricting the formation of high-quality reservoirs. To evaluate the “sweet spot” enrichment area of the Xujiahe Formation gas reservoir, fracture development characteristics are identified and an effective fracture recognition method is established based on core observation, logging data, and intelligent algorithms. The research suggests that structural fractures, diagenetic fractures, and overpressure fractures all develop in the study area. The structural fractures are mainly divided into three phases: Phase 1 (NW-SE orientation) predominantly develops low-angle fractures, with occasional high-angle fractures; Phase 2 (NNE-SSW orientation) mainly develops high-angle fractures; Phase 3 (E-W orientation) predominantly develops high-angle fractures. The fracture segments in the tight gas reservoir display characteristics of low density, high neutron density, high sonic time difference, and positive amplitude differences in deep and shallow lateral resistivity. The conventional logging data with fracture and non-fracture labels were normalized, and machine learning algorithms were applied for fracture intelligent prediction. The F1 scores for the K-nearest neighbors (KNN), support vector machine (SVM), extreme gradient boosting (XGBoost), and random forest algorithms were 0.65, 0.83, 0.88, and 0.91, respectively. It was found that the random forest algorithm demonstrated strong robustness and anti-interference capabilities, with higher prediction accuracy and efficiency compared to the other three algorithms. Additionally, to balance computational efficiency and accuracy, the genetic algorithm was selected as the optimization algorithm for hyperparameter tuning, outperforming grid search, Bayesian optimization, and particle swarm optimization algorithms. Shapley Additive Explanations (SHAP) were used to calculate the contribution of different influencing factors to the predictions. It was found that the sonic time difference, neutron density, and compensated density were the main logging curves influencing prediction accuracy. The fracture density exhibited a clear spatial distribution pattern, decreasing from the southwestern part to the northwestern part of the Sichuan Basin. The research results can provide a practical and feasible intelligent prediction model for the fracture “sweet spot” zone in tight gas reservoirs in the western Sichuan Basin, laying the foundation for increasing reserves and production of tight gas.

Oil shale in the Sinopec exploration areas is abundant and serves as an important strategic reserve and supplementary energy source for the country. Accelerating the exploration and development of oil shale is crucial for improving China’s energy structure and ensuring national energy security. To achieve large-scale exploration and cost-effective development of oil shale, the technologies of in-situ exploitation field tests successfully conducted both domestically and internationally were reviewed and summarized. Based on this review, the characteristics of test areas, geological and engineering adaptability, and selection layer requirements were analyzed. It was concluded that field pilot tests of Shell’s electric heating method, Jilin Zhongcheng Company’s in-situ fracturing chemical retorting technology, and Jilin University’s local chemical reaction-based in-situ pyrolysis technology have been successfully carried out. However, the maturity and feasibility of two technologies in China need to be further studied and validated, and the adaptability of existing in-situ exploitation technologies to deep oil shale remains unverified. The technical characteristics, geological resource conditions, and exploitation engineering conditions of in-situ oil shale exploitation were reviewed and analyzed. Based on the key factors restricting in-situ exploitation of oil shale in China and the heating method, four geological parameters, six engineering parameters, and classification evaluation limits were determined. Additionally, the weights of each parameter were assigned according to the degree of constraints on in-situ exploitation and utilization of oil shale. A two-factor evaluation model of geological and engineering for identifying favorable areas for in-situ oil shale exploitation was then established, leading to the selection of 15 Class Ⅰ favorable areas in Sinopec exploration areas and adjacent areas. The effects of key factors, including roof and floor, fractures, and movable water, on the selected favorable areas were further analyzed. Through comprehensive evaluation, four target areas were selected: the Xunyi mining area on the southern margin of the Ordos Basin, the Shanghuangshan Street mining area on the southern edge of the northern piedmont of the Bogda Mountains, the Dianbai mining area in the Maoming Basin, and the Fushun mining area in the Fushun Basin.

Shale oil resources in the Subei Basin show significant potential. The second and fourth members of the Funing Formation (hereafter referred to as Funing Member 2 and Funing Member 4) are the main target layers for exploration. These layers are characterized by substantial thickness, wide distribution, high content of brittle minerals, well-developed laminated structure, and favorable organic matter types, with typical geological features, including low to medium total organic carbon (TOC), complex tectonics and lithology, and developed faults/fractures. Since 2011, Jiangsu Oilfield has strengthened basic research and exploration practices, leading to the establishment of the theory of differential enrichment of shale oil in complex fault blocks with low to medium TOC. Key technologies for exploration and development have been integrated and innovated, green and low-carbon development models have been explored, and significant breakthroughs have been achieved in shale oil exploration of Funing Member 2 and Funing Member 4 in the Gaoyou Sag. However, there are still many challenges, such as an unclear understanding of the patterns of shale oil enrichment and high yield, insufficient adaptability of engineering technologies, undefined technical policies for cost-effective development, and high development costs. Main approaches to achieving large-scale production and cost-effective development of shale oil include: deepening the fundamental research on the main controlling factors of shale oil enrichment and high yield, tackling main challenges and advancing key technologies, optimizing integrated organizational management and operation mechanisms, and maximizing the drilling success rate in high-quality reservoirs, the utilization rate of shale oil reserves, and the recovery efficiency to further reduce costs and improve efficiency.

The shale lithofacies in the second member of the Funing Formation (hereafter referred to as Funing Formation Member 2) in the Gaoyou Sag of Subei Basin exhibits significant heterogeneity, with complex lamination types that are challenging to quantify using well logging, thus limiting the identification of favorable “sweet spots” for shale oil. Therefore, this study investigates the methods for quantitative characterization of shale lamination types and their development in Funing Formation Member 2 of Gaoyou Sag, by integrating data from core thin sections, whole rock diffraction, elemental logging, and well logging, based on the climatic and environmental evolution during different sedimentary stages. The results show that shale lamination types mainly include quartz-enriched, clay-enriched, calcite, and dolomite bands. Influenced by ancient climatic evolution, the proportions of different lamination types vary across intervals, and the vertical superposition and coupling of these lamination types lead to differential shale oil enrichment, with more developed laminations corresponding to higher oil enrichment. During the deposition of intervals Ⅴ-6 to Ⅴ-10, the sediments exhibit a high aridity index, low Sr/Cu ratio, significant variation in the Sr/Ba ratio, and high V/(V+Ni) ratio. These characteristics suggest a strongly reducing, semi-arid to arid saline water environment with fluctuating water depths and periodic variation in lake nutrients. Saline stratification and diagenesis facilitate the development of abundant bright calcite layers, fibrous calcite layers, and dolomite layers, providing favorable reservoir properties for shale oil. During the deposition of intervals Ⅴ-1 to Ⅴ-5, the Sr/Cu ratio increases significantly while the aridity index decreases. The overall environmental characteristics indicate a strongly reducing, arid saline water environment. The shale is predominantly composed of clay-rich to sandy-mixed lithology, with clay-enriched layers and clay-rich laminations as the dominant lamination types. Due to the influence of recrystallization degree, the proportion of bright calcite layers decreases while the proportion of mudstone-like calcite layers increases. During the deposition of intervals Ⅳ-5 to Ⅳ-8, the Sr/Cu ratio exhibits a periodic variation of “decrease followed by increase”, indicating a decrease in lake water salinity. The lithology primarily consists of clay-rich to sandy-mixed shale, with the development of clay-enriched layers, clay-rich laminations, bright calcite layers, fibrous calcite layers, and dolomite layers. These intervals demonstrate excellent reservoir properties and are regarded as high-quality sweet spot layers for shale oil. During the deposition of intervals Ⅳ1-Ⅳ4, the Sr/Cu ratio increases, indicating intensified arid conditions. The climate characteristics suggest a strongly reducing, arid saline environment. The recrystallization degree of calcite is higher, leading to the development of bright calcite, fibrous calcite, and dolomite layers. Additionally, the proportion of mudstone-like calcite layers increases, indicating a higher overall carbonate mineral content influenced by the depositional environment. During the deposition of the subinterval Ⅲ, the climate alternates between humid and arid conditions, with a higher degree of calcite crystallization and the development of bright calcite layers. Subintervals Ⅱ and Ⅰ exhibit a significant decrease in Fe/Mn and Sr/Ba ratios, indicating intensified humid conditions. Water depth increases, and the shale gradually transitions to blocky structure. The content of gray and muddy minerals decreases, limiting the development of gray and muddy laminations. The study further confirms a positive correlation between the degree of shale lamination development and shale oil enrichment. Based on the geological characteristics of the shale lamination distribution, further analysis was conducted using methods such as edge detection from electrical imaging well logging and shale deposition rate calculation. The study identified intervals Ⅳ-3 to Ⅳ-7 and Ⅴ-6 to Ⅴ-8 in Funing Formation Member 2 as having well-developed laminations and higher total organic carbon (TOC) compared to other intervals, marking them as vertical shale oil sweet spot layers. The image edge detection method using electrical imaging well logging offers high accuracy for shale bedding identification and is suitable for detailed geological evaluation of vertical shale oil sweet spot layers in different blocks. Furthermore, as the climate change during shale deposition becomes more frequent and the sedimentation rate varies more drastically, the vertical heterogeneity and lamination development of shale increase. Thus, sedimentation rate variations can serve as an indicator of shale lamination development. An analysis of stratigraphic cycles in the Huazhuang area's Funing Formation Member 2 revealed that natural gamma MTM spectrum analysis of well Huaye 7 identified eight dominant frequencies, corresponding to cycle thicknesses of 39.84, 11.76, 9.43, 4.20, 3.19, 2.32, 2.13, 1.82 m. The ratio of cycle thicknesses is 21.91:6.47:5.19:2.13:1.76:1.28:1.17:1.00, which is close to the theoretical cycle ratio of 21.32:6.58:5.26:2.74:2.00:1.21:1.16:1.00 for this period. Therefore, the shale deposition process of the Funing Formation Member 2 is controlled by the Milankovitch astronomical cycle. The optimal sedimentation rate for this interval was determined to be 10.8 cm/kyr. Using this optimal rate, the eCOCO statistical method was applied to track and analyze sedimentation rate variations in the Funing Formation Member 2. The results indicate significant differences in sedimentation rates among different sub-layers of the Funing Formation Member 2 due to the influence of periodic climatic fluctuations. Moreover, the degree of lamination development indicated by the sedimentation rate variation correlates well with the overall proportion of lamination development obtained from thin section analysis, and is consistent with the lamination development detected by imaging logging in different intervals. Consequently, this method can predict the spatial distribution of lamination development, providing guidance for three-dimensional shale oil exploration. In summary, this study provides insight on the lithological heterogeneity and quantitative logging characterization of the Funing Formation Member 2 in the Gaoyou Sag, Subei Basin. These findings contribute to the identification and evaluation of shale oil sweet spot layers, promoting shale oil exploration and development.

To address the challenges of rapid production decline and low recovery of shale oil wells, it is imperative to supplement formation energy and explore innovative development methods. Compared with conventional waterflooding, CO₂ exhibits superior injectivity and miscibility with crude oil, making it an effective oil displacement medium. Simultaneously, CO₂ is a major greenhouse gas and a key target for emission reduction. Therefore, exploring CO₂ huff-n-puff in shale oil reservoirs for enhanced oil recovery while simultaneously achieving carbon sequestration has significant practical value. However, Carbon Capture, Utilization and Storage (CCUS) technology in shale oil is still in its exploratory stage, facing challenges such as immature numerical simulation techniques and the lack of large-scale injection-production operations. To investigate the mechanisms and key controlling factors of enhanced oil recovery through CO₂ injection in shale oil, this study employed numerical simulation techniques, integrating logging data, geological parameters, and fracturing operation data to model the formation and distribution of hydraulic fractures. A composite discrete fracture network numerical model combining both artificial and natural fractures was established to analyze the oil recovery enhancement mechanisms of CO₂ huff-n-puff. The study clarified the influence patterns of reservoir engineering parameters in CO₂ huff-n-puff on both cumulative oil increment and CO₂ storage capacity, and determined the primary controlling factors among these parameters. The results showed that CO₂ huff-n-puff restored production capacity in shale oil wells by replenishing formation energy, extracting light and intermediate components from shale oil, and leveraging CO₂ diffusion, oil viscosity reduction, and expansion effects. Considering both oil recovery and storage, the optimal injection strategy for a single well included: initiating when daily oil production declined to just above 8 m³, injecting 15 000-24 000 tons of CO₂ at a rate of 500-900 t/d, shut-in duration of 30-50 days, and conducting 2-3 huff-n-puff cycles. Among the shale oil reservoir engineering parameters, injection volume was identified as the primary factor, with a weight of 0.48. These findings provide technical guidance and evaluation support for the implementation of CCUS technology in shale oil reservoirs.

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 southeastern Sichuan region is characterized by complex tectonic structures. The shale gas reservoir from the first member of the upper Ordovician Wufeng Formation to the Lower Silurian Longmaxi Formation is buried at considerable depths, which significantly affects the rock mechanical properties. However, systematic studies remain limited. This study focuses on the deep shale gas reservoir in the Lintanchang area of southeastern Sichuan. A series of mechanical experiments, including triaxial compressive tests, acoustic wave velocity measurements, tensile strength tests, and fracture toughness tests, were carried out. Based on the results of these multi-mechanical experiments, the rock mechanical properties of shale samples were analyzed, and a vertical mechanical property profile for a single well was established. With increasing temperature and pressure, the residual stress after fracture, Young’s modulus, and Poisson’s ratio of the deep shale samples showed an upward trend. The post-peak stress-strain curves exhibited more pronounced fluctuations. Acoustic wave velocities at the plunging end of the Lintanchang anticline were lower than those at the flanks. Young’s modulus and Poisson’s ratio values, corrected using a dynamic-static linear transformation, exhibited improved accuracy. The maximum load borne by the deep shale samples was less than 10 kN. Type Ⅰ and Type Ⅱ fractures displayed notable differences in propagation characteristics, and the degree of fracture penetration was greatly affected by sampling direction. The vertical mechanical profile of well T4 revealed that the bottom section of the first member of the Wufeng-Longmaxi Formation has higher Young’s modulus, lower Poisson’s ratio, and stronger brittleness, while the compressive and tensile strengths, as well as the fracture toughness index, remain relatively low. These mechanical properties show a weak compressive-tensile state, providing favorable conditions for reservoir stimulation. Thus, this interval represents an optimal target for future exploration and development.

Shale gas production has exhibited high initial yields followed by a rapid decline. This rapid decline suggests that early-stage production rates were likely excessive, accelerating the depletion of reservoir productivity and adversely affecting the Estimated Ultimate Recovery (EUR) of shale gas wells. Therefore, accurate and reasonable productivity evaluation plays a key role in ensuring stable reservoir development. To identify the challenges of current shale gas productivity evaluation approaches and explore feasible solutions, this study analyzed the unique connotation of shale gas productivity and reviewed recent progress in three approaches: (1) Analytical solution methods of flow equations; (2) numerical simulation methods of flow equations; and (3) artificial intelligence (AI)-based methods. The results revealed that shale gas productivity was highly stage-dependent, with substantial variations in dominant controlling factors, flow mechanisms, and flow regimes across different production stages. Early and late production stages exhibit distinct controlling factors, leading to differentiated perspectives across the various evaluation methods. The analytical solution method relied heavily on a deep understanding of flow mechanisms. Numerical simulation methods require extensive, high-quality datasets and strong reservoir engineering expertise for validation. AI-based methods faced challenges such as high opacity, limited interpretability, and poor generalization. Based on these findings, future research should focus on integrating shale gas flow mechanisms at both micro and macro scales. Emphasis should be placed on the multidimensional integration of geological modeling, stress-petrophysical evolution, fracture propagation, multiphase flow numerical simulation, and decline analysis, enabling more comprehensive productivity characterization. In addition, further work is needed to incorporate mechanism-informed constraints into machine learning algorithms, enhance model transparency through causal inference, and improve interpretability. These advancements aim to avoid the limitations in existing productivity evolution methods and support the development of robust and rational shale gas productivity evaluation models and methods, providing theoretical guidance for accurate well productivity prediction, production stabilization, and efficient resource development.

In fault block G76 of the Jidong Oilfield, issues such as increased injection pressure and difficulty in water injection have arisen during the waterflooding development process. To analyze the variation in reservoir properties during water injection, high multiple waterflooding experiments were conducted on cores using two-dimensional nuclear magnetic resonance (NMR) technology. Laser particle size analysis was performed on the target reservoir cores to obtain particle size distribution, and X-ray diffraction (XRD) analysis was conducted to determine mineral content proportions. High multiple waterflooding experiments based on NMR technology were carried out to analyze reservoir property variations. The results showed that core 5-1 and core 6-1 consisted of medium sand-bearing silty fine sandstone and silt-bearing medium sandy fine sandstone, respectively, with high contents of fine sand, silt, and clay minerals. The relative permeability of the water phase and NMR porosity initially increased with cumulative water injection to a high value and then declined. In the NMR T₂ spectrum, the right endpoint values and the curves corresponding to medium and large pores shifted left as water injection increased. In the two-dimensional spectra, the free water signal intensity increased with cumulative water injection. As the injected water transitioned from bound water to a cumulative injection of 500 PV, the bound water signal continuously increased. When the cumulative injection is beyond 500 and up to 1 000 PV, the bound water signal of core 5-1 continued to strengthen, while that of core 6-1 weakened. The study suggests that, in the early stages of water injection, weak hydration of clay minerals occurs. In the later stages, due to water flushing, fine silt particles and clay minerals in the cement may detach and migrate to pore throats, causing blockage and damage to the pore throat structure, thereby reducing water phase permeability. The findings reveal the reasons for injection difficulty and increased pressure during waterflooding in medium-low permeability oil reservoirs and provide guidance for mitigating contamination and improving the effectiveness of waterflooding development.

The deep oil and gas exploration area serves as a crucial position for resource development in Subei Basin. However, challenges including generally poor physical properties of deep reservoirs, insufficient understanding of oil and gas enrichment mechanisms, and ineffective reservoir prediction to meet exploration demands have constrained the expansion of deep oil and gas exploration. To understand the enrichment mechanisms of deep oil and gas, develop key exploration technologies, and indicate future research directions, this paper focuses on the deep layers of Gaoyou and Jinhu Sags, which are rich in oil and gas resources. Firstly, by analyzing the exploration development trends and oil and gas resource potential in oil and gas enrichment Sags such as Gaoyou and Jinhu, along with physical characteristics and main controlling factors of deep reservoirs, it was believed that the deep oil and gas reservoirs in Gaoyou and Jinhu Sags were mainly characterized by low to extra-low porosity and permeability. Secondary pore was the main pore type, while primary pore occurred locally. Overall, as burial depth increased, the proportion of primary pores gradually decreased. Subsequently, based on the relationship between pores and pore throats, deep reservoirs were classified into four types of pore-throat structures: large intergranular pores and wide lamellar throats; small intergranular pores and narrow lamellar throats; intragranular dissolution pores and narrow lamellar throats; and micropores and tubular throats. The physical properties of deep reservoirs were generally poor, with locally developed favorable reservoirs. The factors influencing the physical properties of deep reservoirs were complex. Analysis suggests that sedimentary factors, diagenesis, tectonic activity, oil and gas injection, and abnormal formation pressures all significantly affected the physical properties of deep reservoirs, although the controlling factors and their effects varied across different regions. Secondly, investigations were conducted on the occurrence conditions, main controlling factors, and accumulation models of deep oil and gas. The occurrence conditions of oil and gass suggested that oil and gas migration and accumulation were controlled by the pressure systems and physical properties between source rocks and reservoirs, as well as between different reservoirs. Oil and gas accumulation occurred when migration forces overcame migration resistance. Microscopically, pore-throat structure determined the fluid occurrence state and permeability. Larger throat radii, lower pore-throat radius ratios, and smaller tortuosities led to enhanced pore-throat connectivity and higher reservoir permeability. Macroscopically, pressure increase with oil and gas generation provided the driving force for oil and gas migration and accumulation. The magnitude and direction of source-reservoir pressure difference decided the favorable trends for oil and gas migration and accumulation, controlling their favorable areas. In terms of the main controlling factors for oil and gas enrichment, it was believed that oil and gas accumulation and enrichment in deep reservoirs were jointly controlled by source-reservoir configuration, pressure increase with oil and gas generation, fault-sandstone carrier system, and reservoir physical properties. Three accumulation models for deep oil and gas enrichment were established: stepped accumulation driven by combined abnormal overpressure and buoyancy, accumulation via fault-sandstone carrier system driven by abnormal overpressure, and accumulation of early-stage oil and gas injection followed by later-stage compaction. These models elucidated the enrichment mechanisms of deep oil and gass. Based on the above, to address exploration challenges such as unclear reservoir distribution, undefined enrichment zones, and low identification accuracy of effective reservoirs, three breakthrough technologies were developed: (1) A facies-controlled index method for deep reservoir classification was developed based on “facies-controlled index, porosity-permeability characteristics, pore structures, and diagenetic facies”. Reservoir classification criteria were formulated, categorizing reservoirs into four grades. Effective reservoirs in deep layers were mainly grades Ⅱ and Ⅲ. The distribution of effective reservoirs in the deep layers was evaluated across key stratigraphic intervals, revealing the graded distribution of reservoirs in deep zones of the first and third member of Funing Formation, the third submember in the first member of Dainan Formation in Gaoyou Sag, and the second member of Funing Formation in Jinhu Sag. The favorable areas of effective reservoirs in the deep layers of each stratigraphic system in each Sag were finally determined. (2) Through the analysis of deep oil and gas enrichment mechanisms, and according to the dynamic conditions of oil and gas injection, models for calculating reservoir potential energy, fluid potential, and source-reservoir pressure differences were established. Subsequently, a model for calculating the reservoir injection potential energy index were established based on the above models. Finally, the obtained reservoir injection potential energy index was used to assess the probability of oil and gas accumulation, providing technical support for the selection of favorable oil and gas accumulation zones in deep layers. (3) Subaqueous distributary channels and beach-bar sand bodies were effective reservoirs for deep oil and gass. To address the challenge of effective reservoir prediction in thin sandstone-mudstone interbeds within favorable oil and gas accumulation zones in selected deep layers, an integrated technical suite for effective reservoir prediction was developed. This technique, tailored to different sand body types such as channels and beach bars, integrated pre-stack and post-stack multi-attribute analysis. It leveraged geological, petrophysical, seismic, statistical, and other disciplinary theories to provide a comprehensive approach to reservoir prediction. Based on the distinction between sandstone and mudstone, this suite included six techniques for reservoir prediction: effective reservoir modeling based on petrophysical analysis, post-stack multi-parameter inversion constraint method, pre-stack and post-stack joint inversion method, seismic attribute threshold analysis method, seismic multi-attribute neural network prediction method, and SP curve reconstruction for acoustic curve. These techniques collectively improved the prediction accuracy of effective reservoirs in deep layers. These research findings provide theoretical guidance and technical support for the expansion of deep oil and gas exploration. Significant exploration progress has been made in deep layers such as slope zones, fault zones, and deep sag zones, enabling the expansion of deep oil and gas exploration. In the future, the research directions for addressing challenges in deep oil and gas exploration are clarified, which are continuing to consolidate and expand deep exploration to support the increase in oilfield reserves and production.

The C-2 oilfield, located in the Bohai Bay Basin, is a fluvial-facies offshore oilfield primarily developed with horizontal wells. It is characterized by thin reservoir layers, vertically stacked multi-phase sandbodies, and rapid lateral facies transitions, leading to complex internal reservoir structures and connectivity. The combined effects of complex reservoir structures and well-seismic data make reservoir characterization challenging under sparse well patterns, hindering refined development. Conventional seismic inversion fails to meet the requirements for high-resolution prediction of thin reservoirs and detailed characterization of internal reservoir structures. To study the structural characteristics of braided river reservoirs in the oilfield, a stacking ensemble learning method based on seismic attributes was applied to predict the complex fluvial-facies reservoir structures. This approach significantly improved prediction accuracy compared to a single machine learning model. By integrating multi-dimensional information such as geology, geophysics, and reservoir dynamics, iterative optimization was conducted to further reduce the uncertainty in subsurface reservoir prediction and structural understanding. This enabled the precise characterization of the complex braided river reservoir structures in the study area, providing a basis for refined exploitation of remaining oil and potential sandbodies in the oilfield. The study demonstrates that the reservoir prediction method based on stacking ensemble learning not only enhances seismic vertical resolution, but also exhibits strong horizontal phase-control capabilities. The prediction results include sandbody stacking relationships and internal reservoir structures, making it more suitable for the prediction and fine characterization of continental fluvial sedimentary systems with rapid facies transitions and complex spatial architectural structures. This method can serve as a reference for the detailed characterization of fluvial-facies reservoir configurations during the middle and late development stages of offshore oilfields with sparse well patterns.

The Sichuan Basin has rich resources of tight sandstone gas. Currently, research on the pore evolution of ultra-deep, ultra-tight sandstone reservoirs in the eastern slope of the western Sichuan Depression is relatively scarce. Using core observation, cast thin section identification, scanning electron microscopy, carbon-oxygen isotope analysis, and homogenization temperature of fluid inclusion, combined with burial history and thermal history, the coupling characteristics of pore evolution and oil and gas charge in the ultra-deep, ultra-tight sandstone reservoirs in the second member of Xujiahe Formation (hereinafter referred to as Xu 2 member) on the eastern slope of the western Sichuan Depression were clarified. The Xu 2 member reservoir is mainly composed of lithic sandstone and lithic quartz sandstone, with authigenic quartz and carbonates as the primary cementing materials. The storage space is dominated by intragranular pores. The densification period of the reservoir varies among different submembers. The upper submember is less resistant to compaction due to the presence of higher plastic materials like mudstone clasts, and it became compacted during the Middle to Late Jurassic. Subsequently, under continuous deep burial and the dual destructive effects of pressure dissolution and quartz, the middle and lower submembers became compacted during the Late Jurassic. At the end of the Cretaceous, tectonic uplift led to the formation of fractures that promoted the dissolution of the middle and lower submembers, increasing the reservoir porosity to around 5%, with a more significant increase in permeability. There were two main periods of oil and gas charge. The upper submember had a poorer coupling relationship, with early densification that was unfavorable for oil and gas charge and natural gas accumulation. In contrast, the main oil and gas charge period for the middle and lower submembers occurred prior to the densification of the reservoir, which was favorable for natural gas accumulation and reservoir formation. The Xu 2 member on the eastern slope of the western Sichuan Depression exhibits three “sweet spot” reservoir development modes: ancient trap+source fracture superposition, ancient trap+internal source rock+late fracture superposition, and ancient trap+source fracture+late fracture superposition. The study provides examples and theoretical guidance for understanding the evolution-oil and gas charge coupling characteristics of deeply buried ultra-tight sandstone reservoirs.

As a critical component of Carbon Capture, Utilization and Storage (CCUS) technology, CO₂ geological storage plays a decisive role in the development potential and direction of CCUS technology, and serves as an effective means to achieve “dual carbon” goals. Clarifying the series of formation responses caused by CO₂ injection is essential for safe and efficient injection. Pressure buildup is a primary factor constraining the storage capacity and safety. Fluid dissolution, migration, and precipitation are the fundamental features affecting formation stability and storage efficiency. In addition, reservoir injectivity and caprock integrity are key determinants for the success of geological storage projects. The formation response characteristics caused by CO₂ injection were systematically discussed, including pressure buildup, pressure propagation, CO₂-water-rock interactions, mineral dissolution and precipitation, and rock pore structure characteristics. The influences of wettability, porosity, permeability, fluid properties, rock strength, caprock integrity, surface deformation, and fault activation on reservoir injectivity and caprock safety were summarized. Major current issues in research were identified, including the unpredictability of pressure change patterns, unclear reaction mechanisms, low injection efficiency, and incomplete monitoring and evaluation frameworks. Future work should deepen the understanding of storage mechanisms, improve monitoring and assessment methods of formation response, strengthen environmental risk evaluation, and further promote the safe and efficient application of CO₂ geological storage technology, thereby providing strong support for addressing global climate change.

Marine carbonate oil and gas resources in the western Sichuan region of the Sichuan Basin are buried at depths exceeding 7 000 meters. Vertically, multiple hydrocarbon reservoirs exist, resulting in complex pressure systems where the coexistence of influx and loss may occur within the same open hole-section. When downhole complications arise, well control becomes challenging. In such cases, a contingency casing string must be run, which increases the number of casing intervals, prolongs the drilling cycle, and raises overall costs. To address this challenge, a targeted optimization of the wellbore structure was performed after setting the contingency casing. However, technical challenges persisted due to the coexistence of high- and low-pressure systems within a single open-hole section, and the presence of a narrow safe mud weight window. Based on a managed pressure and gas-venting density reduction process, and integrating formation gas seepage theory with wellbore flow dynamics, the migration patterns of natural gas in both the formation and annular space were analyzed. The research results showed that during the early stage of gas-venting density reduction under managed pressure, the gas influx rate declined rapidly, then gradually slowed and stabilized. This technique effectively released formation energy and reduced formation pressure, thereby helping to expand the safe mud weight window. The gas influx rate was identified as the main factor affecting well control safety. To ensure safe operations, the gas influx rate must not exceed the critical safe threshold. Based on both theoretical analysis and cost evaluation, the optimal duration for gas-venting density reduction was determined to be 10 days. Field applications were conducted in two wells targeting high-pressure formations in the Maokou Formation within the Shuangyushi Structure. Managed pressure and gas-venting operations successfully reduced the lower limit of the safe mud weight window by 0.16 g/cm³ and 0.40 g/cm³ respectively. These wells were drilled in combination with low-pressure reservoirs in the Qixia Formation. As a result, the casing program was simplified from six intervals to five, significantly reducing the drilling cycle and costs. This led to the development of a safe drilling technology for ultra-deep gas wells with complex pressure systems through managed pressure and gas-venting density reduction. The proposed method provides a valuable technical reference for wellbore structure optimization and safe drilling operations in similar ultra-deep, complex pressure environments.

Most oilfields currently using CO₂ flooding in China have transitioned from water flooding to CO₂ injection for development. Over prolonged periods, CO₂-water-rock reactions can alter reservoir physical properties, becoming a key issue that must be addressed. To address limitations in existing studies—such as short reaction durations and unclear effects of environmental variables—this research used a high-temperature, high-pressure reactor to simulate reservoir conditions. Advanced equipment, including high-performance field-emission scanning electron microscope and X-ray diffraction, was utilized to study the effects and mechanisms of CO₂-water-rock reactions on reservoir physical properties and mineral compositions under different environmental variables. The experimental results indicated that feldspar dissolution and clay mineral formation were the primary factors affecting reservoir physical properties after CO₂-water-rock reactions. With increasing temperature, the water-rock reaction intensified, accelerating the dissolution of potassium feldspar, calcium feldspar, and sodium feldspar while increasing the proportion of kaolinite, thereby improving reservoir physical properties. When pressure increased, the dissolution of large amounts of CO₂ lowered the solution pH and inhibited the transformation of minerals such as potassium feldspar and sodium feldspar into clay minerals like kaolinite, causing deterioration in overall reservoir physical properties. As the reaction time increased, the dissolution of feldspar and carbonate minerals intensified, leading to increased mass concentrations of major ions such as Na⁺, K⁺, Ca²⁺, an improvement in reservoir physical properties, and the precipitation of gypsum. Within the experimental range, the degree of mineral dissolution caused by CO₂-water-rock reactions exhibited a positive correlation with temperature and time but a negative correlation with injection pressure. Finally, the experimental results were calculated using the Kozeny-Carman equation, indicating that within the experimental range, reservoir porosity and permeability are positively correlated with temperature and time, and negatively correlated with CO₂ injection pressure. By studying the impact of CO₂-water-rock reactions on reservoirs under different environmental variables, this study offers insights for the application of CO₂ flooding to enhance oil recovery (EOR) in shale oil reservoirs.

The Tarim Basin serves as the major area for deep and ultra-deep oil and gas exploration and development. A significant breakthrough has recently been achieved in the exploration of ancient buried hill-type oil and gas reservoirs within the Cambrian System of the Paleozoic strata in well Tuotan 1, Kuqa Depression, Tarim Basin. Due to the ancient geological age and complex reservoir geology, systematic studies on oil and gas accumulation process and fluid evolution in this area remain insufficient. In this study, methods including biomarker analysis, petrological analysis, in-situ micro-area trace element and strontium isotope analysis, and fluid inclusions were used to determine the fluid origins of vein formation and the timing of multiple-phase of oil and gas charging in the dolomite reservoirs of the Xiaqiulitage Formation. The results revealed that the dolomite reservoirs in Xiaqiulitage Formation, well Tuotan 1 primarily developed two phases of calcite veins that filled fractures and dissolution pores. The first phase of calcite originated from deep, strontium-rich fluids, while the second phase of calcite veins derived from seawater. Two phases of oil-bearing fluid inclusions were predominantly developed within the second-phase calcite veins, comprising secondary blue-white fluorescent oil inclusions and secondary green fluorescent oil inclusions. The integration of fluid inclusion thermometry with single-well burial history reconstruction revealed that the first-phase blue-white fluorescent inclusions recorded oil and gas accumulation during the deposition of the Neogene Jidike Formation (23-20 Ma), while the second-phase green oil inclusions recorded oil and gas accumulation during the deposition of the Neogene Kuqa Formation (5-3 Ma). Oil-source correlation analysis indicated that the two phases of crude oil in the reservoirs of Xiaqiulitage Formation were derived from mixed contributions of lacustrine source rocks in the Triassic Huangsanjie Formation and Jurassic Qakmak Formation. The new findings from well Tuotan 1 in Kuqa Depression demonstrate that ancient strata in the foreland region of the Tarim Basin still retain favorable conditions for large-scale oil and gas accumulation, making buried hill-type oil and gas reservoirs a promising frontier for increasing reserves and production in Kuqa Depression.

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.

The depletion process of a gas-condensate reservoir is characterized by significant condensation phenomenon. Existing material balance methods often fail to establish a linear relationship between pressure drop and cumulative production, resulting in considerable errors in dynamic reserve evaluations. Therefore, it is crucial to study material balance methods tailored for complex multiphase flow gas reservoirs. Based on the fluid flow poromechanics of gas-condensate reservoirs, a new method for calculating dynamic reserves in gas-condensate reservoirs was established by introducing two-phase pseudo-pressure parameter and applying flowing material balance theory. In the multiphase flowing material balance method, a clear linear relationship was observed between the normalized production rate and normalized cumulative production. The analysis results showed that when the production did not reach the pseudo-steady state, the calculated dynamic reserve results would be biased. By analyzing the differences in saturation behavior across various flow regimes, a calculation method for the two-phase pseudo-pressure parameter was developed. The modified production indication curve could improve the accuracy of dynamic reserve calculations for condensate gas reservoirs. The method was applied to wells in a gas-condensate reservoir. Compared with conventional methods and the Blasingame chart fitting method, the proposed approach yielded more accurate dynamic reserve evaluations. The results demonstrate that the proposed calculation method enhances the accuracy of dynamic reserve evaluations for gas-condensate reservoirs and supports timely adjustments to development plans in the field.

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.

To investigate the influence of shale oil with different oil saturation on imbibition recovery rate, shale samples from the Jiangling sag in the Jianghan Basin were taken as the research object. Imbibition experiments were conducted to examine the variation of core imbibition curves at oil saturation of 20%, 30%, 40%, and 50% under conditions of similar and increasing permeability. Nuclear magnetic resonance (NMR) technology was used to analyze the changes in oil-phase signals within the core pores before and after imbibition. Additionally, the imbibition volume and oil displacement volume during the imbibition process were compared. The results showed that under similar permeability conditions, cores with higher oil saturation exhibited higher imbibition recovery rates. In contrast, cores with higher oil saturation had slower imbibition rates at the initial stage of imbibition and required a longer time to reach imbibition equilibrium. When permeability gradually increased, cores with higher oil saturation achieved higher imbibition recovery rates. In this case, cores with higher oil saturation also exhibited faster imbibition rates in the early stages compared to those with lower oil saturation. The hydration and expansion of shale resulted in the imbibition volume exceeding the oil displacement volume during the imbibition process. Moreover, the difference between these two volumes increased with higher oil saturation. The findings of this study provide a theoretical basis for improving shale oil recovery.

Under the influence of fracture shear slippage and wall roughness, the fluid flow channels within the fractures are uneven, making the transport and placement patterns of proppant carried by fracturing fluids more complex. Using core samples from the Longmaxi Formation, rock fracture surfaces were obtained through splitting, and rough fracture plates were created using techniques such as stretching, stacking, and carving to construct an experimental setup for proppant transport in single-sided rough fractures. Semi-quantitative tests of sand dam morphology and quantitative tests of solid-liquid two-phase flow were conducted. Experiments on proppant transport were carried out under conditions of varying roughness, discharge, viscosity, and particle size within the uneven flow channels of rough fractures. Additionally, particle image velocimetry (PIV) / particle tracking velocimetry (PTV) tests were performed in the fracture near-wellbore area under different roughness conditions. Results showed that the flow channels in rough fractures were uneven, and the proppant placement morphology exhibited an irregular concave-like structure, influenced by dominant channels. When fluids and proppants flowed near large protrusions, their original movement direction was altered towards dominant channels. The movement direction of the proppants was also affected by the accumulated sand dam morphology. Discharge was the key factor in reducing the influence of dominant channels, where decreasing discharge could effectively plug these channels. Under varying viscosity and particle size conditions, the influence of dominant channels persisted, with viscosity and particle size mainly affecting the transport distance and accumulation pattern of the proppants. Increased viscosity or reduced particle size led to greater proppant transport distances and layered sand dam accumulation.

For offshore oil and gas jacket platforms with detected structural cracks, a methodology for structural integrity evaluation and maintenance cycle strategy formulation was developed based on engineering critical assessment (ECA) techniques. A case study was conducted on a specific jacket platform. The Morison equation was used for hydrodynamic analysis of the target platform to estimate the ultimate load of joints prone to failure. Hotspot stress assessment was performed on these joints using the finite element analysis method and linear extrapolation. Crack propagation behavior at critical joints was simulated using Paris' law, and the stress intensity factor at the crack tip was determined. Cracks were assessed using failure assessment diagrams (FAD), and the critical crack sizes were provided. Based on the relationship between critical crack depth and crack propagation, a reference maintenance cycle was proposed. The results showed that the joints connecting horizontal braces and risers of the jacket structure were prone to fatigue damage. Failure assessment indicated that failure in the crack depth direction was primarily dominated by collapse, while failure in the crack length direction may involve both collapse and fracture. For the analyzed platform, it was recommended to consider a critical crack depth of 5.3 mm and a critical crack half-width of 9.8 mm. If cracks ranging from 0.5 to 2.0 mm were detected, maintenance was recommended within 13.2 to 5.2 h. This methodology can be extended to similar offshore oil and gas platforms with detected cracks in adjacent sea areas.

Tight oil reservoirs, as a key focus in China’s current oil and gas development, present significant exploration challenges due to their poor physical properties, limited connectivity, and strong heterogeneity. During the exploration of tight oil reservoirs, the influence of different injection media and production methods on recovery mechanisms and performance remains unclear, severely restricting their efficient exploration of these reservoirs. Taking the Fuyu reservoir in the Daqing oilfield of PetroChina as a case study, laboratory experiments involving dynamic core injection were conducted using various injection media (CO₂ and surfactants) and methods (displacement, huff-n-puff, and gas-water alternating injection) to investigate their effects on oil recovery mechanisms and efficiency in tight reservoirs. The results indicated that gas-water alternating displacement improved underground oil recovery by 4.14% compared to CO₂ displacement and by 15.38% compared to surfactant displacement. Similarly, gas-water alternating huff-n-puff increased oil recovery by 0.54% over CO₂ huff-and-puff and by 5.09% compared to surfactant huff-n-puff. Displacement methods, after forming preferential oil flow channels, exhibited larger sweep volumes and higher oil displacement efficiency than huff-and-puff methods. Moreover, gas-water alternating injection effectively reduced fluid channeling compared to single-media injection and enhanced the sweep of fine pore spaces. Due to CO₂’s superior viscosity reduction and dissolved gas drive effects on reservoir crude oil, CO₂ injection achieved higher recovery than surfactant injection. Under identical injection-production conditions, low-viscosity crude oil exhibited a higher recovery compared to high-viscosity crude oil, as increased viscosity significantly raised flow resistance. The study reveals the differences in recovery performance associated with various injection media and methods, providing experimental evidence and theoretical support for the efficient development of tight oil reservoirs.

To investigate the variation of production decline rate at different water cut stages during oilfield development, this study explored the relationship between decline rate, water cut rise rate, and water cut based on relative permeability curves. The relationship between decline rate and water cut under injection-production balance conditions was established, followed by computational analyses on a thick oil reservoir Z and a multi-layer oil reservoir S. The results showed that, under ideal injection-production balance conditions, the decline rate at a certain water cut stage was jointly influenced by liquid production rate and irreducible water saturation. The decline rate exhibited a parabolic trend with increasing water cut and was proportional to the liquid production rate. For a given reservoir under known conditions, the magnitude of the production decline rate was primarily determined by the liquid production rate and could be controlled by adjusting parameters such as well spacing density and the ratio of injection to production wells, which affected the liquid production rate. By establishing the relationship between decline rate and water cut, factors influencing production decline are clarified, providing a basis for strategies to mitigate production decline.

As a critical component of Carbon Capture, Utilization, and Storage (CCUS) technologies, CO₂-enhanced oil recovery (CO₂-EOR) has been widely used both domestically and internationally. This technology not only improves oil recovery but also enables large-scale CO₂ sequestration. However, potential CO₂ leakage risks exist throughout the processes of CO₂ injection, displacement, sequestration, and production. Existing monitoring practices in domestic and international projects primarily focus on reservoirs and caprocks, with limited attention paid to systematic ecological environmental monitoring. CO₂-EOR development commenced in the Zhangjiaduo oilfield in 2014. As of now, a cumulative total of 195,300 tonnes of CO₂ has been injected, resulting in an incremental oil production of 51,600 tonnes. The oil recovery rate was improved by 15.22%, and the phase oil replacement ratio reached 3.78, indicating remarkable stimulation effectiveness. Based on the Zhangjiaduo CO₂-EOR and sequestration project, a comprehensive 3D monitoring system was developed, integrating multiple indicators across groundwater, soil, and atmosphere to enable real-time monitoring and early warning of CO₂ leakage. After over one year of continuous monitoring, the results showed that the CO2 mass concentration in Zhangjiaduo groundwater remained stable at about 5,712 mg/m³, with a near-neutral pH and stable electrical conductivity ranging from 1.343 to 1.347 μS/cm. The CO₂ mass concentration, pH, and conductivity in the soil also remained relatively stable. Atmospheric CO₂ concentrations at three different altitudes exhibited periodic fluctuations consistent with soil data, averaging between 730 and 780 mg/m³, which aligns with typical atmospheric CO₂ levels in low-latitude regions. These multi-parameter monitoring results indicate that no CO₂ leakage has occurred in the Zhangjiaduo oilfield to date. The successful application of this monitoring system has provided robust scientific support for the sustained development of the field. Moreover, it offers practical insights and references for environmental monitoring in similar projects, contributing to the safe and sustainable advancement of CO₂-EOR technologies.

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.

Helium is a rare inert gas with indispensable applications in defense, aerospace, and medicine. However, helium resources available for use in China are extremely limited. To date, no independently accumulated helium resources have been found. Helium is primarily found in two forms: natural gas-associated and geothermal water-dissolved. This study focused on two typical basins—the Hangjinqi area in the northern Ordos Basin and the Weihe Basin—to investigate the genesis of helium. Helium isotope mass spectrometry analysis, rock radioactive element analysis and other methods were conducted to test the assgciated gas, core samples and potential helium source rock in the surrounding areas of the study area. The results show that helium in the Hangjinqi area in the northern Ordos Basin is typically crust-derived. While in Weihe Basin, high volume fractions of mantle-derived helium (up to 6.959%) were detected near deep-seated faults penetrating the basement, such as the Baoji-Xianyang fault and the Piedmont Fault of the Qinling Mountains. Both basins are located on the southwestern margin of the North China Plate and share a basement composed mainly of Archean-Proterozoic metamorphic-granite complexes, which serve as the main source rocks of helium formation. In addition, the main source rocks for helium gas in the Weihe Basin also include the uranium-rich granites of the Yanshanian period around the periphery and the concealed granitic bodies of the same period in the deep part of the basin. Due to the low mass fractions of U and Th elements or the low helium gas content of the desorbed gas in the basement sedimentary rock complexes, they cannot be regarded as the main source rocks for helium gas. The formation, migration and accumulation of helium gas in both areas are controlled by the source rocks and faults, and are closely related to the distribution of deep-seated fault zones. These findings provide a scientific basis for the further exploration and development of helium resources in the Weihe and northern Ordos basins.

With the development of fractured horizontal well technology, shale oil exhibits great exploration and development potential. Compared with conventional oil and gas reservoirs, shale reservoirs are characterized by extremely low porosity and permeability, abundant organic matter, strong stress sensitivity, well-developed laminated structure, and diverse fluid occurrence states. Previous studies on shale oil flow patterns have typically focused on individual characteristics, inevitably leading to an incomplete understanding. This study aims to further explore the coupling mechanism of different factors on the shale oil flow patterns, thereby providing theoretical support for the efficient exploitation of terrestrial shale oil.

A novel model was established to accurately characterize the oil flow patterns in shale reservoirs, integrating vertical heterogeneity and stress sensitivity of shale formation, as well as considering the adsorption-desorption effects of shale oil. The boundary conditions were simplified based on the shale oil reservoir properties to ensure both the calculation efficiency and accuracy. Taking laminated shale reservoirs—a primary target for exploitation—as a case study, the physical process of shale oil flowing from the matrix to the hydraulic fracture was investigated systematically using the proposed model. The seepage mechanism of shale oil during primary depletion was clarified, and the combined influence of vertical crossflow and formation stress sensitivity on the production of free oil and adsorbed oil was discussed. Subsequently, the proposed model was applied to the Paleogene Kong-2 member shale in the Cangdong Sag, revealing significant differences in oil production among different lithofacies and further predicting their respective production trends. Practical development strategies for shale oil were formulated based on lithofacies-dominated production characteristics.

Neglecting the vertical heterogeneity in shale formations and adsorption-desorption effects of shale oil may significantly distort simulation results, leading to inaccurate shale oil production predictions. Comprehensive analyses through numerical simulations and field case studies demonstrated that: (1) During the primary depletion, well-developed laminated structures enhanced shale oil recovery. Free oil primarily migrated through laminated channels, while adsorbed oil benefited from accelerated desorption within these structures. (2) In laminated shale reservoirs, free oil mainly migrated from the shale matrix to hydraulic fractures in shale layers, and it mainly exited through sand layers. This established shale layers as oil sources and sand layers primarily as flow channels. (3) The strong stress sensitivity of shale layers enhanced oil recovery, while that of sand layers exerted adverse effects, with shale layers dominating during mid-to-late production stages and sand layers influencing early stages most significantly. The proposed model accurately simulated the physical process of oil flowing from the shale matrix to hydraulic fractures. The simulation results showed strong consistency with field observations, validating the model’s applicability for shale formation development planning and optimization.

Numerical simulations investigated the shale oil flow patterns in laminated shale reservoirs by incorporating rock and fluid properties. The proposed model was utilized to characterize vertical crossflow and the desorption process of adsorbed oil in shale formations, while quantitatively evaluating the significant effects of laminated structure and stress sensitivity on shale oil production. These findings provide crucial insights for enhancing recovery in continental shale formations.

In the later stage of water injection development, the rapid increase in water content significantly degrades the development performance of water drive reservoirs. The non-uniform distribution and viscosity enhancement of polymer particle dispersed systems effectively reduce the water phase flow capacity that occupies the flow space of large pores, thereby mitigating inefficient and ineffective water circulation. Currently, studies on polymer particle dispersed phase for oil displacement are primarily based on laboratory simulations, focusing on the migration behavior of polymer particles. However, limited research has been conducted on the oil-water flow dynamics and relative permeability curves during the oil displacement process of polymer particle dispersed phase. This study first analyzed the non-uniform distribution of polymer particles in porous media and introduced the red blood cell dendritic volume fraction distribution theory from biological fluid dynamics. A viscosity characterization method was established, considering the effects of the polymer particle phase separation mechanism. Subsequently, a relative permeability model of polymer particle dispersed phase for oil displacement was developed based on fractal and percolation theories. The accuracy of the model was validated through comparisons with laboratory core displacement experiments, and the effects of various factors on the relative permeability of polymer particle dispersed phase for oil displacement were analyzed. This research holds significant value for assessing the development performance of polymer particle dispersed phase for oil displacement.

Shale gas, an unconventional natural gas resource, has become an important supplement to global conventional oil and gas resources. With the increasing development of shale gas resources, deep shale gas reservoirs have emerged as key targets for exploration and production. These reservoirs are characterized by complex geological structures, high rock plasticity, and significant vertical and horizontal stress differences. Such conditions hinder the formation of complex fracture networks during hydraulic fracturing, often resulting in simple, narrow, and long fractures. The narrow width of these fractures significantly affects the settlement and migration of proppants, which in turn influences fracture conductivity and determines the effectiveness of reservoir stimulation. Therefore, investigating the settlement and migration behaviors of proppants in long narrow fractures is essential for the safe and efficient production of deep shale gas wells. Current experimental studies on proppant migration commonly use parallel-plate simulation devices made of organic glass. Research indicates that proppant settlement and migration are substantially influenced by viscous fluid drag, with the drag coefficient depending on factors such as particle shape, concentration, and flow rate. Additionally, proppant type, density, and concentration further affect proppant distribution. However, most existing studies are based on the fracture geometries of medium and shallow shale reservoirs, which differ from those of deep shale formations in both fracture width and suitable proppant size. To address this gap, this study employed a large-scale visualized simulation device to examine the settlement and migration of proppants in long narrow fractures in deep shales. The objective is to clarify the effects of different proppant properties and fracturing parameters on proppant distribution, thereby providing theoretical support for fracturing stimulation in deep shale reservoirs. The experimental setup included a fracture simulation device, a mixing unit, and a circulation system. The fracture simulation device was composed of interconnected organic glass plates, with adjustable fracture widths between 2-3 mm to replicate the fractures in deep shale. Slickwater fracturing fluids were prepared with three viscosities: 3 mPa·s, 6 mPa·s, and 9 mPa·s. Selected proppants included 40/70 mesh, 70/140 mesh, and 100/200 mesh quartz sand, along with 70/140 mesh coated ceramic proppants, representing micro-sized particles. A total of 11 experimental groups were designed to investigate the effects of fracturing fluid viscosity, injection rate, proppant concentration, proppant particle size, proppant type, and fracture width variation. Experimental results indicated that, compared with the wider fractures of medium and shallow shales, under the same conditions, long narrow fractures in deep shale promote the agglomeration of proppant particles, causing a rapid settlement near the inlet. This led to a reduced leading-edge slope of the sand bank and a smaller height difference between the front and rear of the sand bank compared to wider fractures. The overall proppant distribution tends to be more uniform and smoother. In long narrow fractures of deep shale, the proportion of terminal sand bank area to the total sand bank area increases with higher fracturing fluid viscosity and injection rate, while the effect of proppant concentration is relatively limited. Micro-sized proppants are more prone to settling at the far end of the narrow fracture and contribute to a more uniform overall distribution. Moreover, the contraction of fracture width has no significant effect on sand bank placement before contraction, but it hinders the flow and placement of proppant particles after contraction, resulting in decreased proppant settlement. Due to the high closure pressure in deep shale reservoirs, fractures are prone to closure, and the reduction in proppant settlement after fracture contraction further increases the difficulty of effective fracture support. This experimental study reveals the settlement and migration patterns of proppants in long narrow fractures in deep shale, providing a theoretical foundation for optimizing fracturing simulation strategies. The findings have practical significance for selecting proppant types and optimizing fracturing parameters to enhance the production efficiency of deep shale gas wells.

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.