The oil-generating potential of the Upper Paleozoic coal-bearing strata in the Ordos Basin has long been underestimated. To clarify its genetic mechanisms and resource potential, this study conducted a systematic investigation of the coal-derived oil in the Benxi Formation from the Linxing and adjacent areas by integrating coal petrology, organic geochemistry, and fluid inclusion analysis. The results show that: (1) Liquid hydrocarbons in the Benxi Formation coals occur in two states: free and adsorbed. Free oil predominantly accumulates in tectonic microfractures and pores of ferroan carbonate minerals, which have very low capillary entry pressures, forming dominant storage and migration spaces. Adsorbed oil is hosted in the nano-scale intercrystalline pores of authigenic kaolinite aggregates, where its strong water-wetness causes significant capillary blocking and surface adsorption effects. (2) The genetic type of the coal-derived oil is identified as a primary high-maturity condensate-wet gas system, rather than a secondary cracked residual oil. (3) Oil-source correlation confirms that the crude oil is mainly derived from the Benxi Formation coals themselves. The hydrocarbon-generating precursors consist of hydrogen-rich aquatic algae-plankton input under a marine transgression background and terrestrial liptinite macerals (sporinite and cutinite). (4) The coal-derived hydrocarbons follow a sequential generation-evolution pathway, evolving from an early biogas stage, through a low-maturity oil window and a peak condensate-generation stage, to an oil-associated gas stage, and ultimately to a dry gas stage. (5) Rock-Eval and chloroform bitumen "A" data indicate that the coals in the study area are currently in the condensate oil-gas generation stage. It is suggested that the exploration and development strategy should shift from pure coalbed methane production towards integrated "coalbed methane-condensate oil" co-production. Priority should be given to fairways with vitrinite reflectance (Ro) between 0.7 and 1.3%, and pressure-controlled production should be adopted to delay the onset of retrograde condensation, thereby ensuring effective resource recovery.

The Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation are important target strata for shale gas exploration in the Sichuan Basin, China. In this paper, the sedimentary facies and palaeogeography of the two formations in Chongqing area have been analyzed, and total organic carbon (TOC) contents are correlated with the sedimentary facies to prospect the favorable areas for shale gas exploration. According to the lithological characteristics and sedimentary structures, five sedimentary facies are identified, i.e., siliceous deep-water shelf, muddy deep-water shelf, calcareous shallow-water shelf, muddy shallow-water shelf, and silty-muddy shallow-water shelf facies, respectively. The palaeogeography reconstruction is based on the lithological distribution in the study area. The lower part of Wufeng Formation was developed with the muddy deep-water shelf, siliceous deep-water shelf, and calcareous shallow-water shelf facies. The Guanyinqiao Member, representing the upper part of Wufeng Formation, was developed with the transition from siliceous deep-water shelf and muddy deep-water shelf facies to a domination of muddy shallow-water shelf and calcareous shallow-water shelf facies, which was deposited during the glacial-induced global regression. The Lower Member of Longmaxi Formation was characterized by the expansion of siliceous deep-water shelf facies and contraction of muddy shallow-water shelf and calcareous shallow-water shelf facies, signifying a rapid sea level rise associated with global warming. The Upper Member of Longmaxi Formation was developed with muddy shallow-water shelf facies, with the expansion of calcareous shallow-water shelf and silty-muddy shallow-water shelf facies. The shales with higher TOC content tend to be developed in the siliceous deep-water shelf and muddy deep-water shelf facies that were distributed in the Nanchuan, Shizhu, Yongchuan, and Wuxi areas. The results of lithofacies palaeogeography reconstruction have a certain significance to predict shale-gas target areas in Wufeng and Longmaxi formations of Chongqing.

Casing shear deformation,induced by frictional sliding along weak planes in shale formations,represents a critical constraint on the safe and efficient extraction of deep shale gas.To elucidate the frictional sliding characteristics and the associated mechanical response mechanisms,a temperature-pressure coupled triaxial friction testing system was employed.Shale specimens extracted from the Longmaxi-Wufeng Formations in the Sichuan Basin were tested under simulated in-situ reservoir conditions,with temperatures ranging from 100 to 160℃,confining pressures from 105 to 115 MPa,and pore pressures from 80 to 100 MPa.The effects of weak-plane inclination angle(30°and 60°),pore fluid composition(neutral water and acidic solution),and loading rate on the friction coefficient and critical slip pres-sure were systematically analyzed.The results indicate that temperature exerts a negligible influence on the friction coefficient;however,elevated temperature(160℃)substantially reduces the sliding stability of the weak planes.An increase in confining pressure significantly elevates the critical axial slip stress(from 125.94 MPa to 141.41 MPa for the 60° weak plane)but concurrently lowers the friction coeffi-cient(from 0.898 7 to 0.573 6)due to the enhanced effective normal stress,while the dispersion of the rate-dependent parameter(a-b)di-minishes with increasing confining pressure.Elevated pore pressure weakens the shear strength of the weak planes,with a maximum re-duction of 44.5%in the critical axial stress.Acidic solutions raise the threshold of the friction coefficient through mineral dissolution,yet they concurrently intensify sliding instability.The inclination angle governs the slip initiation behavior:the critical pore pressure for the 60° weak plane(94-96 MPa)exhibits negligible sensitivity to temperature variations,and high-angle weak planes are more prone to indu-cing casing shear deformation.In contrast,the 30°weak plane requires extreme mechanical conditions specifically,a confining pressure of 115 MPa and a pore pressure of 106 MPa to initiate slip,during which a creep-rupture competition mechanism is observed.The rate-de-pendent behavior of the friction coefficient was characterized;weak planes with high inclination angles predominantly exhibit velocity-strengthening behavior,whereas those with low inclination angles are susceptible to instability induced by decreasing loading rates.Based on these experimental findings,a series of casing protection and optimization strategies are proposed,including modulation of the friction coefficient(μ>0.5),geometric optimization of the wellbore trajectory(intersection angle with weak planes>50°),and staged fracturing pressure control(maintained below 96 MPa).These measures will provide a theoretical foundation for the safe and efficient development of deep shale gas resources.

To bridge the knowledge gap between the structural alignment and CH4 adsorption for anthracite, isotherm adsorption, high resolution transmission electron microscopy (HRTEM), and grand canonical monte carlo (GCMC) was conducted to clarify the extent of length, orientation, curvature, and stacking of PAH (polycyclic aromatic hydrocarbon), as well as the impact of orientation and curvature on CH4 adsorption. Structural alignment quantification indicated that PAH length was dominated by 0.25-1.0 nm (59-73 %, 65 % in average) with a high orientation degree of 54-60 % (56 % in average). The extent of PAH stacking is still rather low and the non-stacking PAHs account for similar to 84 % or more. There are more curved PAHs (60-74 %, 69 % in average) than straight ones. Isotherm adsorption and GCMC results suggested that PAH curvature was favorable to CH4 adsorption, however, the orientation of PAH has a negative relationship with maximum adsorption. The microporous size distribution from low-temperature CO2 adsorption (LTCO(2)GA) and molecular probe suggested that total microporous volume increases, however, the accessible volume decreases with the increasing PAH curvature. Thus, it could be concluded that the highest adsorption amounts of anthracite are caused by the joint impact of functional group evolution and extended PAH structural alignment. These outcomes do not only contribute to our understanding of methane storage mechanisms in high-rank coal, but also provide practical insights for optimizing coalbed methane recovery.

The Chang 7 Member of the Yanchang Formation in the Ordos Basin consists predominantly of airfall and water-borne tuff along with tuffaceous shale, which exhibit considerable hydrocarbon potential, yet their thermal evolution and hydrocarbon generation behaviors remain inadequately studied. As an emerging unconventional exploration target, this interval was investigated through systematic thermal simulation experiments utilizing a novel programmable dual-pressure constant-flow system, which enables precise control of fluid pressure and automated monitoring of hydrocarbon generation and expulsion processes under semi-open/semi-closed conditions. The study focuses on low-maturity, organic-rich massive tuff and laminated tuffaceous shale from Well Z40, revealing that although all samples are sedimentary in origin, the airfall tuffs are rich in vitric pyroclasts—including accretionary pellets (AP1)—while water-borne tuffs are dominated by feldspar crystal pyroclasts. Key findings demonstrate that massive tuff displays markedly higher hydrocarbon expulsion efficiency compared to laminated tuffaceous shale, with an earlier onset of expulsion and contributions derived from both kerogen cracking and heavy oil components. Thermal evolution analysis further indicates that massive tuff attains higher organic maturity under identical conditions. In laminated shale, expulsion efficiency correlates increases with TOC content, reflecting the role of organic matter in pore development and fluid connectivity. The superior expulsion performance of massive tuff is attributed to its higher volcanic glass content, low clay abundance, and dispersed organic matter distribution, which create highly efficient migration pathways. In contrast, laminated tuffaceous shale exhibits stratified organic matter closely associated with clay minerals, requiring higher thermal maturity (Ro > 0.6%) and elevated TOC to form an interconnected organic network that facilitates efficient expulsion. This study highlights that variations in pore structure, organic matter distribution, and thermal maturity represent the primary controls on differential expulsion efficiency between organic-rich tuff and tuffaceous shale in the Chang 7 Member, providing crucial insights for the exploration and development of shale oil in volcanic-lacustrine basins.

With the recent breakthroughs in deep coalbed methane exploration in the Ordos Basin, Upper Paleozoic coals are widely recognized as strongly gas-prone, whereas their oil-generating capacity has long been underestimated. However, abundant light oil has been repeatedly observed in flowback fluids from Benxi Formation coalbed methane wells in the Linxing and adjacent areas, indicating these coals can act as both effective source rocks and oil reservoirs. Integrating coal petrography, organic geochemistry, and fluid inclusion microthermometry, this study re-evaluates the condensate potential of these marine-continental transitional coals. Crucially, we demonstrate that the Benxi coals host a high-maturity, strongly self-sourced primary condensate-wet-gas system, fundamentally challenging the traditional view that they contain only severely cracked residual oil. Liquid hydrocarbons occur primarily in two modes: free oil within structural microfractures (providing the dominant migration pathways) and adsorbed oil immobilized by capillary blocking within kaolinite aggregates. More importantly, we reveal a distinctive oil-generation mechanism unique to marine-continental transitional facies. Unlike strictly continental coals dominated by higher plants, the principal oil-prone parent materials here are significantly enhanced by marine transgressions. The incorporation of transgression-derived aquatic algal-planktonic organic matter, alongside terrestrial hydrogen-rich liptinite, provides highly efficient, aliphatic-rich, and high-H/C precursors. This synergistic dual-source mechanism significantly boosts condensate generation, offering a new perspective on the hydrocarbon systems of transitional coals and broadening the exploration targets for coal-derived liquids.

Research on hydrocarbon accumulation mechanism in coal-measure whole petroleum systems and coal-rock gas exploration has revealed that coal-rock gas occurs along coal-bearing strata and forms different reservoir types with distinct geological characteristics in different structural regions, and that between primary coal-rock gas reservoirs and residual coal-rock gas reservoirs (i.e., traditional shallow coalbed methane reservoirs), the gas–water relationship in the macroscopic pores and fractures of coal reservoirs gradually evolves in space, forming coal-rock gas accumulation transition zones with prominent features. Taking the coal-rock gas of the Carboniferous Benxi Formation in the central-eastern Ordos Basin, China, as an example, this study constructs the dynamic mechanism and mathematical models for the coal-rock gas accumulation transition zone by considering the dual-medium structure, stress sensitivity, and wettability variation of coal reservoirs. On this basis, the dynamic equilibrium among buoyancy, capillary force and hydrocarbon-generation expansion force is clarified. The results show that, under the geological background of uplift and reworking, the cleat fracture system and porosity–permeability properties of coal reservoirs are fundamental for the formation of the transition zone, the hydrocarbon-generation expansion force of coal rocks is an inherent determinant for the depth of the transition zone, and the spatial variation of coal rank and tectonic reworking intensity control the distribution of the transition zone. Numerical simulation results and practical exploration and development have demonstrated that, at the eastern margin of the Ordos Basin, the transition zone for medium- to high-rank coal-rock gas reservoirs in the Daning–Jixian area in the south is mainly buried at 1 300–1 800 m, while the transition zone for low- to medium-rank coal-rock gas reservoirs in the north occurs at a greater depth of 1 500–2 300 m. Through comprehensive investigation, the coal-rock gas accumulation zones at the eastern margin of the Ordos Basin are examined by hydrocarbon accumulation evolution analysis and spatial distribution prediction. Three continuous hydrocarbon accumulation evolution units are identified, i.e. deep coal-rock gas accumulation zone, coal-rock gas accumulation transition zone, and shallow coalbed methane accumulation zone. The research results deepen the understanding of accumulation mechanism and differential enrichment mechanism of coal-rock gas, and provide a theoretical basis for improving coal-rock gas classification and guiding favorable area evaluation and efficient exploration and development.

Since 2021, CNPC have achieved breakthroughs in exploration and development by using horizontal multistage fracturing technology for natural gas in deep coal-rock reservoirs in the Junggar Basin, Ordos Basin and Sichuan Basin. Systematic analysis demonstrates that the natural gas in the coal-rock reservoir is a new type of natural gas resources, which is markedly distinct from the traditional coalbed methane (CBM). We define this natural gas in the coal-rock reservoir as coal-rock gas (CRG). The discovery of coal-rock gas completes the hydrocarbon accumulation sequence of coal measures as source rocks. Practical evidence indicates that natural gas such as ‘conventional gas, tight gas, coal-rock gas/coalbed methane’ is homologous in origin and exhibit regular spatial distribution, which is a new type of whole petroleum system. Significantly, we propose the whole petroleum system of coal measures. In this petroleum system, the coal-rock gas, CBM, tight oil and gas, conventional oil and gas are controlled by the coal-rock play, forming an orderly accumulation.

Since 2021, drawing on the volumetric stimulation techniques used in shale gas development, horizontal well multi-stage fracturing has been employed to achieve effective development of coal-rock gas (CRG). Coal, as a reservoir, has high organic content, low density, strong plasticity, and well-developed micro-pores and macro-fractures, forming a typical dual-porosity and dual-permeability structure. Coalbed methane (CBM) exists in an adsorbed state under groundwater pressure and requires long-term dewatering to reduce reservoir pressure below the critical desorption pressure for effective production. In contrast, coal-rock gas has a higher proportion of free gas. By artificially improving reservoir connectivity, free gas is produced through the release of elastic potential energy. As reservoir pressure decreases, adsorbed gas desorbs and supplements production, enabling effective development. From the production curve characteristics of gas wells, the casing pressure and cumulative gas production of horizontal wells exhibit a typical linear relationship in the early stage, indicating that free gas in the reservoir is produced through the release of elastic potential energy. The mid-to-late production period is characterized by a long production cycle.

Marine-continental transitional (MCT) shale gas is an important successor of unconventional natural gas resource in China. Based on integrated analyses of published data including outcrop investigation, exploration practice, drilling cores, and experimental testing, the recent progresses of both global and domestic shale gas development were systematically reviewed and compared, and we further examined the exploration progress and challenges of MCT shale gas in the Ordos Basin, Sichuan Basin, and their adjacent areas, and conducted a comprehensive discussion of the key geological conditions for the formation of shale gas and its resource potential, challenges, and counter measures. The results show that MCT shale in China is mainly developed within the Carboniferous–Permian strata (Benxi, Shanxi, and Longtan formations), dominated by lagoon, swamp, and tidal flat facies, and possesses favorable conditions for shale gas formation and development potential. They mainly include the generation and storage of shale gas as follows: (1) The organic-rich intervals are thick and widespread, dominated by Type III organic matter with high total organic carbon (TOC) content (⩾3.0

Here, macromolecular representation and CO2-CH4 competitive adsorption properties of mylonitic coal (MC) were revealed based on 13C nuclear magnetic resonance, Fourier transform infrared spectroscopy, high-resolution transmission electron microscopy, and grand canonical Monte Carlo simulation. Results suggested that MC has a higher content of aromatic carbon, non-protonated aromatic carbon, and alkyl-substituted aromatic carbon compared with primary coal (PC). There were much longer aliphatic chains and lower branching degrees for MC than PC. The basic structural units of MC were characterized by a higher percentage of longer aromatic fringes (>1 nm) with higher structural alignment (38–48%, 41% in average) than PC (31–38%, 35% in average). Molecular probe results suggested that MC has more free volumes than PC at a given occupied volume. Single adsorption of CO2 and CH4 revealed a higher saturation adsorption capacity of CO2 and CH4 and more predominant energy reduction of MC. Competitive selectivity of CO2 over CH4 (SCO2/CH4) was >1, indicating the adsorption advantages of CO2 over CH4. At pressures of <3.0 MPa, the SCO2/CH4 of MC was higher than PC. For pressures of 3~4 MPa, they were close, indicating that the competitive adsorption advantages of CO2 over CH4 become weak at higher pressures for MC reservoirs. For temperature dependence, it decreases with the increasing temperature, suggesting that high temperature could exert a more significantly unfavorable impact on CO2 adsorption than for CH4 adsorption. Both the swelling ratios decrease with the increasing temperature for PC and MC; however, that of MC was higher than that of PC, suggesting that MC possess stronger swelling deformation at a given temperature. The outcomes of this paper indicated that compared with PC, the higher tendency of gas outburst for the MC zone was jointly controlled by a higher proportion of large aromatic fringes, more extensive development of structural defects, higher specific surface area of micropores, and stronger adsorption affinity of CH4. Competitive adsorption results suggested that MC reservoirs are more favorable for CO2-ECBM engineering than those of PC.

The evolution of coal molecular structure is accompanied by the formation of pores that control the capacity for methane adsorption. However, the evolution of the coal molecular structure, pore formation mechanism and the adsorption capacity of methane for different chemical groups remain unclear during the coalification process. In this study, the High Resolution Transmission Electron Microscopy (HRTEM) experiment has been used to explore the evolution of aromatic fringes during the coalification process. The C-13 Nuclear Magnetic Resonance (C-13 NMR) and Fourier Transform Infrared (FT-IR) spectroscopy have been employed to analyze the aromatic structures, aliphatic side chains and different chemical groups in coal molecules. The low pressure N-2 and CO2 adsorption experiments are used to determine changes in pore volume and surface area. Combined with molecular simulations, the methane adsorption capacity of different chemical groups was investigated. The results indicate that small aromatic rings (e.g., naphthalene, 2 & times; 2 and 3 & times; 3 aromatic rings) gradually decrease during coalification, while small molecular structures, including methane, ethane and butane, will be apparent. Concurrently, some small aromatic rings drop off from the coal molecule and subsequently reconnect, evolving into larger aromatic rings (4 & times; 4, 5 & times; 5, 6 & times; 6, 7 & times; 7, 8 & times; 8 and > 8 & times; 8 aromatic rings). Besides, the micropores volume and surface area increase from 0.024 cm(3)/g and 69.913 m(2)/g to 0.068 cm(3)/g and 226.800 m(2)/g, whereas the mesopores/macropores volume and surface area decrease from 0.019 cm(3)/g and 2.810 m(2)/g to 0.005 cm(3)/g and 1.270 m(2)/g in coal. The adsorption capacity of methane in slit pore models with different types of chemical groups is ranked from largest to smallest as follows: aromatic rings, oxygen-containing functional groups (-OH and -COOH), and methyl and methyl-methylene functional groups (-CH3 and -CH2CH3). The maximum adsorption amount (aromatic rings) is 1.5 times that of the minimum adsorption amount (-CH2-CH3). This study demonstrates that during the coalification process, the coal molecular structure determines the evolution of the pores and methane adsorption capacity by controlling the evolution of aromatic rings.

Geological outcrops serve as natural laboratories for fracture systems, offering indispensable calibration data for subsurface reservoir modeling due to their multi-scale and multi-genetic fracture characteristics. However, traditional outcrop-based fracture identification methods often suffer from low efficiency, limited data resolution, and challenges in fracture parameter characterization. To address these issues, this study proposes an intelligent fracture identification approach that integrates unmanned aerial vehicle (UAV) oblique photogrammetry, three-dimensional laser point cloud modeling, and convolutional neural networks (CNN). Based on high-precision fracture identification results, key fracture parameters, including orientation, length, development density, and connectivity, are quantitatively characterized. A multi-scale discrete fracture network (DFN) probabilistic model is then constructed using Monte Carlo stochastic simulation. The results demonstrate a breakthrough in centimeter-scale fracture identification accuracy and modeling efficiency, achieving an intelligent fracture identification success rate of over 80% and improving identification efficiency by 50%. This method provides robust support for the quantitative characterization of outcrop fractures and enhances the accuracy of indoor fracture prediction.

Coalbed methane primarily exists in coal seams in both adsorbed and free states. Due to factors such as formation pressure, coal properties, and reservoir conditions, shallow CBM reservoirs are dominated by adsorbed gas, with minimal free gas content. In contrast, deep coal seams contain more than 50

The occurrence states of water in coal, particularly as water films and water bridges, exert a significant influence on coalbed methane production. However, its role in gas storage and production in deep coal reservoirs remains unclear. In this study, scanning electron microscopy and low-pressure CO2/N-2 adsorption experiments were conducted to obtain pore structure characteristics, followed by methane adsorption experiments with different relative humidity levels to investigate the water-induced variation in methane adsorption capacity. Using C-13 nuclear magnetic resonance and Fourier transform infrared spectroscopy experiments, the three-dimensional molecular structure model of the Suide coal sample was constructed. Subsequently, molecular dynamics simulations were employed to build methane-water interaction models and calculate effective diffusion coefficients and production efficiencies. The results reveal that the spatial distribution and formation of clusters of water molecules on pore surfaces are affected by water content. In the first stage (S-w = 2.52%-6.79%, 2.58%-7.14%, and 2.53%-6.75% in the 1, 2, and 4 nm pores, respectively), the water molecules adhere to the surface of the pore walls and begin to gather to form water clusters. In the second stage (S-w = 6.79%-22.59%, 7.14%-23.81%, and 6.75%-20.81% in the 1, 2, and 4 nm pores, respectively), water clusters form continuous films along the pore surfaces by coming together. In the third stage (S-w = 22.59%-37.75%, 23.81%-36.34%, and 20.81%-37.59% in the 1, 2, and 4 nm pores, respectively), the water molecules form two states, known as the water films and the water bridges, in the 1 nm pores. The water bridge gradually disappears in the 2 and 4 nm pores. These water structures restrict methane transport. First, a few water molecules form clusters, resulting in a gradual decrease in the efficiency of methane production from 37.48% to 36.38% at S-w = 0-2.58%. Conversely, many water molecules combine with each other to form a film, and the efficiency of methane production increases from 37.48% to 46.10% at S-w = 7.14%-23.81%. The formation of water bridges limits the migration of methane molecules by blocking the pore tunnels, thereby decreasing the efficiency of methane production from 46.10% to 5.70% at S-w = 23.81%-43.01%. This study provides insight into how water films and water bridges form in coal and reveals their effect on methane storage and production.

The Ordovician-Silurian transition represents a critical period marked by the formation of marine shale gas horizons within the South China Block. However, the mechanism for organic matter enrichment of Paleozoic marine shales in the western South China Block remain contentious, primarily due to insufficient understanding of paleogeomorphological evolution. In this paper, we describe the sedimentology of the Ordovician-Silurian succession composed of the Wufeng-Longmaxi Formation in the western South China Block and report new paleontological, and geochemical data for this succession to explore the relationship between basin paleogeomorphology and water mass environment. Nine graptolite zones are identified, spanning from the WF1 (Linxiang Formation) through WF2-WF4 (Wufeng Formation) to LM1-LM5 (Longmaxi Formation) in this well. Based on sedimentological and geochemical analyse results, three distinct stages of redox and paleoproductivity conditions in the water mass have been identified: (1) suboxic environments and low paleoproductivity in WF2-WF4; (2) euxinic and stagnant water conditions in LM1-LM3 accompanying with high paleoproductivity; and (3) anoxic water and low paleoproductivity in LM4-LM5. By integrating marine redox fluctuation, paleoproductivity conditions and regional hiatus (LM1-LM3) observed across multiple successions, we interpret thatthe western margin of the South China Block have been significantly affected by a collision between the South China Block and Yanbian terrane. The results of this study indicate that the accumulation of organic matter in the western margin of the South China Block was predominantly controlled by paleogeomorphology being caused by this collision event.

Accurately predicting the content of adsorption gas and free gas in nanopore structures, as well as the dynamic production of adsorption gas and free gas, is of great importance for the production of coalbed methane wells. However, the storage and transport of adsorption gas and free gas in different nanopores are still unclear. In this study, the molecular adsorption simulation results and pore size distribution data were combined to calculate the amounts of adsorption gas and free gas in different pore sizes of the coal sample. The molecular mechanism for the adsorption gas and free gas in tunnels of different sizes during the transport behaviors is proposed. The results indicate that in pore sizes smaller than 1 nm, the amount of adsorption gas is 18.85 cm(3)/g, which is up to 74.31% of the total amount of adsorption gas, hardly any free gas is present. At 1-2 nm pores, the amount of adsorption gas is 4.14 cm(3)/g, and then the amount of free gas is 1.20 cm(3)/g, which provides about 71.59% of the total amount of free gas. In other types of pores (2-5, 5-10, and >10 nm), the amounts of adsorption gas are 0.30, 0.23, and 0.17 cm(3)/g and the amounts of free gas are 0.05, 0.07, and 0.35 cm(3)/g, respectively. By transport simulation, a molecular mechanism for the adsorption gas and free gas in tunnels of different sizes during the transport behaviors was provided. In the first stage, with more free methane molecules stored in the macropores and fractures expelled from the coalbed, the gas production from coalbed methane wells has risen sharply at the beginning of the stage. Subsequently, the dramatic depletion of free methane molecules results in the desorption and migration of adsorption methane molecules. In the second stage, more adsorption gas is desorbed and migrates into the micropores, thereby providing a stable increase in gas production. In the last stage, only a small amount of free gas is initially stored in the macropores and fractures and the adsorption gas desorbs from the micropores and begins to slowly migrate through different size tunnels; the gas production in coalbed methane wells will gradually decrease.

Gas-bearing shales have become a major source of future natural gas production worldwide. It has become increasingly urgent to develop a reliable prediction model and corresponding workflow for identifying shale gas sweet spots. The formation of gas-bearing shales is closely linked to relative sea-level changes, providing an important approach to predicting sweet spots in the Wufeng-Longmaxi shale in the southern Sichuan Basin, China. Three types of marine shale gas sweet spots are identified in the shale based on their formation stages combined with relative sea-level changes: early, middle, and late transgression types. This study develops a prediction model and workflow for identifying shale gas sweet spots by analyzing relative sea-level changes and facies sequences. Predicting shale gas sweet spots in an explored block using this model and workflow can provide a valuable guide for well design and hydraulic fracturing, significantly enhancing the efficiency of shale gas exploration and development. Notably, the new prediction model and workflow can be utilized for the rapid evaluation of the potential for shale gas development in new shale gas blocks or those with low exploratory maturity.

In recent years, extensive low-resistivity shale reservoirs have been discovered in the Sichuan Basin, especially in the Lower Cambrian Qzs Fm (Qiongzhusi Formation). However, significant variations in gas production from these low-resistivity reservoirs across different regions have posed challenges in selecting and predicting sweet spots for the exploration and development of shale gas. Therefore, the shale samples were subjected to the analysis of a series of experiments, including core resistivity measurements, thermal simulations, and Raman spectroscopy, in order to explore the genesis mechanisms behind low-resistivity shale reservoirs and analyze their response characteristics to pore structure. The results show that HMG-OM (highly mature graphitized organic matter) and formation water stored in pores and fractures provide more conductive pathways, which are the primary mechanisms driving the low-resistivity characteristics of shale within the study area. As graphitization increases, shale resistivity significantly decreases, while maturity increases. Additionally, there are notable changes in the shale mineral composition and pore structure, including quartz breakage, clay minerals transforming into quartz, feldspar, and other minerals, and the dissolution of calcite and pyrite, which leads to a significant increase in inorganic pores. Meanwhile, the graphitization of OM causes the continuous deformation, shrinkage, and collapse of OM pores, resulting in poor development of OM pores. In this study, we integrate theoretical analysis and the experimental results and identify the Weiyuan-Ziyang area in southwestern Sichuan as a key area for future shale development in the Qzs Fm, with the aim of providing theoretical guidance for the exploration and development of shale gas in the Sichuan Basin.

The formation and distribution of sedimentary facies of the Wufeng Formation reflect the evolution of Guangxi Movement and significantly impact shale reservoir quality in southern Sichuan Basin, China. This study characterizes the sedimentary facies and their evolution of Ordovician-Silurian transition shale based on detailed core descriptions, full-scale imaging of large slabs, and field emission scanning electron microscopy of argon-ion polished sections. There only exist fine-grained turbidite deposits, hemipelagic deposits, and shallow shoal deposits for the Wufeng shale. Fine-grained turbidite deposits consist primarily of clastic quartz and clay minerals and can be divided into nine subdivisions. Hemipelagic deposits are mainly composed of quartz, detrital carbonate, and clay minerals. Shallow shoal deposits are dominated by clay minerals, dolomite, and calcite, with carbonates primarily of autochthonous origin. The fine-grained turbidite deposits predominantly occur within the Dicellograptus complanatus and D. complexus graptolite biozones, while hemipelagic deposits are confined to the Paraorthograptus pacificus biozone, and shallow shoal deposits are restricted to the Metabolograptus extraordinarius biozone. Formation and distribution of the three sedimentary facies are closely related to the Guangxi Movement. During the strong tectonic compression stage, sufficient sediment supply and intensive volcanic eruption favored the formation of the fine-grained turbidite deposits. Along with waning tectonic activity and reduced terrestrial input, hemipelagic deposits formed and then shallow shoal deposits. Sedimentary facies exert first-order controls on shale reservoir quality, with hemipelagic deposits exhibiting optimal reservoir characteristics. Laboratory analyses reveal that hemipelagic facies possess the highest porosity (3.34–4.15%) and TOC content (2.91–4.10%) due to biogenic quartz enrichment and minimal allochthonous dilution, whereas fine-grained turbidites show degraded properties (porosity: 1.58–3.81%; TOC: 0.15–2.6%) from high-energy siliciclastic influx. Shallow shoal deposits display intermediate values (porosity: 3.92%; TOC: 3.25%), constrained by carbonate cementation.