In this study, carbon molecular sieves (CMS) were functionalized with bismuth species via a solvothermal method to obtain two high-temperature suitable adsorbents, Bi0/CMS and Bi2S3/CMS. XRD results suggest that CMS remainds its carbon framework features after exposured to LiF–BeF2 molten salt or irradiated by 60Co γ‑ray, supporting its applicability as a robust porous host. The surface area of Bi0/CMS and Bi2S3/CMS was proved to 306 and 367 m2g−1 due to the nanospherical Bi0 and needle‑like Bi2S3 structure, respectively. In molten LiF-BeF2-LiI at 923 K, Bi0/CMS and Bi2S3/CMS achieved rapid iodide removal with uptake capacities of 318 and 472 mg g−1, and the kinetic profiles were well described by pseudo‑second‑order fitting. Based on both the high operating temperature and an inventory-constrained analysis of the Bi loading, a sequential capture–volatilization pathway iodide removal was further proposed, in which iodide was first captured in CMS pores and at Bi sites, then converted into volatile BiI3 and left from salt phase. Radioactive experiments further proved that Bi2S3/CMS decreased the 131I activity in molten salt with a decontamination factor (DF) of approximately 960 at the final point (decay-corrected). This work highlight Bi-functionalized porous carbons for halide control in complex molten environments via a thermally driven converter-type concept.

High-viscosity, low-mobility reservoir bitumen is widely distributed in the Jurassic Qigu Formation sandstones in the Yongjin area of the Junggar Basin, yet its characteristics and impact on reservoir quality and free fluid saturation (FFS) remain poorly understood. This study integrates thin-section petrography, porosity-permeability measurements, nuclear magnetic resonance (NMR), and high-pressure mercury injection capillary pressure (MICP) analyses to investigate the petrological characteristics, pore structure, and reservoir bitumen occurrence in these sandstones. Porosity, permeability, and FFS were quantified before and after extraction to evaluate the influence of reservoir bitumen on reservoir quality and FFS. Results indicate that Reservoir bitumen, occupies 5.25% to 19.51% of the rock volume and occurs in solid, semi-solid, semi-plastic and plastic states, with occurrences including pore-filling, pore-coating, droplet-shaped accumulations and bitumen-light oil mixtures. The presence of reservoir bitumen significantly reduces reservoir quality and FFS, resulting in average reductions of 3.23% in porosity (a 35.3% relative decrease), 0.20 mD in permeability (a 52.6% relative decrease), and a decline in FFS from 63.9% (post-extraction) to 35.5% (pre-extraction). The extent of reduction varies considerably, with pore-filling bitumen causing the strongest reduction, followed in decreasing order by pore-coating bitumen, and bitumen-light oil mixtures. These variations are controlled by the physical properties and occurrence of the bitumen, as well as the host pore structure. A conceptual model is proposed to illustrate the distribution of different reservoir bitumen and their differential effects on reservoir quality and FFS. This study provides significant insights into the heterogeneous effects of reservoir bitumen on pore system quality and fluid mobility in Qigu Formation, offering a scientific basis for resource assessment, development strategy optimization, and risk mitigation in the deep to ultra-deep bitumen-bearing reservoirs in the Yongjin area.

The molecular structure of coal critically governs microbial adsorption, enzymatic depolymerization, and downstream metabolic regulation, directly determining methane yield during lignite degradation. However, systematic insights into its dynamic structural evolution remain limited. This study investigates lignite from the Jirgalangtu Sag via elemental analysis and molecular characterization to unravel coal molecular structure evolution under microbial degradation. Results reveal that aromatic hydrocarbons, aliphatic hydrocarbons, and heteroatomic functional groups decreased exponentially over time, whereas carboxyl, hydroxyl, and oxygencontaining aliphatic structures initially increased before declining. Biodegradation progressed through rapid and slow degradation phases, transitioning from molecular backbone degradation to oxygen-containing functional group decomposition. During the rapid degradation phase, the relative abundances of carbonyl (initially 16.99 %) and -CHI (initially 3.69) showed the most pronounced reductions (54.66 % and 42.98 %, respectively), Concurrently, methylene aliphatic (initial 24.80 %) and aromatic structures (initial 64.49 %) in the carbon backbone exhibited relative reductions of 28.04 % and 11.52 %, respectively. This rapid cleavage of aromatic, aliphatic, and oxygen-containing functional groups generated abundant metabolic intermediates that facilitated methanogenic pathways. As exogenous carbon sources were depleted and microbial activity declined, the system transitioned to the slow degradation phase. During this phase, carboxyl groups (initial 11.93 %) displayed a 52.27 % relative reduction, hydroxyl groups (initial 51.83 %) decreased by 12.91 %, and oxygen-containing aliphatic structures (initial 16.38 %) declined by 22.10 %. Microbial efficiency in converting aliphatic and oxygen-containing structures underpinned high methane yields. These findings advance theoretical frameworks for optimizing lignite bioconversion and enabling sustainable energy utilization.

Reservoir geological modeling plays a crucial role in characterizing the spatial distribution and heterogeneity of subsurface reservoirs. The exploration of deep oil and gas resources is not only a global trend in the oil industry but also an inevitable choice for China to ensure energy security and achieve sustainable development in the oil and gas industry. Oil and gas exploration and development technologies have also made continuous breakthroughs, providing strong support for the sustained increase in China’s deep and ultra-deep oil and gas production. Deep and ultra-deep oil and gas reservoirs exhibit high levels of heterogeneity, which are governed by the original sedimentation processes and have a significant impact on oil and gas migration and accumulation. However, traditional pixel-based stochastic reservoir modeling encounters challenges when attempting to effectively simulate multiple facies simultaneously or objects with intricate internal hierarchical architectures. To address the characterization of highly heterogeneous deep and ultra-deep oil and gas reservoirs, this study defines unit architecture bodies, such as point bars, braided rivers, and mouth bars, incorporating internal nested hierarchies. Furthermore, a novel object-based stochastic modeling method is proposed, which leverages seismic and well logging interpretation data to construct and simulate reservoir bodies. The methodology is rooted in the unit element theory. In this approach, sedimentary facies models are stochastically constructed by selecting appropriate unit elements from a database of different sedimentary environments using Sequential Indicator Simulation. The modeling process is constrained by time sequence, event, and sedimentary microfacies distributions. Additionally, the porosity and permeability of each microfacies in the reservoir model are quantitatively characterized based on statistics derived from porosity and permeability data of different strata, sedimentary microfacies, and rock facies in the study area. To demonstrate the superiority and reliability of this novel modeling method, a modeling case is presented. The case utilizes braided river unit elements as objects for the stochastic simulation of the target reservoir. The results of the case study highlight the advantages and robustness of the proposed modeling approach.

The pathways and mechanisms of primary hydrocarbon migration, which are still not well understood, are of great significance for evaluating both conventional and unconventional oil and gas resources, understanding the mechanisms of shale oil retention, and predicting sweet spots. To investigate the petrography, geochemistry, and pore systems of organic-rich mudstones and organic-lean sand-silt intervals in core samples from the Yanchang shale in the Ordos Basin, China, we conducted thin-section observation, X-ray diffraction, Rock-Eval pyrolysis, field emission scanning electron microscopy (FE-SEM), and porosity analysis. Sand-silt intervals are heterogeneously developed within the Yanchang shale. The petrology, mineral composition, geochemistry, type, and content of solid organic matter as well as the pore type, pore size, and porosity of these intervals differ significantly from those of mudstones. Compared with mudstones, sand-silt intervals typically have coarser detrital grain sizes, higher contents of quartz, feldspar, and migrated solid bitumen (MSB), larger pore sizes, higher porosity, and higher oil saturation index (OSI). In contrast, they have lower contents of clay minerals, total organic carbon (TOC), free liquid hydrocarbons (S1), and total residual hydrocarbons (S2). The sand-silt intervals in the Yanchang shale serve as both pathways for hydrocarbon primary migration and “micro reservoirs” for hydrocarbon storage. The interconnected inorganic and organic pore systems, organic matter networks, fractures, and sand-silt intervals form the hydrocarbons’ primary migration pathways within the Yanchang shale. A model for the primary migration of hydrocarbons within the Yanchang shale is proposed.

Coal-and-gas outbursts represent a significant hazard in coal mining, with gas expansion energy (GEE) in coal seams being a primary energy source. Accurate GEE assessment is vital for outburst prediction and mitigation, thereby enhancing mining safety. Traditional calculation models have struggled with limited understanding of outburst mechanisms and experimental constraints, leading to broad GEE estimates with considerable discrepancies. Addressing this gap, this study introduces an experiment-driven, highly practical calculation model, along with innovative experimental methods to measure accurately key determinants of GEE: fracture porosity, CH4 desorption amount, and gas pressure in coal seams. For the first time, this study employed remade and raw coal columns as media to simulate accurately the real conditions of tectonic and raw coal seams for exploring the coupling effects of stress and gas pressure on GEE. This study calculated the GEE as stress increases from 5 to 50 MPa and gas pressure decreases from 2 to 0.5 MPa. The results indicate that, for two remade coal columns, the GEE decreased from 1870 to 62 kJ/t and from 2039 to 356 kJ/t while for the raw coal column, the GEE dropped from 130 to 6 kJ/t.

The Ordos Basin is characterized by abundant natural gas resources, and the marine-continental transitional shale gas of the Permian Shanxi Formation has great exploration and development potential. However, few systematic studies have focused on the burial history, thermal maturity, and hydrocarbon generation of the shale, which limits the understanding of shale gas enrichment and resource evaluation. To reveal the shale gas resource potential, we focused on the Shanxi Formation shale in the southeastern Ordos Basin. Net erosion was estimated, and then one-dimensional (1D) and three-dimensional (3D) geological models were constructed using PetroMod to simulate the burial-thermal history and hydrocarbons generated in the Shanxi Formation shale, and finally, the gas generation intensity was evaluated. The results show that four periods of uplift and erosion events have occurred in the study area since the Mesozoic, of which the erosion in the Late Cretaceous was the most severe. The burial center gradually shifted from east to northwest in the study area, and the basin reached the maximum burial depth in the Late Cretaceous and then gradually changed to a monoclinal tilted east to west after uplift and erosion. The Shanxi Formation shale reached the hydrocarbon generation threshold at 233 Ma (R-o = 0.5%), reached the oil generation peak at 200 Ma (R-o = 1.0%), and entered the high maturity stage rapidly (R-o = 1.3%). Currently, the average maturity is approximately 2.48%, which is in the overmature stage. The center of shale maturity was in the southern part of the study area before the Late Jurassic and shifted northeast in the late Early Cretaceous. Cumulative gas generated to date is 44.0 x 10(12) m(3), and the center of gas generation was in the middle-eastern region of the study area before the Early-Middle Jurassic and shifted northwest in the Early Cretaceous. This study provides a theoretical basis and guidance for the exploration and development of marine-continental transitional shale in the Ordos Basin.

Coalbed methane adsorption isotherms are crucial tools for characterizing the gas adsorption capacity, playing a crucial role in accurately predicting actual methane adsorption in coalbed. Pore information on coal samples was acquired through low-pressure N-2/CO2 adsorption measurements. By employing adsorption models grounded in micropore filling and surface coverage coupled with the adsorbed phase volume method, the adsorbed phase density was calculated. Ultimately, the results were validated through high-pressure adsorption experiments. In order to investigate the influence of adsorbed phase density on excess adsorption, the methane adsorption data are subjected to corrected analysis. Results show that the calculated adsorbed phase density is 0.36 g/cm(3). In methane adsorption experiments at 6 MPa, the variation in the adsorption amount between the corrected absolute adsorption and excess adsorption for four coal sample groups ranged from 0.013 to 3.641 cm(3)/g, indicating significant differences between the two. In adsorption experiments at 20 MPa, the Langmuir volumes obtained from the absolute adsorption data in four different pressure intervals were 39.83-48.51 cm(3)/g, 20.06-29.08 cm(3)/g, 21.85-27.15 cm(3)/g, and 21.32-24.48 cm(3)/g, respectively, indicating that selecting various pressure intervals significantly influences the Langmuir volume. From the slopes of the adsorption curves, the slope of the adsorption points for AN, HV, and JD coal samples increased at pressures of 17.06, 15.63, and 12.04 MPa, respectively, while DT coal samples exhibited an almost constant slope at 14.05 MPa, deviating from the inherent adsorption characteristics of the adsorbent. Therefore, only the absolute adsorption data from the continuously decreasing segment of the slope were chosen for fitting, resulting in Langmuir volumes ranging from 23.73 to 44.16 cm(3)/g. This study provides an accurate method for determining adsorbed phase density values and criteria for selecting pressure ranges for absolute adsorption calculations, which is a significant theoretical guidance for reserve estimation.

A combination of physical and numerical simulations is employed to compare the differences in desorption deformation and desorption volumes of coal samples under varying depressurization paths, aiming to understand their impact on coalbed methane (CBM) extraction. In this work, two medium-rank coal samples from the central-eastern region of the Qinshui Basin were chosen for the desorption–strain experiments. The experiment facilitated real-time observation of desorption gas volumes and coal matrix deformation under various depressurization paths. Finite element analysis was utilized to model and analyze the evolution of pore pressure during depressurization and desorption. The research outcomes indicate a dependency of desorption gas volumes on the chosen depressurization path. With the slow depressurization path, the desorption gas volume over 12 h was 8

Through the optimization of tool parameters and the wedge shape, titanium alloy workpieces free of internal and external defects were formed by flat cross wedge rolling (CWR) adopting tools without surface grooves. Firstly, the thermomechanical coupled model of CWR for TC11 (Ti-6.5Al-3.5Mo-1.5Zr-0.3Si) titanium alloy was established in the finite element (FE) software DEFORM-3D, and the effects of forming angle α, stretching angle β, and section reduction Ψ were studied. The results showed that in the conventional empirical range of tool parameters, the defect-free workpiece is hard to be rolled by the typical tool structure. To optimize the forming quality of rolled workpieces, a modified tool structure was proposed by introducing an inclined plane with a width of λ (2–5 mm) on the top of the wedge shape and revising the side wedge plane α to a combination of two inclined planes α1 and α2 (α ≥ α1 > α2). Simulations and experiments demonstrated that the modified tools without surface grooves can achieve TC11 alloy workpieces with smooth surface. When the distance between the top and bottom tools is too large, the rolled workpiece axis is prone to being bent, and the gap from the top tool to the billet should be controlled in the range of 0–0.2 mm to ensure its straightness. Finally, the necking-free TC11 alloy rolled workpieces (Ψ = 67.9

To investigate the implications of insufficient creep on deformation energy of tectonic coal under hydrostatic pressure, hydrostatic single and graded cyclic loading-unloading tests and graded creep experiments under varying stress gradients were conducted, deriving the following conclusions. Coal specimens under constant hydrostatic pressure exhibit a lab-unattainable ultimate creep strain corresponding to sufficient creep. The generalized Kelvin model can roughly describe coal creep behaviour in lab. Insufficient or absent creep results in a bending-down phenomenon in the deformation energy curve when beyond 76.41% similar to 82.45% of the maximum stress. With increasing creep, deformation energy for coal samples increases by 0.29% similar to 2.79%. A correction term incorporating stress and creep strain is introduced and exhibits a slow-then-fast growth trend with increasing creep strain, stabilizing at 1 after coal specimens experience full creep or reach critical stress. Original nonlinear model approximately characterizes the deformation energy of coal in actual geological formations, providing guidance for on-site production.

CO2-ECBM 2-ECBM (Enhanced Coalbed Methane recovery) offers the dual benefits of increasing methane production and reducing carbon emissions through sequestration. Previous studies have primarily focused on the competitive adsorption effects of different gas compositions during the CO2-ECBM. 2-ECBM. However, the dynamic changes in desorption volume, desorption strain, and gas composition for different compositional ratios of CO2/CH4 2 /CH 4 after injecting CO2 2 remain unclear. Therefore, high-volatile bituminous coals from the southern margin of the Junggar Basin are chosen for desorption experiments with five different compositional ratios of CO2/CH4. 2 /CH 4 . Desorption volume, desorption strain, and gas composition of the coal samples are monitored during the desorption process. Finally, the mechanism influencing the dynamic changes in gas composition during desorption is analyzed. The results indicate that as CO2 2 concentration increases, both desorption volume and desorption strain correspondingly increase. At the same desorption volume, a higher CO2 2 concentration results in greater desorption strain. For different compositional ratios of CO2/CH4, 2 /CH 4 , CH4 4 concentration gradually decreases while CO2 2 concentration gradually increases over desorption time. The concentration of the desorption gas is influenced by the initial CO2 2 concentration and the pore structure. Specifically, higher initial CO2 2 concentrations, better pore opening, and more developed mesopores and macropores lead to greater changes in composition concentrations during desorption. Different concentrations of CO2 2 all promote CH4 4 production, with higher CO2 2 concentrations enhancing CH4 4 production efficiency more significantly, especially for samples that are more difficult to produce. The research findings can provide guidance for the efficient production of CBM after CO2 2 injection.

The key to the variation in permeability within coal reservoirs lies in the stress-induced deformation and desorption-induced deformation during the coalbed methane (CBM) production. The differences in sample scale and measurement methods between stress-induced deformation and desorption-induced deformation significantly affect the accuracy of permeability measurements. Therefore, in order to elucidate the relationship between stress-induced deformation and adsorption-induced deformation, as well as the influencing factors, and to assess the accuracy of permeability evolution prediction, this study conducted a series of parallel experiments, including compression deformation experiments under stress loading (stress-induced deformation), methane adsorption-induced deformation experiments (adsorption-induced deformation), μCT scanning, and overburden permeability measurements.The results of the study indicate that stress-induced deformation and adsorption-induced deformation are negatively correlated but exhibit a relatively weak correlation. Stress-induced deformation encompasses deformation of coal matrix, minerals, and fractures, whereas adsorption-induced deformation primarily reflects coal matrix deformation. While there is some overlap between the two, they are not entirely identical. The main influencing factor of stress-induced deformation is the mechanical strength of coal, with minerals in coal increasing the Young's modulus of coal reservoirs. Among them, minerals that are more dispersed and have smaller particles have a more significant impact on stress-induced deformation. The primary influencing factor of adsorption-induced deformation is the deformation capability of the coal matrix, with minerals and fractures having less significant effects. Permeability changes are controlled by fracture deformation, but stress-induced deformation measurements weakly reflect this aspect, leading to an inability to accurately predict the scale of the impact of effective stress changes on permeability during CBM production and CO2-ECBM processes. In contrast, adsorption-induced deformation relatively accurately reflects the deformation capability of the coal matrix and provides a more accurate prediction of permeability rebound under the condition of almost unchanged effective stress in the late stages of mining. Therefore, deformation parameters under stress loading are challenging to directly apply to the prediction of permeability evolution, while adsorption-induced deformation parameters can be effectively utilized.

The morphology, content, and distribution of the δ phase in GH4169 alloy have important effects on the performance of parts. To study the evolution of the δ phase during the cross-wedge rolling of GH4169 alloy, the microstructure and phase structure were characterized using scanning electron microscopy, electron backscatter diffraction, and transmission electron microscopy. Furthermore, the interaction mechanism between the δ phase and dynamic recrystallization during cross-wedge rolling was investigated. The experimental results showed that the fracture and dissolution of the δ phase gradually extended from the surface to the center of GH4169 alloy rolled parts. The initial acicular δ phase on the surface and at the core of the rolled piece gradually fractured and dissolved into short rods/granules, and the degree of spheroidization gradually increased as the section shrinkage rate increased. Varying microstructures were obtained at different positions of the rolled piece owing to nonuniform plastic deformation induced by cross-wedge rolling. During deformation, dislocations piled up near the δ phase and formed high-density dislocation cells, promoting dynamic recrystallization nucleation. The necklace-like microstructure was characterized by insufficient dynamic recrystallization, while the fine homogenous microstructure was derived from full dynamic recrystallization as the section shrinkage rate increased to 82

A three-dimensional invasion percolation simulation model is introduced and integrated into a novel three-dimensional geological modeling framework based on the “unit element” theory to study secondary hydrocarbon migration. Leveraging the computational efficiency inherent in the invasion percolation theory, the simulation method is effectively applied to basin-scale hydrocarbon migration using finely discretized grids. Sensitivity analysis demonstrates the substantial influence of geological parameters including structural configuration, sedimentary facies, and pressure, on simulation results. Noteworthy observations from this study encompass: (1) The intricate influence of sedimentary facies and petrophysical properties characteristics on hydrocarbon migration and accumulation patterns within structural and lithological traps. Favorable petrophysical attributes in the carrier beds enhance the likelihood of accumulation in the structural traps, while lithological traps are prevalent in less conducive carrier beds. (2) The significant impact of sand bodies exhibiting favorable petrophysical attributes, such as channels, on migration and accumulation profiles. This underscores the necessity of incorporating sedimentary facies and rock attributes into oil and gas resource exploration. (3) The pronounced effects of overpressure magnitude and direction on hydrocarbon migration and accumulation dynamics. (4) Optimal strategies for oil and gas resource exploration necessitate a comprehensive assessment of rock attributes, overpressure considerations, and sedimentary facies. The practical implementation of this methodology is demonstrated in an actual exploration project within China's Junggar Basin. The simulation results closely align with established oil recovery data and facilitate predictive identification of promising exploration areas. This indicates the methodology is applicable to all petroleum systems similar to Junggar Basin. Through practical applications, the development of a scientifically rigorous three-dimensional geological model for the study area, coupled with numerical simulations of oil and gas migration, facilitates the elucidation of accumulation patterns. This approach aids in identifying pivotal factors such as sand body distribution, internal structural composition, permeability attributes, and fracture behavior, which collectively influence oil and gas migration. Furthermore, by correlating insights obtained from oil and gas discoveries in wells, a deeper understanding of carrier bed properties and their geological evolution is attained.

A large amount of oil and gas has been discovered in the ultradeep reservoirs in the Shawan Sag, Junggar Basin. However, the hydrocarbon phases in ultradeep reservoirs are complex, and the controlling factors and evolution have not been studied, which are important for exploration and development. This study determined the hydrocarbon phase states of the reservoirs in the Upper Wuerhe Formation (P(3)w) of Well Zheng 10 in the Shawan Sag via hydrocarbon components and a pressure-volume-temperature (PVT) phase diagram. We used 1D basin modeling to simulate the thermal maturity of the Lower Wuerhe (P(2)w) source rock, components of generated hydrocarbons, reservoir temperature and pressure, and hydrocarbon phase. The results show that the hydrocarbons in the P(3)w reservoir are secondary condensate gas. The source rock began to enter the threshold of hydrocarbon generation at the end of the Late Triassic, and the thermal maturity (Easy Ro%) of the P(2)w source rock in the P(3)w reservoir fetch area is approximately 1.5% at present. The reservoir experienced multiple periods of hydrocarbon charging and phase evolution. During the Late Triassic to the early Late Jurassic and the late Early Cretaceous to the Late Cretaceous, the hydrocarbons in the P(3)w reservoir were liquid. Since the Miocene, a large amount of gas has migrated to the P(3)w reservoir, leading to gas invasion, which is the key to the formation of a condensate gas reservoir. The hydrocarbons changed from liquid to condensate gas due to the increasing gas-oil ratio and reservoir temperature. This study provides a quantitative method to reconstruct the phase evolution process and establishes an accumulation model of condensate gas reservoirs.

Through real-time monitoring of gas composition, water ions, and productivity variations in multiple production wells after liquid CO2 injection, it reveals differences in reservoir response characteristics and geological control mechanisms between coalbed methane production wells. The results show that CO2 forms preferential migration channels along low ground stress and high-altitude directions. The production wells are divided into efficient stimulation wells, inefficiency stimulation wells, inhibition wells, and unaffected wells according to stimulation effect. The efficient stimulation wells show that the stimulation mode is CO2 displacement. The gas production increases significantly, with a maximum increase rate of 46.85 %. The N-2 component in the produced gas and the HCO3- + CO32- ions in the produced increase during the continuous injection. The inefficient stimulation wells and inhibition wells show CO2 driven water production mode. The N-2 and CO2 component, and the HCO3- + CO32- ions increase during the injection process. And the formation of water-abundant zones around the production wells inhibits the production of gas. The unaffected well is not affected by CO2 injection and shows a natural gas production mode of drainage depressurization and desorption. The results of the study provide technical support for the implementation and evaluation of the CO2-ECBM project.

The strong heterogeneity characteristics of deep-buried clastic low-permeability reservoirs may lead to great risks in hydrocarbon exploration and development, which makes the accurate identification of reservoir lithofacies crucial for improving the obtained exploration results. Due to the very limited core data acquired from deep drilling, lithofacies logging identification has become the most important method for comprehensively obtaining the rock information of deep-buried reservoirs and is a fundamental task for carrying out reservoir characterization and geological modeling. In this study, a machine learning method is introduced to lithofacies logging identification, to explore an accurate lithofacies identification method for deep fluvial-delta sandstone reservoirs with frequent lithofacies changes. Here Sangonghe Formation in the Central Junggar Basin of China is taken as an example. The K-means-based synthetic minority oversampling technique (K-means SMOTE) is employed to solve the problem regarding the imbalanced lithofacies data categories used to calibrate logging data, and a probabilistic calibration method is introduced to correct the likelihood function. To address the situation in which traditional machine learning methods ignore the geological deposition process, we introduce a depositional prior for controlling the vertical spreading process based on a Markov chain and propose an improved Bayesian inversion process for training on the log data to identify lithofacies. The results of a series of experiments show that, compared with the traditional machine learning method, the new method improves the recognition accuracy by 20%, and the predicted petrographic vertical distribution results are consistent with geological constraints. In addition, SMOTE and probabilistic calibration can effectively handle data imbalance problems so that different categories can be adequately learned. Also the introduction of geological prior has a positive impact on the overall distribution, which significantly improves the accuracy and recall rate of the method. According to this comprehensive analysis, the proposed method greatly enhanced the identification of the lithofacies distributions in the Sangonghe Formation. Therefore, this method can provide a tool for logging lithofacies interpretation of deep and strongly heterogeneous clastic reservoirs in fluvial-delta and other depositional environments.

Abundant abandoned mine methane (AMM) accumulates in the mining-disturbed coal/rock strata in abandoned coal mines. However, the simplified pore and fracture model of the mining-disturbed strata is often adopted to investigate AMM resources. In this case, AMM distribution needs to be more accurate, making it difficult to determine the appropriate location of surface wells. So the question is, how can the pore and fracture be characterized in different zones of the mining-disturbed strata? What is the distribution of AMM resources in the mining-disturbed strata? To address these problems, in this work, the mining-disturbed coal/rock strata of the abandoned mine are divided into five zones. The pore and fracture of the mining-disturbed strata in different zones are characterized by simulation experiments. On this basis, the new evaluation approach of AMM in the mining-disturbed strata is established to reveal the distribution of AMM in each zone. The results show that the mining-disturbed coal/rock strata are divided into five zones: stress concentration zone (I), shear fracture zone (II), separation fracture zone (III), compaction zone (IV), and bottom fracture zone (V). The pore and fracture of coal/rock strata and the distribution of AMM are different in each zone. The AMM resources in the miningdisturbed strata have great potential for development. The AMM in zone I account for 69% of the total, mainly the adsorbed gas in the remaining coal seam affected by mining disturbance. The AMM in the stress relief zone is mostly free gas remaining in the pore and fracture. The fractures in zone II are connected along the horizontal direction, forming a ring fracture body with abundant free AMM resources, which accounted for 19% of the total AMM resources. The AMM in zones III, IV, and V are limited. This work provides a new approach to evaluating the AMM and plays a guiding role in the layout of the surface wells in abandoned mines.