Existing sandstone rock structure evaluation methods rely on visual inspection, with low efficiency, semi-quantitative analysis of roundness, and inability to perform classified statistics in grain size analysis. This study presents an intelligent evaluation method for sandstone rock structure based on the Segment Anything Model (SAM). By developing a lightweight SAM fine-tuning method with rank-decomposition matrix adapters, a multispectral rock particle segmentation model named CoreSAM is constructed, which achieves rock particle edge extraction and type identification. Building upon this, we propose a comprehensive quantitative evaluation system for rock structure, assessing parameters including grain size, sorting, roundness, particle contact and cementation types. The experimental results demonstrate that CoreSAM outperforms existing methods in rock particle segmentation accuracy while showing excellent generalization across different image types such as CT scans and core photographs. The proposed method enables full-sample, classified grain size analysis and quantitative characterization of parameters like roundness, advancing reservoir evaluation towards more precise, quantitative, intuitive, and comprehensive development.

The gas-liquid countercurrent flow pattern is complex and the bubble migration velocity is difficult to predict in the process of bullheading well killing. The experiment on bubble migration in gas-liquid countercurrent flow in annulus is carried out under different working conditions to reveal how the wellbore inclination angle, liquid phase property and countercurrent liquid velocity affect the bubble deformation and bubble migration trajectory/velocity, and to establish a bubble migration velocity prediction model. The bubbles in the countercurrent flow mainly migrate in two modes: free rising of isolated bubbles, and interactive rising of multiple bubbles. The bubbles migrate by an S-shaped trajectory in the countercurrent flow. With the increase of countercurrent liquid velocity, the lateral oscillation of bubbles is intensified. The increases of wellbore inclination angle, liquid density and liquid viscosity make the bubble migration trajectory gradually to be linear. The bubble is generally ellipsoidal during its rising. The wellbore inclination angle has little effect on the degree of bubble deformation. With the increase of liquid viscosity and density, the aspect ratio of the bubble decreases. As the wellbore inclination angle increases, the bubble migration velocity gradually decreases. As the liquid viscosity increases, the bubble migration velocity decreases. As the liquid density increases, the bubble migration velocity increases slightly. The established bubble migration velocity prediction model yields errors within ± 15 %, and demonstrates broad applicability across a wide range of operating conditions.

The lamina (combination) types, reservoir characteristics and occurrence states of organic-rich shale in the Triassic Chang 7₃ sub-member in the Ordos Basin were systematically investigated to reveal the main controlling factors of shale oil occurrence under different lamina combinations. The differential enrichment mechanism and pattern of shale oil were discussed using micro-migration characterization and evaluation methods from the perspectives of relay hydrocarbon supply, stepwise migration, and multi-stage differentiation. The results are obtained in five aspects. First, Chang 7₃ mainly develops five types of lamina combination, i.e. mudstone, sandy laminae, tuffaceous laminae, mixed laminae, and organic-rich laminae. Second, shales with different lamina combinations are obviously different in the reservoir space. Specifically, shales with frequent development of rigid laminae represented by sandy laminae and tuffaceous laminae have a large number of intergranular pores, dissolution pores and hydrocarbon generation-induced fractures. The multi-scale pore and fracture system constitutes the main place for liquid hydrocarbon occurrence. Third, the occurrence and distribution of shale oil in shale with different lamina combinations are jointly controlled by organic matter abundance, reservoir quality, thermal evolution degree, mineral composition, and laminae scale. The micro-nano pores and fractures in shales with rigid laminae represented by sandy laminae and tuffaceous laminae mainly host free light components, while the surfaces of organic matter, clay minerals and skeleton mineral particles are dominated by adsorbed heavy components. Fourth, there is obvious shale oil micro-migration between shales with different lamina combinations in Chang 7₃. Generally, such micro-migration is stepwise in a sequence of shale with organic-rich laminae → shale with tuffaceous laminae → shale with mixed laminae → shale with sandy laminae. Fifth, the relay hydrocarbon supply of organic matter under the control of the spatial superposition of shales with various laminae, the stepwise migration via multi-scale pore and fracture network, and the multi-differentiation in shales with different lamina combinations under the control of organic-inorganic interactions fundamentally decide the differences of shale oil components between shales with different lamina combinations.

Based on the comprehensive analysis of data from petrology, well logging, seismic surveys, paleontology, and geochemistry, a detailed research was conducted on the tectonic-sedimentary setting, and paleoenvironmental and paleoclimatic conditions of the source rocks in the second member of the Eocene Wenchang Formation (Wen 2 Member) in the Shunde North Sag at the southwestern margin of the Pearl River Mouth Basin. The Wen 2 Member hosts excellent, thick lacustrine oil shales with strong longitudinal heterogeneity and an average total organic carbon (TOC) content of over 4.9%. The Wen 2 Member can be divided into three units (I, II, III) from bottom to top. Unit I features excellent source rocks with Type I organic matters (average TOC of 5.9%) primarily sourced from lake organic organisms; Unit II hosts source rocks dominated by Type II₂ organic matters (average TOC of 2.2%), which are originated from mixed sources dominated by terrestrial input. Unit III contains good to excellent source rocks dominated by Type II₁ organic matters (average TOC of 4.9%), which are mainly contributed by lake organisms and partially by terrestrial input. Under the background of rapid subsidence and limited source supply during strong fault depression, excellent source rocks were developed in Wen 2 Member in the Shunde North Sag under the coordinated control of warm and humid climate, volcanic activity, and deep-water reducing conditions. During the deposition of Unit I, the warm and humid climate and volcanic activity promoted the proliferation of lake algaes, primarily Granodiscus, resulting in high initial productivity, and deep-water reducing conditions enabled satisfactory preservation. These factors jointly controlled the development and occurrence of excellent source rocks. During the deposition of Unit II, a transition from warm to cool and semi-arid paleoclimatic conditions led to a decrease in lake algaes and initial productivity. Additionally, enhanced terrestrial input and shallow-water, weakly oxidizing water conditions caused a significant dilution and decomposition of organic matters, degrading the quality of source rocks. During the deposition of Unit III, when the paleoclimatic conditions are cool and humid, Pediastrum and Botryococcus began to thrive, leading to an increase in productivity. Meanwhile, the reducing environment of semi-deep water facilitated the preservation of excellent source rocks, albeit slightly inferior to those in Unit I. The study results clarify the differential origins and development models of various source rocks in the Shunde Sag, offering valuable guidance for evaluating source rocks and selecting petroleum exploration targets in similar marginal sags.

By comprehensively considering the influence of temperature and pressure on fluid density in high temperature and high pressure (HTHP) wells in deepwater fractured formation and the effects of formation fracture deformation on well shut-in afterflow, this study couples the shut-in temperature field model, fracture deformation model, and gas flow model to establish a wellbore pressure calculation model incorporating thermo-hydro-mechanical coupling effects. The research analyzes the governing patterns of geothermal gradient, bottomhole pressure difference, drilling fluid pit gain, and kick index on casing head pressure, and establishes a shut-in pressure determination chart for HPHT wells based on coupled model calculation results. The results show: geothermal gradient, bottomhole pressure difference, and drilling fluid pit gain exhibit positive correlations with casing head pressure; higher kick indices accelerate pressure rising rates while maintaining the maximum stable casing pressure; validation against field case data demonstrates over 95% accuracy in predicting wellbore pressure recovery after shut-in, with the pressure determination chart achieving 97.2% accuracy in target casing pressure prediction and 98.3% accuracy in target shut-in time determination. This method enables accurate acquisition of formation pressure after HPHT well shut-in, providing reliable technical support for subsequent well control measures and ensuring safe and efficient development of deepwater and deep hydrocarbon reservoirs.

Taking the Lower Silurian Longmaxi Formation shale in the Sichuan Basin as an example, this study employs atomic force microscopy-based infrared spectroscopy (AFM-IR) to analyze the submicron-scale molecular functional groups of different types and occurrences of organic matter. Combined with the quantitative evaluation of pore development via scanning electron microscopy (SEM), the response of organic pore formation and evolution mechanisms to chemical composition and structural evolution of organic matter in overmature marine shale is investigated. The results indicate that the AFM-IR spectra of graptolite periderms and pyrobitumen in shale are dominated by the stretching vibrations of conjugated C=C bonds in aromatic compounds at approximately 1 600 cm^-1, with weak absorption peaks near 1 375, 1 450, and 1 720 cm^-1, corresponding to aliphatic chains and carbonyl/carboxyl functional groups. Overall, the AFM-IR structural indices (A and C factors) of organic matter show a strong correlation with visible porosity in shales of equivalent maturity. Lower A and C factor values correlate with enhanced development of organic pores, which is associated with the detachment of more aliphatic chains and oxygen-containing functional groups from precursors during thermal evolution. Pyrobitumen-clay mineral composites generally exhibit superior pore development, likely attributable to clay mineral dehydration participating in hydrocarbon generation reactions that promote the removal of more aliphatic chains and oxygen-containing functional groups. Additionally, hydrocarbon generation within organic-clay composites during high-over mature stages may induce volumetric expansion, leading to microfracturing and hydrocarbon expulsion. The associated higher hydrocarbon expulsion rates promote the formation of larger pores and flake-shaped pores adjacent to clay minerals. This study highlights that molecular-level insights into aliphatic chains and functional groups provide a deeper understanding of organic matter evolution and pores development mechanisms in overmature shales, thereby offering critical theoretical parameters for deciphering reservoir formation mechanisms in shale oil and gas exploration.

Natural gas hydrate (NGH), as a widely recognized clean energy, has shown a significant resource potential. However, due to the lack of a unified evaluation methodology and the difficult determination of key parameters, the evaluation results of global NGH resource are greatly different. This paper establishes a quantitative relationship model between NGH resource potential and conventional/unconventional oil and gas resource and a NGH resource evaluation model based on the whole petroleum system (WPS) and through the analysis of dynamic field controlled hydrocarbon accumulation. Furthermore, the global NGH initially in place and recoverable resources are inverted through the Monte Carlo simulation, and verified by using the volume analogy method based on drilling results and the trend analysis method of previous evaluation results. The proposed evaluation model considers two genetic mechanisms of natural gas (biological degradation and thermal degradation), volume factor difference between conventional natural gas and NGH, and the impacts of differences in favorable formation and distribution area and thickness and in other aspects on the results of NGH resource evaluation. The study shows that the global NGH initially in place and recoverable resources are 99×10¹² m³ and 30×10¹² m³, with averages of 214×10¹² m³ and 68×10¹² m³, respectively, less than 5% of the total conventional oil and gas resources, and they can be used as a supplement for the future energy of the world. The proposed NGH resource evaluation model creates a new option of evaluation method and technology, and generates reliable data of NGH resource according to the reliability comprehensive analysis and test, providing a parameter basis for subsequent NGH exploration and development.

Based on the basic data of drilling, logging, testing and geological experiments, the geological characteristics of the Permian Dalong Formation marine shales in the Sichuan Basin and the factors controlling shale gas enrichment and high yield in these shales are studied. The results are obtained in four aspects. First, the high-quality shale of the Dalong Formation was formed after the deposition of the Wujiaping Formation, and it is mainly developed in the Kaijiang-Liangping trough in the northern part of Sichuan Basin, where deep-water continental shelf facies and deep-water reduction environment where siliceous organisms flourished have formed the black siliceous shale rich in organic matter. Second, the Dalong Formation shale contains both organic and inorganic pores, with stratification of alternating brittle and plastic minerals, which was stacked with severe compaction to enlarge the fractures, thereby improving the permeability. In addition to organic pores, a large number of inorganic pores are developed even in the ultra-deep (˃4 500 m) layers, contributing a total porosity of more than 5% and a permeability of 0.2×10^-3 μm², which significantly expands the accommodation space for shale gas. Third, the limestone at the roof and floor of the Dalong Formation acted as a seal in the early burial and hydrocarbon generation stage, providing favorable conditions for the continuous hydrocarbon generation and rich gas preservation in shale interval. In the later reservoir stimulation process, it was beneficial to the lateral extension of the fractures, so as to achieve the optimal stimulation performance and increase the well-controlled resources. Combining the geological, engineering and economic conditions, the favorable area with depth <5 500 m is determined to be 1 800 km², with resources of 5 400×10⁸ m³. Fourth, the shale reservoirs of the Dalong Formation are thin but rich in shale gas. The syncline zone far away from the main faults in the high and steep tectonic zone, eastern Sichuan Basin, with depth <5 500 m, is the most favorable target for producing the Permian shale gas under the current engineering and technical conditions. It mainly includes the Nanya syncline, Tanmuchang syncline, and Liangping syncline.

The Carter model is used to characterize the dynamic behaviors of fracture growth and fracturing fluid leakoff. A thermo-fluid coupling forward model is built considering the fluid flow and heat transfer in wellbore, fracture and reservoir. The influences of fracturing parameters and fracture parameters on the responses of distributed temperature sensing (DTS) are analyzed, and a diagnosis method of fracture parameters is presented based on the simulated annealing algorithm. A field case study is introduced to verify the model’s reliability. The results show that typical V-shaped characteristics can be observed from DTS responses in the multi-cluster fracturing process, with locations corresponding to the created hydraulic fractures. The V-shape depth is shallower for a higher injection rate and longer fracturing and shut-in time. Also, the V-shape is wider for a higher fracture-surface leakoff coefficient, longer fracturing time, and smaller fracture width. Additionally, the cooling effect near the wellbore continues to spread into the reservoir during the shut-in period, causing the DTS temperature to decrease instead of rise. Real-time monitoring and interpretation of DTS temperature data can help understand the fracture propagation during fracturing operation, so that immediate measures can be taken to improve the fracturing performance.

Addressing the issue that traditional finite element methods cannot fully consider the semi-infinite earth strata and have lower solution accuracy, a new equivalent force model for development-induced deformation is derived from the perspective of semi-infinite earth strata. A brand-new volume boundary element numerical solution method has been developed and verified and tested. The study shows that the influences of internal flow and impermeable boundary of the reservoir on strata deformation are equivalent to the impacts on strata deformation when external forces act at the interior and boundary of the reservoir, respectively. The methods for calculating flow equivalent forces and boundary equivalent forces are provided. The deformation solution at any point in the strata can be obtained through the convolution of flow equivalent forces, boundary equivalent forces, and Green's functions. After discretization, the deformation solution at any point in the strata can be obtained by multiplying the grid boundary equivalent forces, grid flow equivalent forces with their corresponding grid boundary sources, and grid volume sources, and then summing them up. This is called the volume boundary element solution method, which eliminates the need for meshing outside the reservoir and yields a greatly improved accuracy. Compared with traditional commercial simulators, it fully considers the impacts of reservoir impermeable boundaries, pore pressure gradient fields within the reservoir, and changes in fluid mass within the pores on strata deformation, providing a new technical solution for the simulation of deformation induced by reservoir development.

Based on development practices of Gulong shale oil and a series of experiments on interactions between CO₂ and the rocks and fluids of shale oil reservoirs, the application and adaptability of CO₂ pre-fracturing to the Gulong shale oil reservoirs are systematically evaluated. The pilot tests indicate that compared to wells with conventional fracturing, wells with CO₂ pre-fracturing demonstrate four significant characteristics: high but rapidly declined initial production, low cumulative production, high and unstable gas-oil ratio, and non-competitive liquid production. These characteristics are attributed to two facts. First, pre-fracturing with CO₂ inhibits the cross-layer extension of the main fractures in the Gulong shale oil reservoirs, reduces the stimulated reservoir volume, weakens the fracture conductivity, and decreases the matrix permeability and porosity, ultimately impeding the engineering performance. Second, due to the confinement effect, pre-fracturing with CO₂ increases the saturation pressure difference between the fracture-macropore system and the matrix micropore system, leading to continuous gas production and light hydrocarbon evaporation in the fracture-macropore system, and difficult extraction of crude oil in the matrix-micropore system, which affects the stable production. Under the superposition of various characteristics of Gulong shale oil reservoirs, pre-fracturing with CO₂ has significant negative impacts on reservoir stimulation (incl. fracture extension and fracture conductivity), matrix seepage, and fluid phase and production, which restrict the application performance of CO₂ pre-fracturing in the Gulong shale oil reservoirs.

Taking the natural gas reservoirs of the Sinian Dengying Formation on the east and west sides of the Deyang-Anyue rift trough as the research object, the geochemical parameters (component, isotopic composition) of natural gas from the Dengying Formation in different areas are thoroughly compared, and then the differences in geochemical characteristics of Dengying natural gas on the east and west sides of the Deyang-Anyue rift trough and their genesis are clarified. First, the Dengying gas reservoirs on both sides of the rift trough are predominantly composed of oil-cracking gas with high maturity, which is typical dry gas. Second, severely modified by thermochemical sulfate reduction (TSR) reaction, the Dengying gas reservoirs on the east side exhibit high H₂S and CO₂ contents, with an elevated δ¹³C₂ value (average value higher than -29‰). The Dengying gas reservoirs in the Weiyuan area show less TSR modification, though δ¹³C₁ values are slightly greater than that of the reservoirs on the east side, likely due to the water-soluble gas precipitation and accumulation mechanism. The Dengying gas reservoir of Well Datan-1 shows no TSR influence. Third, the Dengying gas reservoirs reflect high helium contents (>0.10%, higher than that on the east side) in the Weiyuan and Datan-1 areas on the west side, which is supposed to attribute to the widespread granites in basement and efficient vertical transport along faults. Fourth, controlled by the paleo-salinity of water medium in the depositional period of the source rock, the δ²H_CH4 of the Dengying gas reservoirs on the west side is slightly lighter than that on the east side. Fifth, the Dengying natural gas in the Datan-1 area is contributed by the source rocks of the Doushantuo Formation and the third member of the Dengying Formation, in addition to the Cambrian Qiongzhusi Formation.

By systematically reviewing the development status of global carbon dioxide capture, utilization and storage (CCUS) cluster, and comparing domestic and international CCUS industrial models and successful experiences, this study explores the challenges and strategies for the scaled development of the CCUS industry of China. Globally, the CCUS industry has entered a phase of scaled and clustered development. North America has established a system of key technologies in large-scale CO₂ capture, long-distance pipeline transmission, pipeline network optimization, and large-scale CO₂ flooding for enhanced oil recovery (CO₂-EOR), with relatively mature cluster development and a gradual shift in industrial model from CO₂-EOR to geological storage. The CCUS industry of China has developed rapidly across all segments but remains in the early stage of cluster development, facing challenges such as absent business model, insufficient policy support, and technological gaps in core areas. To achieve scaled development of CCUS industry, China needs to improve the policy support system to boost enterprises participation across the entire industrial chain, strengthen top-level design and medium- to long-term planning to accelerate demonstration projects for whole-process CCUS clusters, advance for a full-chain technological system, including low-cost capture, pipeline optimization, and EOR/storage integration technologies, and enhance academic disciplines and fostering university-enterprise research collaborations.

To address the challenges in studying the pore formation and evolution processes, and preservation mechanisms of deep to ultra-deep carbonate rocks, a high-temperature and high-pressure visualization simulation experimental device was developed for ultra-deep cross-tectonic-periods carbonate reservoirs. This unit comprises four core modules: an ultra-high temperature, high pressure triaxial stress reactor (temperature >300 °C, pressure >150 MPa), a multi-stage continuous flow system with temperature-pressure regulation, an ultra-high temperature-pressure sapphire window cell, and an in-situ high-temperature-pressure fluid property measurement and real-time ultra-high temperature-pressure permeability detection system. Using the new experimental device to simulate the dissolution-precipitation process of deep to ultra-deep carbonate in an analogous geological setting, the geological insights were obtained in three aspects. First, the pore-throat structure of carbonate is controlled by lithology and initial pore-throat structure, and fluid type, concentration and dissolution duration determine the degree of dissolution. The dissolution process exhibits two evolution patterns. The dissolution scale is positively correlated to the temperature and pressure, and the pore-forming peak period aligns well with the hydrocarbon generation peak period. Second, the dissolution potential of dolomite in an open flow system is greater than that of limestone, and secondary dissolved pores can be formed continuously due to the type and concentration of acidic fluids, and the initial physical properties. These pores predominantly distribute along pre-existing pore/fracture zones. Third, in a nearly closed diagenetic system, after the chemical reaction between acidic fluids and carbonate rock reaches saturation and dynamic equilibrium, the pore structure no longer changes, keeping pre-existing pores well-preserved. These findings have important guiding significance for the evaluation of pore-throat structure and development potential of deep to ultra-deep carbonate reservoirs, and the prediction of main controlling factors and distribution of high-quality carbonate reservoirs.

The ultra-deep (˃8 000 m) petroleum in the platform-basin zones of the Tarim Basin has been found mainly in the Lower Paleozoic reservoirs located to the east of the strike-slip fault F5 in the north depression. However, the source and exploration potential of the ultra-deep petroleum in the Cambrian on the west of F5 are still unclear. Through the analysis of lithofacies and biomarkers, it is revealed that there are at least three kinds of isochronous source rocks (SRs) in the Cambrian Newfoundland Series in Tarim Basin, which were deposited in three sedimentary environments, i.e. sulfide slope, deep-water shelf, and restricted bay. Recently, Well XT-1 in the western part of northern Tarim Basin has yielded a high production of condensate from the Cambrian. In the produced oil, entire isoprenoid alkane biomarkers were detected, but triaryl-sitosterane (TAS) was absent. This finding is well consistent with the characteristics of the Newfoundland slope SRs represented by those in Wells LT-1 and QT-1, suggesting that the Newfoundland SRs in western Manjaer Sag are the main source of the Cambrian petroleum discovered in Well XT-1. Further analysis indicates that the Cambrian crude oil of Well XT-1 also presents the predominance of C₂₉ steranes and is rich in long-chain tricyclic terpenes (up to C₃₉), which can be indicators for effectively distinguishing lithofacies such as siliceous mudstone and carbonate rock. Combined with the analysis of hydrocarbon accumulation in respect of conduction systems including thrust fault and strike-slip fault, it is found that the area to the west of F5 is a possible destination of effective supply of hydrocarbons from the Cambrian Newfoundland SRs. This finding suggests that the area to the west of F5 will be a new target of exploration in the Cambrian ultra-deep structural-lithologic reservoirs in the Tarim Basin, in addition to the Cambrian ultra-deep platform-margin facies-controlled reservoirs in the eastern part of the basin.

The chemical analysis results of formation water in oil and gas fields may be affected by various factors in the process of testing, trial production, collection, storage, transportation, and analysis, making the properties of formation water not be reflected truly. This paper discusses the data credibility evaluation method for formation water in oil and gas fields of petroliferous basins within China, and the commonly used chemical indicators, hydrochemical characteristic coefficients, and their corresponding geological setting. It is indicated that formation water is identified by some basic methods based on single factor such as physical properties, hydrochemical composition, water type, and characteristic coefficient. On this basis, a comprehensive data credibility evaluation method is proposed, which is mainly realized by analyzing the correlation between sodium chloride coefficient (r_Na/r_Cl) and desulfurization coefficient [r_SO4×100/(r_Cl+ r_SO4)] and evaluating the geological setting. The basic methods enable the preliminary identification of hydrochemical data and the preliminary screening of data on site. The proposed comprehensive method realizes the evaluation by classifying the CaCl₂-type water into types A-I to A-VI and the NaHCO₃-type water into types B-I to B-IV, so that researchers can make in-depth evaluation on the credibility of hydrochemical data and analysis of influencing factors. When the basic methods are used to identify the formation water, the formation water containing anions such as CO₃^2-, OH^- and NO₃^-, or the formation water with the sodium chloride coefficient and desulphurization coefficient not matching the geological setting, are all invaded with surface water or polluted by working fluid. When the comprehensive method is used, the data credibility of A-I, A-II, B-I or B-II formation water can be evaluated effectively and accurately only if the geological setting analysis in respect of the factors such as formation environment, sampling conditions, condensate water, acid fluid, leaching of ancient weathering crust, and ancient atmospheric fresh water, is combined, although such water is believed with high credibility.

In order to identify the development characteristics of fracture network in tight conglomerate reservoir of Mahu after hydraulic fracturing, a hydraulic fracturing test site was set up in the second and third members of Triassic Baikouquan Formation (T₁b₂ and T₁b₃) in Ma-131 well area, which learned from the successful experience of hydraulic fracturing test sites in North America (HFTS-1). Twelve horizontal wells and a high-angle cored well MaJ02 were drilled. The occurrence, connection, propagation law and major controlling factors of hydraulic fractures were analyzed by comparing results of CT scans, imaging logs, direct observation of cores from Well MaJ02, and the tracer monitoring data. Results indicate that: (1) Two types of fractures have developed by hydraulic fracturing, i.e. tensile fractures and shear fractures. Tensile fractures are approximately parallel to the direction of the maximum horizontal principal stress, and propagate less than 50 m from the perforation cluster. Shear fractures are distributed among tensile fractures and mainly in the strike-slip mode due to the induced stress field among tensile fractures, and some of them are in conjugated pairs. Overall, tensile fractures alternate with shear fractures, with shear fractures dominated and activated after tensile ones. (2) Tracer monitoring results showed an obvious difference in fracturing and fluid production among different fracturing stages in horizontal wells. Some hydraulic fractures with length exceeding the well spacing gradually close during the fluid production process due to interwell communication. (3) Density of hydraulic fractures is mainly affected by the lithology and fracturing parameters, which is smaller in the mudstone than the conglomerate. Larger fracturing scale and smaller cluster spacing lead to a higher fracture density, which are important directions to improve the well productivity.

Based on the test and experimental data from exploration well cores in the central-eastern Ordos Basin, combined with structural, depth and fluid geochemistry analyses, this study reveals the fluid characteristics, gas accumulation control factors and accumulation modes in coal reservoirs. The study indicates findings in two aspects. First, the 1 500-1 800 m interval represents the critical transition zone between shallow-medium open fluid system and deep closed fluid system. Reservoirs below 1 500 m reflect intense water invasion, with discrete pressure gradient distribution, and the presence of methane mixed with varying degrees of secondary biogenic gas, and they generally exhibit high water saturation and adsorbed gas undersaturation. Reservoirs deeper than 1 800 m, with extremely low permeability, are self-sealed, and contains closed fluid systems formed jointly by the hydrodynamic lateral blocking and tight caprock confinement. Within these systems, surface runoff infiltration is weak, the degree of secondary fluid transformation is minimal, and the pressure gradient is relatively uniform. The adsorbed gas saturation exceeds 100% in most seams, and the free gas content primarily ranges from 1 to 8 m³/t (˃10 m³/t in some seams). Second, the gas enrichment in deep coals is primarily controlled by coal quality, reservoir-caprock assemblage, and structural position governed storage, wettability and sealing properties, under the constraints of the underground temperature and pressure conditions. High-rank, low-ash yield coals with limestone and mudstone caprocks show superior gas accumulation potential. Positive structural highs and negative structural lows are favorable sites for gas enrichment, while slope belts of fold limbs exhibit relatively lower gas content. This research enhances understanding of gas accumulation mechanisms in coal reservoirs and provides effective guidance for precise zone evaluation and innovation of adaptive stimulation technologies for deep resources.

Static adsorption and dynamic damage experiments were carried out on typical No.8 deep coal rock in the Ordos Basin to evaluate the adsorption capacity of hydroxypropyl guar gum and polyacrylamide as fracturing fluid thickeners on deep coal rock surface and the permeability damage caused by adsorption. The adsorption morphology of the thickener was quantitatively characterized by atomic force microscopy, and the main controlling factors of the thickener adsorption were analyzed. Meanwhile, the adsorption mechanism of the thickener was revealed by Zeta potential, Fourier infrared spectroscopy and X-ray photoelectron spectroscopy. The results show that the adsorption capacity of hydroxypropyl guar gum on deep coal surface is 3.86 mg/g, and the permeability of coal rock after adsorption decreases by 35.24%-37.01%. The adsorption capacity of polyacrylamide is 3.29 mg/g, and the permeability of coal rock after adsorption decreases by 14.31%-21.93%. The thickness of the thickener adsorption layer is positively correlated with the mass fraction of thickener and negatively correlated with temperature, and a decrease in pH will reduce the thickness of the hydroxypropyl guar gum adsorption layer and make the distribution frequency of the thickness of the polyacrylamide adsorption layer more concentrated. Functional group condensation and intermolecular force are the chemical and physical forces for adsorbing fracturing fluid thickener in deep coal rock. Optimization of thickener mass fraction, chemical modification of thickener molecular, oxidative thermal degradation of polymer and addition of desorption agent can reduce the potential damages on micro-nano pores and cracks in coal rock.

In recent years, wells Pengshen 10, Heshen 9, Tongshen 17 and Zhengyang 1 in the Sichuan Basin have confirmed the presence of a set of porous reef-beach reservoirs in the Upper Permian Changxing Formation, which breaks the traditional view that deep and ultra-deep carbonate oil and gas are mainly distributed in porous dolomite reservoirs and karst fracture-cavity limestone reservoirs. Through core and thin section observations, reservoir geochemical analysis, and well-seismic based reservoir identification and tracking, this study provides insights in four aspects. (1) Porous reef-beach limestone reservoirs are developed in the Changxing Formation in deep-buried layers. The reservoir space is mainly composed of intergranular (dissolved) pores, framework pores, biological cavity pores, mold pores and dissolution pores, which are formed in sedimentary and early surface environments. (2) The intermittently distributed porous reef-beach complexes are surrounded by relatively dense micrite limestone, which leads to the formation of local abnormal overpressure inside the reef-beach complexes under the deep ultra-high temperature. (3) The floor of the Changxing Formation reservoir is composed with interbedded tight mudstone and limestone of the Upper Permian Wujiaping Formation, and the floor is the tight micrite limestone interbedded with mudstone of the first member of Lower Triassic Feixianguan Formation. Under the clamping of dense roof and floor, the abnormal overpressure in the Changxing Formation is formed. Abnormal overpressure is the key to maintain the pores formed in the sedimentary and surface periods in deep-buried layers. (4) Based on the identification of roof, floor and reef-beach complexes, the favorable reef-beach limestone reservoir distribution area of 10.3×10⁴ km² is predicted by well-seismic combination. These insights lay the theoretical foundation for the development of deep porous limestone reservoirs, expand the new field of exploration of deep-buried limestone reservoirs in the Sichuan Basin, and have important reference value for the exploration of deep-buried limestone reservoirs in other basins.

Based on recent advancements in shale oil exploration within the Ordos Basin, this study presents a comprehensive investigation of the paleoenvironment, lithofacies assemblages and distribution, depositional mechanisms, and reservoir characteristics of shale oil in continental freshwater lacustrine basins, with a focus on the Chang 7₃ sub-member of Triassic Yanchang Formation. The research integrates a variety of exploration data, including field outcrops, drilling, logging, core samples, geochemical analyses, and flume simulation experiment. The study indicates that: (1) The paleoenvironment of the Chang 7₃ deposition is characterized by a warm and humid climate, frequent monsoon events, and a large water depth of freshwater lacustrine basin. The paleogeomorphology exhibits an asymmetrical pattern, with steep slopes in the southwest and gentle slopes in the northeast. This can be further subdivided into microgeomorphological units, including depressions and ridges in lakebed, as well as ancient channels; (2) The Chang 7₃ sub-member is characterized by a diverse array of fine-grained sediments, including very fine sandstone, siltstone, mudstone, and tuff. These sediments are primarily distributed in thin interbedded and laminated arrangements vertically. The overall grain size of the sandstone predominantly falls below 0.062 5 μm, with individual layer thicknesses of 0.05-0.64 m. The deposits contain intact plant fragments and display various sedimentary structure, such as wavy bedding, inverse-to-normal grading sequence, and climbing ripple bedding, which indicating a depositional origin associated with density flows; (3) Flume simulation experiments have successfully replicated the transport processes and sedimentary characteristics associated with density flows. The initial phase is characterized by a density-velocity differential, resulting in a thicker, coarser sediment layer at the flow front, while the upper layers are thinner and finer in grain size. During the mid-phase, sliding water effects cause the fluid front to rise and facilitate rapid forward transport. This process generates multiple “new fronts”, enabling the long-distance transport of fine-grained sandstones, such as siltstone and argillaceous siltstone, into the center of the lake basin; (4) A sedimentary model primarily controlled by the density flows was established for the southwestern part of the basin, highlighting that the frequent occurrence of flood events and the steep topography in this area are the primary controlling factors for the development of density flows; (5) Sandstone and mudstone in the Chang 7₃ sub-member exhibit micro- and nano-scale pore-throat systems, with varying oil-bearing properties across different lithologies and significant differences in mobile oil content. (6) It was determined that the fine-grained sediment complexes formed by multiple episodes of sandstones and mudstones associated with density flow in the Chang 7₃ formation exhibit characteristics of “overall oil-bearing with differential storage capacity”. The combination of mudstone with low total organic carbon content (TOC) and siltstone is identified as the most favorable exploration target at present.

This paper investigates the macroscopic and microscopic characteristics of viscosity reduction and quality improvement of heavy oil in a supercritical water environment through laboratory experiments and analytical testing. The effect of three reaction parameters, i.e. reaction temperature, reaction time and oil-water ratio, is analyzed on the product and their correlation with viscosity. The results show that the flow state of heavy oil significantly improved with a viscosity reduction of 99.4% in average after the reaction in supercritical water. Excessively high reaction temperature leads to a higher content of resins and asphaltenes, with significantly increasing production of coke. The optimal temperature ranges in 380 °C-420 °C. Prolonged reaction time could continuously increase the yield of light oil, but it will also results in the growth of resins and asphaltenes, with the optimal reaction time of 150 minutes. Reducing the oil-water ratio helps improve the diffusion environment within the reaction system and reduce the content of resins and asphaltenes, but it will increase the cost of heavy oil treatment. An oil-water ratio of 1:2 is considered as optimum to balance the quality improvement, viscosity reduction, and reaction economics. The correlation of the three reaction parameters relative to the oil sample viscosity is ranked as temperature, time, and oil-water ratio. Among the four fractions of heavy oil, the viscosity is dominated by asphaltene content and less affected by resins and saturates contents.

By considering the thermo-poroelastic effects of rock, the constitutive relationship of fatigue deterioration under cyclic loading, elastic-brittle failure criteria, and wellbore stress superposition effects, a thermal-hydraulic-mechanical-fatigue damage coupled model for fracture propagation during soft hydraulic fracturing in hot dry rock (HDR) was established and validated. Based on this model, numerical simulations were conducted to investigate the fracture initiation and propagation characteristics in HDR under the combined effects of different temperatures and cyclic loading. The results are obtained in three aspects. First, cyclic injection, fluid infiltration, pore pressure accumulation, and rock strength deterioration collectively induce fatigue damage of rocks during soft hydraulic fracturing. Second, the fracture propagation pattern of soft fracturing in HDR is jointly controlled by temperature difference and cyclic loading. A larger temperature difference generates stronger thermal stress, facilitating the formation of complex fracture networks. As cyclic loading decreases, the influence range of thermal stress expands. When the cyclic loading is 90%p_b and 80%p_b (where p_b is the breakdown pressure during conventional hydraulic fracturing), the stimulated reservoir area increases by 88.33% and 120%, respectively, compared to conventional hydraulic fracturing (with an injection temperature of 25 ℃). Third, as cyclic loading is further reduced, the reservoir stimulation efficiency diminishes. When the cyclic loading decreases to 70%p_b, the fluid pressure cannot reach the minimum breakdown pressure of the rock, resulting in no macroscopic hydraulic fractures.

Based on the data of 3D seismic survey, drilling, sidewall coring, thin sections and tests, this paper systematically discusses the necessary conditions for the formation of buried-hills, reservoirs, and accumulations in the large oil and gas fields in deep to ultra-deep composite buried hills in the Bohai Sea through the analysis of the Meso-Cenozoic geotectonic dynamics, buried-hill reservoir characteristics, and differential enrichment patterns of oil and gas in the buried hills, as well as case study of typical reservoirs. The key findings are as follows. First, the double-episode destruction of the North China Craton in the Yanshanian and Himalayan served as the primary tectonic driver for the development of deep to ultra-deep composite buried hills in the Bohai Sea. Jointly controlled by the destruction of the North China Craton and the activity of the Tanlu Fault, the destruction center migrated and converged episodically from the margins of the Bohai Bay Basin towards the Bozhong Depression, resulting in an orderly mountain-building process within the basin and subsequently two development zones for composite buried hills, i.e. the middle and inner rim zones within the Bozhong Depression. Second, under the coupling of favorable lithologies and multi-stage structures, the middle and inner rim zones are conducive to the formation of reservoirs in fluid dissolution-pore/fracture zones underlying the weathering crust. Third, during the Episode II craton destruction, the middle and inner rim zones subsided intensely, along which massive hydrocarbons were generated, resulting in the overpressure, and then migrated to and accumulated in the composite buried hills. The lower parts and interiors of these buried hills still possess excellent conditions for hydrocarbon accumulation. These findings promote a shift in buried hill exploration to three-dimensional exploration of composite buried hills. It is emphasized that the deep to ultra-deep composite buried hill interiors in the middle rim zone and the multi-stage volcanic edifices in the inner rim zone of the depression represent important successor areas for future exploration in the Bohai Sea.

The saline lacustrine hybrid sedimentary rocks are complex in lithology and unknown for their sedimentary mechanisms. The hybrid sedimentary rocks samples from the Neogene upper Ganchaigou Formation to lower Youshashan Formation (N₁-N₂¹) in the Fengxi area, the Qaidam Basin, were investigated through core-log and petrology-geochemistry cross-analysis by using the core, casting thin section, scanning electron microscope, X-ray diffraction, logging, and carbon/oxygen isotope data. The results indicate that the hybrid sedimentary rocks in the Fengxi area were deposited in a shallow lake environment far from the source, or occasionally in a semi-deep lake environment, with 5 lithofacies types and 6 microfacies types recognized. Stable carbon and oxygen isotopes reveal that the formation of sedimentary cycles is controlled by a climate-driven compensation-undercompensation cyclic mechanism. A sedimentary cycle model of hybrid sedimentary rocks in an arid and saline setting is proposed. According to this model, in the compensation period, the lake level rises sharply, and microfacies such as mud flat, sand-mud flat and beach are developed, with physical subsidence as the dominant sedimentary mechanism; in the undercompensation period, the lake level falls slowly, and microfacies such as lime-mud flat, lime-dolomite flat and algal mound/mat are developed, with chemical-biological process as the dominant sedimentary mechanism. Unlike marine carbonate rock formed during transgression, lacustrine carbonate rock is mainly formed along with regression. In the saline lacustrine sedimentary system, the facies change is not interpreted by the accommodation believed traditionally, but controlled by the temporary fluctuation of lake water chemistry caused by climate change. The research results update the interpreted high-resolution sequence model and genesis of hybrid sedimentary rocks in the saline lacustrine basin and provide a valuable guidance for exploring unconventional hydrocarbons of saline lacustrine facies.

Through investigating the Triassic Yanchang Formation in the Ordos Basin, black carbon has been found for the first time in the seventh member of the Middle Triassic Yanchang Formation (Chang 7 Member). This study fills the gap in black carbon record in the Middle Triassic in terrestrial basins in in the East Tethys, and suggests that the oxygen content in the East Tethys during the Middle Triassic was beyond 15% and that plants had recovered from the Late Permian mass extinction. The results show that the distribution of black carbon in the Chang 7 Member is heterogeneous in the basin. In the southeastern part, the black carbon content is the highest (possibly ˃6%) in shale, with the proportion in TOC up to 20%, which is lower than 10% in the northwestern and northeastern parts. It is intriguing that the proportion of black carbon in the organic matter can reach to this high level during the Middle Triassic when black carbon was stunted. Therefore, it is postulated that black carbon could account for great proportion in organic matter after vegetation on land in the Silurian. The traditional practice needs to be caution when TOC is set as a critical proxy in source rock evaluation and shale oil and gas sweet spot screening. Source rock bearing high TOC but high proportion in black carbon may not be good target for unconventional oil and gas exploitation, while shale bearing low TOC with low or no black carbon may become promising option. The TOC in the source rock can be fractioned into black carbon (w_b), active carbon (w_a), residual carbon (w_r), and maturated oil carbon (w_o). TOC subtract w_b or TOC-w_b is recommended for evaluation of source rock, w_a for screening the in-situ recovery area of low to medium maturity shale oil, and w_o of matured shale oil for appraisal of the favorable exploration area of medium to high matured shale oil. These results allow for the quantitative evaluation of organic matter composition of shale, hydrocarbon generation potential, maturation stage, and expulsion and retention of shale oil, and also guide the reconstruction of paleoclimate in the source rock development period and the shale oil and gas sweet spot screening.

Taking the Ordos Basin as an example, this paper proposed that the construction of an energy super basin should follow the principle of “more energy, less carbon, and better energy structure”. The modeling workflow of energy super basin was built. Based on the resources/reserves, development status and infrastructures of the Ordos Basin, the development potential of the basin was evaluated, the uncertainties in the construction of energy super basin were analyzed, and the future vision and realization path of the Ordos Energy Super Basin were recommended. This study demonstrates that the Ordos Basin has the advantages of abundant sources, perfect infrastructures, well-matched carbon source and sink, small population density, and proximity to the energy consumption areas. These characteristics ensure that the Ordos Basin is a good candidate of the energy super basin. It is expected that the energy supply of the Ordos Basin in 2050 will reach 23×10⁸ tons of standard coal, and the proportion of fossil fuels in energy supply will decrease to 41%. The carbon emissions will decrease by 20×10⁸ tons of carbon dioxide equivalent compared to the emissions in 2023. The future construction of the basin should focus on the generation and storage of renewable energy. The carbon capture, utilization and storage technology requires breakthrough innovation.

Considering the adsorption loss of the hydraulic fracturing assisted oil displacement (HFAD) agent in the matrix, a method is proposed to characterize the dynamic saturation adsorption capacity of the HFAD agent with pressure differential and permeability. On this basis, coupled with the viscosity-concentration relationship of the HFAD agent, a non-linear seepage model of HFAD was established, taking into account the adsorption effect of high pressure drops, and the influencing factors were analyzed. The findings indicate that the replenishment of formation energy associated with HFAD technology is predominantly influenced by matrix permeability, fracture length and the initial concentration of the HFAD agent. The effect of replenishment of formation energy is positively correlated with matrix permeability and fracture length, and negatively correlated with the initial concentration of the HFAD agent. The initial concentration and injection amount of the high-pressure HFAD agent can enhance the concentration of the HFAD agent in the matrix and improve the efficiency of oil washing. However, a longer fracture is not conducive to maintaining the high concentration of the HFAD agent in the matrix. Furthermore, the fracture length and pump displacement are the direct factors affecting the fluid flow velocity in the matrix subsequent to HFAD. These factors can be utilized to control the location of the displacement phase front, and thus affect the swept area of HFAD. A reasonable selection of the aforementioned parameters can effectively supplement the formation energy, expand the swept volume of the HFAD agent, improve the recovery efficiency of HFAD, and reduce the development cost.

Based on 2D and 3D seismic data and well logging data, this paper studies the distribution of well-seismic stratigraphic filling and shoal controlled reservoirs of Upper Cambrian Xixiangchi Formation in the south slope of Leshan-Longnüsi paleouplift in the Sichuan Basin, to reveal the genetic relationship between stratigraphic filling, paleogeomorphology and large-scale grain shoal. (1) The Xixiangchi Formation in the study area is overlapped and filled gradually to the Leshan-Longnüsi paleouplift, but gets thin sharply due to truncation only near the denudation pinch-out line of the paleouplift. Therefore, 2 overlap slope break belts and 1 erosion slope break belt are identified, and the Xixiangchi Formation is divided into 4 members from bottom to top. (2) The filling pattern of the overlapping at the base and erosion at the top indicates that the thickness of Xixiangchi Formation can reflect the pre-depositional paleogeomorphology, and reveals that the study area has a monoclinal geomorphic feature of plunging to southeast and being controlled by multistage slope break belts. (3) The large-scale grain shoals and shoal controlled reservoirs are developed longitudinally in the third and fourth member of the Xixiangchi Formation, and laterally in the vicinity of the multistage overlap slope break belts. (4) Overlap slope break belts are closely related to northwest trending reverse faults. The northwest to southeast compressive stress formed by the convergence of the western margin of South China Plate with the Himalayas landmass of the Qiangtang-Tethyan realm in the middle and late Cambrian led to the rapid uplift of the northwest margin of the Yangtze Plate and the expansion to the southeast, forming a gradually plunging multistage slope break paleogeomorphology. Combined with oil and gas test results, it is predicted that the favorable exploration zone of the grain shoal controlled reservoirs can cover an area of 3340 km².

The depositional facies types of the fourth member of the Middle Triassic Leokoupo Formation (Lei-4 Member) in western Sichuan Basin are examined through the methods of sedimentology, lithology and the mineral composition interpretation, as well as the special lithofacies indicators such as microbialite, anhydrite-halite succession and tempestites, using the data of about 400 boreholes and 11 outcrop sections. The distribution evolution characteristics and its hydrocarbon significances of the paleo-bay facies have been discussed further. The Lei-4 Member in western Sichuan Basin has an ocean-bay-flat depositional model, with the presence of evaporated tidal flat, restricted tidal flat and paleo-bay facies from east to west. The subfacies such as bay margin, subtidal bay and bay slope are recognized within the paleo-bay, with microbial reef and grain bank microfacies in the bay margin, microbial dolomitic flat, deep-water spongy reef and hydrostatic mudstone microfacies in the subtidal bay, and tempestites and collapsed deposits in the upper bay slope. The bay margin covered the Guangyuan-Zitong-Dujiangyan area in the period of the first submember of the Lei-4 Member (Lei-4-1), regressed westward into the Shangsi-Jiangyou-Dujiangyan area in the period of Lei-4-2, and expanded to the Jiange-Zitong-Langzhong-Wusheng-Yanting-Chengdu area in the northern part of central Sichuan Basin in the period of Lei-4-3 along with a small-scale transgression. The topographic pattern of “one high and two lows” is confirmed in the Lei-4 Member, corresponding to a configuration of source rocks and reservoir rocks that are alternated horizontally and superimposed vertically. Two efficient source-reservoir configuration models, i.e. side source & side reservoir, and self-generating & self-storing, are available with the microbial reef and grain bank reservoirs at the bay margin and the high-quality source rocks within the sags on both sides of the bay. The research findings will inevitably open up a new situation for the hydrocarbon exploration in the Leikoupo Formation.

Considering the demands, situations, and trends in respect to global climate change, carbon neutrality, and energy transition, the achievements and implications of the global green energy transition and China’s new energy revolution are summarized, and the “energy triangle” theory is proposed. The research indicates that the energy technology revolution is driving a dual transformation in global energy: the black “shale oil and gas revolution” in North America and the green “new energy revolution” in China. China’s green energy revolution has achieved significant milestones in wind, solar, and hydrogen storage technologies, leading the world in photovoltaic and wind power. The country has developed the world’s largest, most comprehensive, and competitive new energy innovation, industrial, and value chains, along with the largest clean power supply system globally. New quality productivity represents green productivity. China’s green “new energy revolution” has accelerated the transformation of its energy structure and the global shift towards clean energy, promoting a new win-win model for the global green and low-carbon transition. The “energy triangle” theory in the context of new quality productivity interprets the relationship and development between energy security, economy and greenness, carbon neutrality goal, and green energy transition. Compared to the global energy resource endowment, China’s energy resources are characterized by abundant coal, limited oil and gas, and unlimited wind and photovoltaic energy. Moving forward, China's energy strategies will focus on the advancement of technologies to clean coal for carbon emission reduction, increase gas output while stabilizing oil production, increase green energy while enhancing new energy, and achieve intelligent integration. Vigorously developing new energy is an essential step in maintaining China’s energy security, and establishing a carbon-neutral “super energy system” is a necessary choice. It is crucial to enhance China’s international competitiveness in new energy development, promote high-quality energy productivity, support the country’s transition to an “energy power,” and strive for “energy independence.”

This study integrates field outcrop profiles, drilling cores, 2D seismic profiles, and 3D seismic data of key areas to analyze the Triassic tectonic-sequence stratigraphy in the Kuqa foreland basin, and investigates the impact of episodic thrust structures on sedimentary evolution and source rock distribution. (1) The Kuqa foreland basin has experienced stages of initial strong, weakened activities, relaxation and inactivity of episodic thrusting, resulting the identification of 4 second-order sequences (Ehebulake Formation, Karamay Formation, Huangshanjie Formation, Taliqike Formation) and 11 third-order sequences (SQ1-SQ11). Each sequence or secondary sequence displays a “coarse at the bottom and fine at the top” pattern due to the influence of secondary episodic thrust activity. (2) The episodic thrusting is closely linked to regional sequence patterns, deposition and source rock formation and distribution. The sedimentary evolution in the Triassic period progresses from fan delta to braided river delta, lake, braided river delta, and meandering river delta, corresponding to the initial strong (Ehebulake Formation), weakened (Karamay Formation), relaxation (Huangshanjie Formation), and inactivity (Taliqike Formation) of episodic thrusting. The development stage of thick, coarse-grained sandy conglomerate reservoirs aligns with the strong to weakened thrust activities, while the source rock formation period coincides with the relaxation to inactivity stages. (3) Controlled by the intensity and stages of episodic thrust activity, the nearly EW trending thrust fault not only significantly thickened the footwall source rock during the Huangshanjie Formation, becoming the development center of Triassic source rock, but also experienced multiple overthrust nappes in the soft stratum of the source rock, showing “stacked style” distribution. (4) The deep layers of the Kuqa foreland basin have the foundation and conditions necessary for the formation of substantial gas reservoirs, capable of forming various types of reservoirs such as self-generating and self-storing lithology, lower generating and upper storing fault-lithology, and stratigraphic unconformity. This area holds significant importance for future gas exploration efforts aimed at enhancing storage and production capabilities.

Based on the analyses of the core, cast thin section, physical property, CT, wireline loggings, well tests and seismic data, taking the Lower Cretaceous Yamama Formation in Oilfield A of the Central Arabian Basin as an example, the sedimentation and diagenesis characteristics and favorable reservoir distribution in semi-restricted carbonate ramp are clarified. The results show that semi-restricted carbonate ramp is enriched with Algae, Benthic foraminifera, Bivalve, Bacinella, and peloids, and is characterized by diverse low-energy and shallow-water lithofacies. The depositional environment of the Yamama Formation at early stage is dominated by open shelf, and then is dominated by large scale lagoon, locally being grain shoal, patchy reef, back shoal and tidal flat. There are three sequences in the Yamama Formation, namely I, II, and III, from bottom to top. During the regression cycle, the sequence I is dominated by cementation, the sequence II by dissolution, and the sequence III by alternating cementation and dissolution. The reservoirs are composed of packstone, wackstone and bindstone, with varying lithological sequence laterally which is difficult to be correlated. The reservoirs are porous, with the space contributed by micropores, moldic pores, and skeletal pores, as well as less primary intergranular pores, corresponding to medium- and micro-throats. The physical properties generally exhibit low to medium porosity, and low to ultra-low permeability. The medium-high permeability reservoirs are underdeveloped. It is found that the development of favorable reservoir in semi-restricted carbonate ramp are controlled by high-energy sedimentation locally, soluble bioclastic enrichment, and intense dissolution. Local high-energy grain shoals and patchy reef contain primary intergranular pores with no intense cementation, and they are important facies of favorable reservoirs in semi-restricted carbonate ramp. Low- to medium-energy facies such as lagoon and back shoal are rich in soluble bioclastics such as Algae and Bacinella. The bioclastics were intensely dissolved, forming a large number of moldic pores and skeletal pores, which effectively improved the reservoir physical properties, thus facilitating the formation of large-scale favorable reservoirs. The favorable reservoirs of the Yamama Formation in Oilfield A are mainly distributed in the north-central anticline axis of YA member and YB member.

The application framework leveraging large language models (LLMs) is explored to address the sophisticated demands of data retrieval and analysis, detailed well profiling, computation of key technical indicators, and the development of solutions in reservoir dynamic analysis (RDA). This framework encompasses a large language foundation model augmented with incremental pre-training, fine-tuning, and subsystems coupling. Key innovations in specialized fine-tuning technologies include named entity recognition (NER) based on prompt engineering, classification-based tool invocation, and Text-to-SQL construction, all aimed at resolving pivotal challenges in developing the specific application of LLMs for RDA. This study conducted a detailed accuracy test on feature extraction models, tool classification models, data retrieval models, and analysis recommendation models. The results indicate that these models have demonstrated good performance in various key aspects of reservoir dynamic analysis. The research takes some injection and production well groups in the real block of the PK3 Fault Block transition zone of the Daqing Oilfield as an example for testing. Testing results show that our model has significant potential and practical value in assisting reservoir engineers with RDA. The research results provide a powerful support to the application of LLM in reservoir performance analysis.

The fracture propagation and channeling patterns of zipper fracturing under the factory-like development mode of deep shale gas well remain unclear. Based on the finite element-discrete element method, a fluid-solid coupling model for fracture propagation of zipper fracturing was established, which incorporates the influence of natural fracture zone. This model was validated using both experimental data and field-monitored pressure surge data. Taking the deep shale gas reservoirs in southern Sichuan Basin as example, the propagation and channeling patterns of hydraulic fractures under the influences of natural fracture zones with various characteristics were investigated. The results show that the fracture zone with large approaching angle can block the forward propagation of hydraulic fractures and the intersection of inter well fractures. During pump shutdown, hydraulic fractures continue to expand under the net pressure driving. Under high stress difference, as the approaching angle of the fracture zone increases, the pressure increase of response well shows a trend of decreasing and then increasing, and the total length of hydraulic fractures tends to increase and then decrease. Compared to fracture zones with small approaching angle, natural fracture zones with large approaching angles require longer time to intersect; The width of fracture zone and the length of natural fractures, respectively, are negatively and positively correlated with the increase in response well pressure, and positively and negatively correlated with the time required for channeling, the total length of hydraulic fractures, and fracturing efficiency. As the well displacement increases, the probability of fractures channeling decreases, but the influence regularity between the well displacement and the increase in response well pressure and total length of hydraulic fractures is not obvious.

By benchmarking with the iteration of drilling technology, fracturing technology and well placement mode for shale oil and gas development in the United States, and considering the geological characteristics and development difficulties of shale oil in the Jiyang continental rift lake basin, the development technology system suitable for the geological characteristics of shale oil in continental fault lake basins has been primarily formed through innovation and iteration of development technology, drilling technology and fracturing technology. The technology system supports the rapid growth of shale oil production and reduces the development investment cost. By comparing with the shale oil development technology in the United States, the prospect of the shale oil development technology iteration in continental rift lake basins is proposed. It is suggested to continuously strengthen the overall three-dimensional development, improve the precision level of engineering technology, upgrade the engineering technical indicator system, accelerate the intelligent optimization of engineering equipment, explore the application of complex structure wells, form a whole-process integrated quality management system from design to implementation, and constantly innovate the concept and technology of shale oil development, so as to promote the realization of extensive, beneficial and high-quality development of shale oil in continental fault lake basins.

Based on an elaboration of the resource potential and annual production of tight sandstone gas and shale gas in the United States and China, this paper reviews the researches on distribution of tight sandstone gas and shale gas reservoirs, and analyzes the distribution characteristics and genetic types of tight sandstone gas reservoirs. It is indicated that, in the United States, the proportion of tight sandstone gas in the total gas production declined from 20%-35% in 2008 to about 8% in 2023, and the shale gas production was 8 310×10⁸ m³ in 2023, as about 80% of the total gas production, in contrast to the range of 5%-17% during 2000-2008. In China, the proportion of tight sandstone gas in the total gas production increased from 16% in 2010 to 28% or higher in 2023. China began to produce shale gas in 2012, with the production reaching 250×10⁸ m³ in 2023, as about 11% of the country's total gas production. The distribution of shale gas reservoirs is continuous. According to the fault presence and the gas layer thickness, the continuous shale gas reservoirs can be divided into two types: continual and intermittent. Most of previous studies believed that both tight sandstone gas reservoirs and shale gas reservoirs are continuous, but this paper holds that the distribution of tight sandstone gas reservoirs is not continuous. According to the trap types, tight sandstone gas reservoirs can be divided into lithologic, anticlinal, and synclinal reservoirs. The tight sandstone gas is coal-derived gas in typical basins in China and Egypt, but oil-type gas in typical basins in the United States and Oman.

This paper reviews the basic research means for oilfield development and also the researches and tests of enhanced oil recovery (EOR) methods for mature oilfields and continental shale oil development, analyzes the problems of EOR methods, and proposes the relevant research prospects. The basic research means for oilfield development include in-situ acquisition of formation rock/fluid samples and non-destructive testing. The EOR methods for conventional and shale oil development are classified as modified water flooding (e.g. nano-water flooding), chemical flooding (e.g. low-concentration middle-phase micro-emulsion flooding), gas flooding (e.g. mcro/nano bubble flooding), thermal recovery (e.g. air injection thermal-aided immiscible flooding), and multi-cluster uniform fracturing/water-free fracturing, which are discussed in this paper for their mechanisms, approaches, and key technique research and field test. These methods have been studied with remarkable progress, and some achieved ideal results in field tests. Nonetheless, some problems exist, such as inadequate research on mechanisms, imperfect supporting processes, and incomplete industrial chains. It is proposed to further strengthen the basic researches and expand the field tests, thereby driving the formation, promotion and application of new technologies.

To address the key problems in the application of intelligent technology in geothermal development, smart application scenarios for geothermal development were constructed. The research status and existing challenges of intelligent technology in each scenario were analyzed, and the construction scheme of smart geothermal field system was proposed. The smart geothermal field is an organic integration of geothermal development engineering and advanced technologies such as the artificial intelligence. At present, the technology of smart geothermal field is still in the exploratory stage. It has been tested for application in scenarios such as intelligent characterization of geothermal reservoirs, dynamic intelligent simulation of geothermal reservoirs, intelligent optimization of development schemes and smart management of geothermal development. However, it still faces many problems, including the high computational cost, difficult real-time response, multiple solutions and strong model dependence, difficult real-time optimization of dynamic multi-constraints, and deep integration of multi-source data. Therefore, the construction scheme of smart geothermal field system is proposed, which consists of modules including the full database, intelligent characterization, intelligent simulation and intelligent optimization control. The connection between modules is established through the data transmission and the model interaction. In the next stage, it is necessary to focus on the basic theories and key technologies in each module of the intelligent geothermal field system, accelerate the lifecycle intelligent transformation of the geothermal development and utilization, and promote the intelligent, stable, long-term, optimal and safe production of geothermal resources.

This article elucidates the concept of large model technology, summarizes the research status of large model technology both domestically and internationally, provides an overview of the application status of large models in vertical domains, outlines the challenges and issues confronted in applying large models in the oil and gas sector, and offers prospects for the application of large models in the oil and gas industry. The existing large models can be divided into three categories: large language models, visual large models, and multimodal large models. The application of large models in the oil and gas industry is still in its infancy. Based on open-source large language models, some oil and gas enterprises have released large language model products using methods like fine-tuning and retrieval augmented generation. Several scholars have attempted to develop scenario-specific models for oil and gas operations by using visual/multimodal foundation models. Additionally, a few researchers have constructed pre-trained foundation models for seismic data processing and interpretation, as well as core analysis. The application of large models in the oil and gas industry faces challenges such as current data quantity and quality being difficult to support the training of large models, high research and development costs, and poor algorithm autonomy and control. The application of large models must be guided by the needs of oil and gas business, to take the application of large models as an opportunity to improve data lifecycle management, enhance data governance capabilities, promote the construction of computing power, strengthen the construction of “artificial intelligence + energy” composite teams, and boost the autonomy and control of big model technology.