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 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 Permian Wujiaping Formation, and it is developed in the Kaijiang-Liangping trough in the northern part of Sichuan Basin, where deep-water continental shelf facies and deep-water reduction environment with thriving siliceous organisms have formed the black siliceous shale rich in organic matter. Second, the Dalong Formation shale contains both organic and inorganic pores, with stratification of alternated brittle and plastic minerals, which was stacked with severe compaction to enlarge fractures, thereby improving the permeability. In addition to organic pores, a large number of inorganic pores are developed even in ultra-deep (deeper than 4 500 m) layers, contributing a total porosity of more than 5%, which significantly expands the accommodation space for shale gas. Third, the limestone at the roof and floor of the Dalong Formation acted as seal rock 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 less than 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 less than 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.

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 between NGH resource potential and conventional oil and gas resource and a NGH resource evaluation model based on the whole petroleum system (WPS) and through the analysis of dynamic field controlling hydrocarbon accumulation. 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), surface volume conversion factor difference between conventional natural gas and NGH, and the impacts of differences in favorable 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.

The lamina (combination) types, reservoir characteristics and shale oil occurrence states of organic-rich shale in the Triassic Yanchang Formation 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 mechanisms and patterns of shale oil were discussed using the shale oil 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 shale mainly develops five types of lamina combination, i.e. non-laminated (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 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 property, thermal evolution degree, mineral composition and laminae scale. The micro-nano pores and fractures in the 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 → mudstone. 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.

In recent years, drilling data from 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 limestone reservoirs in the Upper Permian Changxing Formation, which breaks the traditional view that deep carbonate oil and gas are 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, the study on formation mechanism of pores in deep reef-beach limestone reservoirs is carried out, 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 composed of intergranular 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 high-pressure inside the reef-beach complexes under the continuously increasing 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 roof 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 high-pressure in the Changxing Formation is formed. Abnormal high-pressure (overpressured compartment) is the key to maintain the pores formed in the sedimentary and surface environments 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.

Based on the comprehensive analysis of data from petrology and mineralogy, well logging, seismic surveys, paleontology, and geochemistry, a detailed research was conducted on paleoenvironmental and paleoclimatic conditions, and modeling of the source rocks in the second member of the Eocene Wenchang Formation (Wen 2 Member) in the Northern Shunde Subsag at the southwestern margin of the Pearl River Mouth Basin. The Wen 2 Member hosts excellent, thick lacustrine source rocks 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 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 intense rifting period in the Eocene, excellent source rocks were developed in Wen 2 Member in the Northern Shunde Subsag 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 of organic matters. 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.

The formation water sample in oil and gas fields is highly susceptible to being polluted, making the properties of formation water not be reflected truly. This paper discusses the identification methods and data credibility evaluation method for formation water in oil and gas fields of petroliferous basins within China. 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 and desulfurization coefficient and evaluating the geological setting. The basic identifying methods for formation water 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 and 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 formation water is believed with high credibility.

To address the challenges in studying the pore formation and evolution processes, and unclear preservation mechanisms of deep to ultra-deep carbonate rocks, a high-temperature and high-pressure visualization simulation experimental device was developed for ultra-deep carbonate reservoirs. Carbonate rock samples from the Sichuan Basin and Tarim Basin were used to simulate the dissolution-precipitation process of deep to ultra-deep carbonate in an analogous geological setting. This unit comprises four core modules: an ultra-high temperature, high pressure triaxial stress core holder module (temperature higher than 300 °C, pressure higher than 150 MPa), a multi-stage continuous flow module with temperature-pressure regulation, an ultra-high temperature-pressure sapphire window cell and an in-situ high-temperature-pressure fluid property measurement module and real-time ultra-high temperature-pressure permeability detection module. The experimental device was used for simulation experiment, and the geological insights were obtained in three aspects. First, the pore-throat structure of carbonate reservoirs 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 formed continuously are controlled by 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 (deeper than 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. In 2024, 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 aryl-isoprenoid alkane biomarkers were detected, but triaromatic dinosterane was absent. This finding is well consistent with the geochemical characteristics of the Newfoundland sulfidized slope SRs represented by those in wells LT-1 and QT-1, suggesting that the Newfoundland SRs are the main source of the Cambrian petroleum discovered in Well XT-1. Cambrian crude oil of Well XT-1 also presents the predominance of C₂₉ steranes and is rich in long-chain tricyclic terpanes (up to C₃₉), which can be the 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 possible to receive effective supply of hydrocarbons from the Cambrian Newfoundland SRs in Manxi hydrocarbon-generation center. 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.

Based on the data of drilling, logging, experiment and gas testing in the Nanchuan area, southeastern Sichuan Basin, the hydrocarbon generation potential, gas genesis, occurrence state, migration characteristics, preservation conditions, pore and fracture features and accumulation evolution of the first member of Permian Maokou Formation (Mao 1 Member) are systematically studied, and the main controlling factors of unconventional gas enrichment and high production in marlstone assemblage of Mao 1 Member are discussed. (1) The enrichment and high yield of unconventional natural gas in the Mao 1 Member are controlled by three factors: carbon-rich fabric controlling hydrocarbon generation potential, good preservation controlling enrichment, and natural fracture controlling production. (2) The carbonate rocks of Mao 1 Member with carbon rich fabric have significant gas potential, exhibiting characteristics of self-generation and self-storage, which lays the material foundation for natural gas accumulation. (3) The occurrence state of natural gas is mainly free gas, which is prone to lateral migration, and good storage conditions are the key to natural gas enrichment. Positive structure is more conducive to natural gas accumulation, and a good compartment is created jointly by the self-sealing property of the Mao 1 Member and its top and bottom sealing property in monoclinal area, which is favorable for gas accumulation by retention. (4) Natural fractures are the main reservoir space and flow channel, and the more developed natural fractures are, the more conducive to the formation of high-quality porous-fractured reservoirs and the accumulation of natural gas, which is the core of controlling production. (5) The accumulation model of unconventional natural gas is proposed as “self-generation and self-storage, preservation controlling richness, and fractures controlling production”. (6) Identifying fracture development areas with good preservation conditions is the key to successful exploration, and implementing horizontal well staged acidizing and fracturing is an important means to increase production and efficiency. The study results are of referential significance for further understanding the natural gas enrichment in the Mao 1 Member and guiding the efficient exploration and development of new types of unconventional natural gas.

Taking the natural gas reservoirs of the Sinian Dengying Formation on the east and west sides (Gaoshiti-Moxi area and north slope of central Sichuan paleo-uplift on the east; Weiyuan and Well Datan-1 block on the west) of the Deyang-Anyue rift trough in the Sichuan Basin, China, as the research object, the geochemical parameters (component, isotopic composition) of natural gas from the Dengying Formation in different areas are 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 are less affected by TSR modification, though the δ¹³C₁ values are slightly greater than that of the reservoirs on the east side with partial reversal of carbon isotope composition, likely due to the water-soluble gas precipitation and accumulation mechanism. The Dengying gas reservoir of Well Datan-1 shows no influence from TSR. Third, the Dengying gas reservoirs reflect high helium contents (significantly 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 values of the Dengying gas reservoirs on the west side are slightly lighter than those on the east side. Fifth, the Dengying natural gas in the Datan-1 area is contributed by the source rocks of the Sinian Doushantuo Formation and the third member of the Dengying Formation, in addition to the Cambrian Qiongzhusi Formation.

Based on the test and experimental data from exploration well cores of the Upper Paleozoic in the central-eastern Ordos Basin, combined with structural, burial 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 transition zone between shallow-medium open fluid system and deep closed fluid system. Reservoirs above 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 content 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 m³/t to 8 m³/t (greater than 10 m³/t in some seams). Second, the gas accumulation 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 wide and gentle 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 parameter reference for precise zone evaluation and innovation of adaptive stimulation technologies for deep resources.

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 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 functional groups. Additionally, hydrocarbon generation within organic-clay composites during high-over mature stages may induce volumetric expansion, resulting in microfracturing and hydrocarbon expulsion. The associated higher hydrocarbon expulsion rates promote the formation of larger pores and fracture-shaped pores adjacent to flake-shaped clay minerals. This study highlights that the research of submicron-scale molecular functional groups provides a deeper understanding of organic matter evolution and pores development mechanisms in overmature shales, thereby offering critical theoretical parameters for reservoir evaluation in shale oil and gas exploration.

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, the 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 (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.

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. The bubbles are ellipsoidal during rising, with little influence of wellbore inclination angle on 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.

To address 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 induced deformation during oil and gas reservoir development is derived from the perspective of semi-infinite strata. A brand-new volume boundary element numerical method solution has been developed and verified and tested. The influences of internal flow and flow 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. Calculation methods for the flow equivalent force and boundary equivalent force 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 respectively, and then summing them up. This numerical method is termed the Volumetric Boundary Element Method (VBEM). Compared with traditional commercial simulators, the VBEM fully considers the effects of reservoir flow boundaries, pore pressure gradient fields within the reservoir, and fluid mass changes within pores on formation deformation. It eliminates the need for meshing outside the reservoir, achieves significantly improved solution accuracy, and provides a new technical framework for simulating deformation induced by reservoir development.

The Carter model is used to characterize the dynamic behaviors of fracture growth and fracturing fluid leakoff. A thermo-fluid coupling temperature response 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. Typical V-shaped characteristics can be observed from the DTS responses in the multi-cluster fracturing process, with locations corresponding to the 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.

By comprehensively considering the influences of temperature and pressure on fluid density in high temperature and high pressure (HTHP) wells in deepwater fractured formations 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 study 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 a constant maximum 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 head pressure prediction and 98.3% accuracy in target shut-in time. 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.

By summarizing the characteristics of the global energy structure and China’s energy resource endowment, this study analyzes the historical context and opportunities for China to build an “energy powerhouse”, and proposes pathways and measures for its realization. It is indicated that the energy resource endowment in China is characterized by abundant coal, limited oil and gas, and vast renewable potential, coupled with an energy consumption structure characterized by high coal consumption, low oil and gas consumption, and rapidly growing renewable energy use. The concept of the “whole-energy system” has been explicitly clearly defined, the “whole-energy system” approach that integrates multi-energy complementarity, green development, stable supply, smart utilization and carbon neutrality is an effective solution to addressing energy transition and energy independence. To build an “energy powerhouse,” China can follow the approach of the steady and orderly low-carbon development of fossil fuels, the safe and scaled development of new energy, the integrated development of a carbon-neutral “whole-energy system”, and the shared development of the “Belt and Road” energy corridor. China’s construction of an “energy powerhouse” should follow a “three-phase” strategic pathway: from 2025 to 2030, achieving peak primary energy consumption and “carbon peaking”; from 2031 to 2050, energy production will achieve parity with consumption for the first time, striving for “energy independence”; and from 2051 to 2060, aiming for “carbon neutrality”, and establishing an “energy powerhouse”. Building an “energy powerhouse” will fundamentally safeguard national energy security, advance the achievement of carbon neutrality goals, provide Chinese solutions for global energy transition and green Earth construction, and support the modernization and great rejuvenation of the Chinese nation.

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. 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 construction 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 talent cultivation and academic disciplines, fostering university-enterprise research collaborations.

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.