Natural hydrogen does not need to be prepared artificially and features zero carbon emissions over its entire lifecycle, making it a potential resource for filling the gap in hydrogen supply. However, the dynamic nature of natural hydrogen accumulation systems and the coupling relationships among generation, migration, accumulation, sealing and dissipation have not been systematically investigated. Based on the systems approach, this paper proposes a dynamic natural hydrogen accumulation system with the coupling of five elements (generation, migration, accumulation, sealing and dissipation), and reviews the generation pathways, occurrence states, migration mechanisms, dissipation processes, and preservation conditions of natural hydrogen. Natural hydrogen is mainly generated by water-rock interactions, water radiolysis and deep fluid activity, with the characteristics of continuity, multi-source superimposition and flux control. Natural hydrogen occurs in free, dissolved, and adsorbed states in the subsurface. Its preservation is constrained by physical diffusion, chemical reaction and microbial action. Its accumulation depends on whether hydrogen input can compensate for losses caused by migration and dissipation over a geological timescale. According to the coupling relationships among five elements under different geological backgrounds, three representative natural hydrogen accumulation models are identified: ophiolite-hosted self-generation and self-storage, cratonic-basement tight sealing, and fault-controlled sedimentary-basin accumulation. Natural hydrogen assessment should shift from static reserve evaluation to integrated constraints on hydrogen generation flux, migration efficiency, reservoir capacity, caprock sealing, and dissipation intensity. The proposed framework of dynamic accumulation provides additional systematic insights for research on geological theory and exploration of natural hydrogen.

Targeting the continental tight sandstone reservoirs of the Chang 8 Member of the Triassic Yanchang Formation in the Ordos Basin, China, a hydraulic fracturing test site was constructed in the Xifeng Oilfield. By deploying two differentially fractured wells and one coring well that served both experimental testing and production, multi-source technologies including core observation, microseismic monitoring, imaging logging, and ceramic proppant tracing were integrated to investigate directional fracture propagation patterns, fracture parameters, and proppant placement characteristics. The differentiated characteristics and identification methods are clarified for different fracture types. A total of 17 hydraulic fractures are identified in the 223.6 m-long core, revealing that the hydraulic fractures propagation is generally dominated by in-situ stress, with minor diversion locally, and the main fractures propagate in the direction of NE 73°. The hydraulic fractures predominantly extend as single fractures, with local inter-well coupling, and exhibit a non-uniform clustered distribution. The supported effective of the main fractures is approximately 180 m. A low-cost proppant design combining particle size grading and color coding is adopted, showing a non-uniform unimodal concentrated distribution along the fractures, with mixed particle sizes dominating the near-wellbore zone and small-sized particles prevailing at the distal end. The tight oil hydraulic fracturing test site in the Xifeng Oilfield has established a distinctive testing mode for precise fracturing of continental tight oil reservoirs, providing a practical basis for the cost-effective development of tight oil and a technical support for the stimulation of tight sandstone reservoirs similar to the Chang 8 Member reservoirs in the Xifeng Oilfield.

A commercial breakthrough in the in-situ conversion process (ICP) of lacustrine low-to-medium maturity shale oil requires that the energy output-to-input ratio (E_out/E_in) exceeds the economic threshold. The selection of the in-situ heating window represents one of the critical factors controlling E_out/E_in. Based on hydrocarbon generation simulations, hydrocarbon yield, and the evolution of porosity and permeability with increasing temperature for shale samples from the third submember of the seventh member of the Triassic Yanchang Formation (Chang-7₃ Member) in the Ordos Basin and the second member of the Cretaceous Nenjiang Formation (Nen-2 Member) in the Songliao Basin, China, this study demonstrates that the optimal control of the in-situ heating window can effectively reduce development costs. The results indicate that kerogen type and structure govern the main hydrocarbon generation window and the composition of “synthetic hydrocarbons”. Kerogen in the Chang-7³ Member is abundant in short side-chain hydrocarbon groups, resulting in earlier hydrocarbon generation and lighter products. In contrast, kerogen in the Nen-2 Member is rich in long-chain hydrocarbon groups, resulting in later hydrocarbon generation and heavier products, and it exhibits a conversion rate exceeding 80% and peak light hydrocarbon yield at both heating temperatures of 346 °C and 363 °C. Clay minerals in shale function as natural catalysts, lowering the activation energy for kerogen cracking and enhancing the yields of gaseous and light hydrocarbons. At 300-340 °C, light hydrocarbon mass yields from organic matter in montmorillonite-rich shale are 20%-50% higher than in montmorillonite-poor shale. A high clay mineral content effectively reduces the required heating window temperature. Shale porosity and permeability exhibit an inflection point corresponding to the main stage of “synthetic hydrocarbon” formation. At 300-350 °C, porosity and permeability increase markedly, with much greater enhancement parallel to bedding than perpendicular to bedding. At 350 °C, porosity increases by a factor of 7.3 and permeability by a factor of 265. The optimum in-situ heating windows for shale oil are determined to be 330-350 °C for the Chang 7₃ Member and 330-360 °C for the Nen-2 Member. Within these windows, synthetic hydrocarbon production, E_out/E_in, and product value are maximized, thereby significantly improving the economic viability of the resource.

In response to the issues of production decline and safety caused by liquid accumulation in wellbores during natural gas production, this paper proposes a method for liquid loading prediction and water-influx-induced shutdown warning based on the integration of a mechanism model and intelligent algorithms. Constrained by the liquid-carrying mechanism and driven by time-series production data, enhanced samples were generated using the mechanism model and through numerical simulation, and a dual-channel liquid loading prediction model and a multi-strategy water-influx-induced shutdown warning model were established. Then, physical constraints were introduced to correct the models, enabling a progressive analysis from liquid loading identification to shutdown warning. Applications in 56 wells in a tight gas field in China demonstrate a liquid loading identification accuracy of 91.6%, the initial identification point being 5 d and 3 d ahead of the designated one for the long-term and intermittent liquid loading cases, respectively, and the early warning of water influx 7 d in advance for typical shutdown cases. Among the shutdown cases, 49 cases (87.5%) were successfully detected by the model, with an average advance of 6.5 d. These findings are conducive to optimizing maintenance decisions, reducing the risk of unplanned shutdowns, and extending the production cycle of gas wells. The proposed models are promising for engineering application.

Visualization experiments of axial-torsional coupled percussion (ATCP) drilling in hot dry rock (HDR) were conducted using digital image correlation technique and multiscale characterization method. The evolution mechanism of high-temperature granite under ATCP mode was revealed, spanning from dynamic strain response and mesoscopic crack propagation to macroscopic rate of penetration (ROP) improvement. The results indicate that ATCP induces a coupled tensile-compressive strain response in granite, which develops a fracture network dominated by a transgranular-intergranular composite mode, thereby facilitating a transition in the rock-breaking pattern from high-energy crushing and grinding to low-energy volume spalling. The ATCP mode promotes alternation of rock principal strain between the positive and negative values by enhancing the coupled tensile-compressive strain response. This reduces the weight on bit and its fluctuation during drilling, ensuring a stable rock-breaking while improving the ROP and lowering the mechanical specific energy (MSE). Field test results from the geothermal well Fushen-1 showed that the ATCP mode significantly increases ROP and reduce MSE in HDR formations, demonstrating its great applicability for improving HDR drilling performance.

To address the limitation of conventional macroscopic wettability measurements in characterizing pore-scale wettability distributions in shale, a quantitative method for microscopic wettability characterization was developed. The method improves the conventional Amott approach by integrating nuclear magnetic resonance and high-pressure mercury intrusion porosimetry. Fluid distributions during spontaneous and pressurized imbibition in oil-water and oil-fracturing-fluid systems were measured, and a calculation model for the pore-size-dependent microscopic wettability index was established. The average microscopic wettability index derived from the proposed method agrees well with those obtained from gravimetric and macroscopic NMR measurements, validating the reliability of the method and revealing mixed-wettability characteristics that may be obscured by macroscopic averaging. The method was applied to interbedded, laminated, and mud-laminated shale cores from Well H181-1 in the Chang 7 Member of the Triassic Yanchang Formation, Ordos Basin. The results show that the original macroscopic wettability of the shale is generally neutral to oil-wet, whereas the overall water-wetness of all three core types increases markedly after fracturing-fluid interaction. However, the pore-scale wettability responses vary significantly among the three shale types. In the interbedded shale, local oil-wetness increases in small pores,whereas the intermediate and large pores generally become more water-wet. In the laminated shale, water-wetness increases markedly in small pores, the intermediate pores exhibit heterogeneous responses, and water-wetness decreases in large pores. In the mud-laminated shale, the small and intermediate pores shift toward more water-wet conditions, whereas the large pores exhibit heterogeneous wettability changes. These results clarify the pore-scale wettability distribution characteristics of shale reservoirs and provide a theoretical basis for fracturing-fluid selection, stimulation-parameter optimization, and enhanced oil recovery.

The concept of integrated source-to-sink system (IS2S) is proposed to systematically integrate fine-grained (<62.5 μm) clastic sediments into the source-to-sink framework, bridge the long-standing separation between coarse- and fine-grained sediment research, and unravel the complete sediment-routing system and multi-factor coupling along the source-to-sink pathway. The concept is based on multi-proxy provenance analysis and a comparison of marine and continental sedimentary records. The IS2S framework extends source-to-sink analysis from coarse-grained clasts to the full gravel-to-clay grain-size spectrum of terrigenous clastic sediments, places chemical weathering on an equal footing with physical denudation as a primary control, and unifies characterization of the dynamically coupled clastic and associated dissolved/colloidal fluxes within the same framework. Chemically and biogenically induced precipitates are explicitly treated as independent, parallel pathways outside the clastic grain-size spectrum. The framework further recognizes that coarse-grained sediment deposition is governed mainly by topographic gradients and tractive currents, whereas fine-grained sediment deposition is dominated by suspended transport and flocculated settling. Although terrigenous coarse- and fine-grained clasts share a common provenance, they differ markedly in transport and depositional mechanisms. Compared with coarse-grained source-to-sink systems, fine-grained systems are still constrained by non-unique provenance proxies, complex bottom-current reworking, and marked differences between marine and continental settings. The IS2S is intended primarily to characterize syndepositional sediment composition and depositional-body architecture, and can provide sedimentological constraints on quantitative provenance analysis of fine-grained sediments and on modeling the spatial co-occurrence of conventional and unconventional hydrocarbon accumulations.

Based on seismic, drilling, and outcrop data, fault geometry-kinematics analysis and balanced-section restoration were used to define the architecture and boundaries of the Awati Sag, Northern Depression, Tarim Basin, reconstruct its structural evolution history, and identify its hydrocarbon accumulation controls. The Awati Sag presents a framework of wedge-shaped structure with larger thickness in the west than in the east, as a result of multi-stage differential reactivation of the South Kalayuergun, Shajingzi, and Aqia-Tumuxiuke faults. Internally, conjugate and strike-slip fault systems form a multi-stage, vertically differentiated, heterogeneous 3D deformation network with a composite structural style. Its structural evolution history includes two stages: a pre-sag stage, and a sag stage. The former stage can be divided into five sub-stages: the Jinningian rifting center, the Early-Middle Caledonian intracratonic depression, the Middle-Late Caledonian post-uplift of the peripheral foreland basin, the Early-Middle Hercynian northwestern Tarim paleo-uplift, and the Late Hercynian rifting center, while the later stage into 3 sub-stages: the Indosinian embryonic sag, the Yanshanian paleo-uplift slope, and the Himalayan final shaping. Principal source rocks are the high-quality marine Cambrian Yuertusi and Ordovician Saergan formations, supplemented by the Ordovician Yingan Formation and Permian-Triassic coal measures and dark mudstones. Thermal evolution shows the characteristics of long-term shallow burial followed by rapid deep burial. Within the total petroleum system, near-source fractured-vuggy/tight sandstone and far-source structural-lithologic reservoirs form a composite play, with in-source shale oil/gas as a potential target. The eastern slope has the greatest exploration potential.

Taking the shale of Cretaceous Qingshankou Formation in Songliao Basin as an example, this study adopts experimental methods including X-ray diffraction analysis, field emission electron microscopy, atomic force microscopy, two-dimensional nuclear magnetic resonance, combined with the test of pressure-preserved sealed core ultra-low temperature frozen samples, to discuss the coupling relationship between the diagenetic evolution of organic-clay complex and the “four properties” of shale, i.e., reservoir property, oil-bearing property, mobility and fracability. (1) The oil content of organo-clay complex initially increases and then decreases with increasing diagenesis, with the maximum oil content exceeding twice that of the corresponding bulk shale, indicating a significant contribution to shale oil production. The decrease in oil content of organo-clay complex during the middle diagenetic stage B suggests that a portion of the crude oil has micro-migrated into other shale pores for storage. (2) The BET specific surface area and pore volume of organo-clay complex show a trend of first increasing and then decreasing with diagenetic evolution, reaching maximum values of 65 m²/g and 0.15 cm³/g, respectively, at the end of the middle diagenetic stage A₁. From middle diagenetic stage A₂ to middle diagenetic stage B, volume shrinkage of the organo-clay complex generates abundant organo-clay complex pores and bedding-parallel fractures, resulting in an increase in effective porosity of the shale from 5% to 10% or so. (3) The transformation of clay minerals within the organo-clay complex and the formation of authigenic minerals such as quartz lead to improved shale fracability. In the middle diagenetic stage B, the shale exhibits an elastic modulus greater than 20 GPa, a Poisson’s ratio less than 0.2, and a brittleness index greater than 65%. (4) Both the organo-clay complex and the bulk shale show increasing free oil content with progressive diagenesis, indicating improved shale oil mobility. During the middle diagenetic stages A₂ and B, dehydration of clay minerals results in an increase in pore water content of the shale, reaching a maximum of 11.8 mg/g, which suggests alterations in the wettability of shale flow pathways that are favorable for water-oil displacement and imbibition during hydraulic fracturing. Integrating the shale oil enrichment model and the coupling relationships among the “four properties” parameters, three types of shale oil “sweet spot” zones (intervals) are categorized. The findings of this study hold significant theoretical implications for the exploration evaluation and development practice of continental high-clay-content shale oil.

This study integrates modern and ancient sedimentological analogs, as well as surface and subsurface geological analyses, using outcrops, modern sediments, cores, well logs, seismic data, production data, and laboratory test data to comprehensively investigate the geologic age and distribution the Kalazha Formation in the southern Junggar Basin, and its relationship with the Qingshuihe Formation. The results are obtained in four aspects. First, the Kalazha Formation comprises a series of sandy and gravelly distributive fluvial systems (DFSs) in the piedmont zone of the southern Junngar Basin. These systems vary in scale and sedimentary facies, including coarse-grained alluvial fan, fluvial fan, sandy fluvial mega-fan, and their relative (fan) deltas. The Kalazha Formation is widely distributed across the southern Junggar Basin, forming apron-like bodies along the basin margin, with thickness decreasing from south to north and from east to west. The Kalazha Formation is also well developed in the western part of the southern Junggar Basin. Third, the Kalazha Formation conglomerates and the Qingshuihe Formation sand-mudstones are alternating and superimposed vertically near the piedmont outcrop, exhibiting continuous deposition and a conformable contact. Laterally, they represent contemporaneous difference facies. Towards the basin center, the Kalazha Formation conglomerates gradually thin, pinch out, and transition to the fine-grained deposits of the Qingshuihe Formation and the Tugulu Group. Four, the stratigraphic affiliation of the Kalazha Formation is related to the Jurassic-Cretaceous boundary in the southern margin of the Junggar Basin. However, the delineation of this boundary remains uncertain. It is suggested that more biostratigraphic and chronostratigraphic data be accumulated. Drilling results confirm that the Kalazha Formation has the basic conditions to contribute high-quality hydrocarbon reservoirs. Future research should strengthen quantitative characterization of sedimentary systems in this interval and pay attention to the associated lithofacies paleogeographic changes during the Jurassic-Cretaceous transition, thereby providing more evidence for hydrocarbon exploration.

To address the requirements for comprehensive analysis of multi-source geological information and intelligent decision-making in shale oil exploration and development, this paper proposes a methodology for constructing a domain-specific large language model (LLM) for the shale oil field, along with methods for building and evaluating an LLM-based intelligent agent for shale oil seismic processing and interpretation. Utilizing Qwen2.5-72B and Qwen3-32B as foundation models, we integrated publicly available shale oil literature with domain knowledge graphs to construct a specialized corpus comprising 21 billion tokens. Leveraging expert annotations and model generation, we compiled 58,000 high-quality domain-specific question-answer pairs to form the supervised fine-tuning dataset. We propose a multi-stage, efficient domain-adaptation training framework for shale-oil large language models (LLMs). Domain knowledge is injected via task-aware expanded continual pre-training; supervised fine-tuning is then performed by combining Quantized Low-Rank Adaptation (QLoRA) with context-parallel algorithms. Direct Preference Optimization (DPO) and Group Relative Policy Optimization (GRPO) are employed to align disciplinary preferences and strengthen reasoning capabilities. Furthermore, a reflective retrieval-augmented generation (RAG) framework is constructed to improve the accuracy and interpretability of model outputs. Building on the LLM, we curate a specialized toolkit from open-source geoscience tools and conduct tool-use-oriented supervised fine-tuning to enhance the model’s tool-calling capability while effectively mitigating hallucinations during tool invocation. Leveraging the Model Context Protocol (MCP), we deploy an intelligent scheduling service that deeply integrates such core functionalities as seismic data processing, seismic interpretation, visualization and report generation, and construct an LLM-driven agent for shale-oil seismic processing and interpretation. Experimental evaluations demonstrate that the shale-oil LLM significantly outperforms general-purpose base models in professional question answering and has superior domain-adaptation performance. After tool-use supervised fine-tuning, its tool-calling capability is substantially improved compared with open-source base models.

Taking the Permian clastic buried-hill reservoirs in the Jiyang Depression, Bohai Bay Basin, China, as the research object, core samples, thin-section observations and experimental/test data were utilized to investigate reservoir characteristics and diagenetic fluid types/assemblages, and identify the reservoir-controlling factors. On this basis, a reservoir-controlling model was established. The results show that four types of diagenetic fluids are developed in the clastic buried-hill reservoirs, namely alkaline water associated with tuffaceous alteration, meteoric fresh water, hydrothermal fluid, and organic acid. Fluid assemblages vary distinctly among different buried-hill reservoirs. The Gubei buried-hill is characterized by the assemblage of meteoric fresh water + volcanic hydrothermal fluid + organic acid. The Gaoqing buried-hill and the Yihezhuang-Dawangzhuang area both develop the assemblage of alkaline water associated with tuffaceous alteration + meteoric fresh water (relatively weak) + organic acid. Among these fluids, meteoric fresh water and organic acid exert constructive modification on reservoir quality. Reservoirs are synergistically controlled by multiple factors such as fault-related fractures, weathering crust, soluble sedimentary components, and diagenetic fluids. The established “three-element and six-factor” reservoir-controlling model yields predictions that display a significant positive correlation with measured reservoir physical properties. Sand bodies with coarse grains, large thickness and abundant tuffaceous components formed during the sedimentary period provide the material basis for high-quality reservoir formation. Meteoric fresh water dissolves soluble components within reservoirs during the uplifting stage, whereas organic acid improves reservoir quality via further dissolution during the burial stage. The proposed model supplies new geological theoretical support for the prediction of clastic buried-hill reservoirs.

Focusing on Shunbeilong 2, a well with commercial oil/gas flow from the Ordovician Penglaiba Formation in the dome structure in the Shunbei area in the Tarim Basin of China, the drilling, logging, testing and thin-section data were integrated for petrologic analysis, microscopic temperature measurement of fluid inclusions, C/O isotope analysis, trace element analysis, and U-Pb dating. The pore space, fluid properties/origin, and controlling factors of the Penglaiba Formation reservoirs were delineated, together with their genetic mechanisms. Finally, a reservoir development model was established. The results indicate that the Penglaiba Formation dolomite reservoirs are distributed in the form of thin interbeds and quasi-layers, with the pore space consisting of fabric-selective vugs which are superimposed by reticular fractures. Image logging data reveal a weak correlation between vug intervals and fracture intervals, demonstrating that vugs were formed primarily under the control of high-frequency sequence boundaries. The matrix is predominantly composed of medium-to-coarse crystalline dolomite, with minor fine crystalline dolomite and late calcite cements. The U-Pb age of medium-to-coarse crystalline dolomite is dated to 464±14 Ma; this dolomite shares inherited seawater-derived dolomitizing fluid signatures with fine crystalline dolomite and vug-filling dolomite cements. The homogenization temperatures of fluid inclusions hosted in secondary quartz and late calcite are concentrated at 150 ℃-160 ℃ and 130 ℃-140 ℃, respectively, and the in-situ U-Pb age of late calcite yields 450±3.4 Ma. It is proposed that the Penglaiba Formation dolomite reservoirs have evolved in four stages: selective dissolution controlled by high-frequency sequence boundaries during the penecontemporaneous period; dolomitization under shallow burial conditions; hydrothermal fluid modification of carbonate rocks along fault-fracture systems; and reworking by superimposed reticular fractures.

Application of CO₂ pre-fracturing to displace the shale oil of the Permian Fengcheng Formation in the Mahu Sag, the Junggar Basin, suffers from gas channeling, asphaltene precipitation, emulsification and viscosity increase of crude oil under fracturing impact, and low utilization rate of CO₂. To address these problems, a high-temperature and high-pressure visual silicon tube experimental system was used, together with Raman-infrared microscope and stereoscope, to study the interaction between CO₂ and crude oil in fractures and microfissures, and to reveal the influence mechanism of solubilizer on the dissolution characteristics, foam oil behavior and flow stability of CO₂-crude oil system. The results show that, during displacement at higher pressure, the solubilizer can greatly reduce the start-up pressure and oil-water interfacial tension of CO₂-crude oil system, enhance the dissolution and retention capacity of CO₂ in crude oil, form a stable and fine foam oil structure, inhibit bubble aggregation and delay gas release, thereby delaying the process of gas channeling, and improving the sweep and oil displacement efficiency of CO₂. The effect is better when the mass fraction of solubilizer is 1.0%. During production at lower pressure, the solubilizer can inhibit the precipitation of resin and asphaltene by means of peptization, thus reducing the risk of plugging near wellbore and in pore throat, and improving the mobility of crude oil in hydraulic fractures. The field data confirm that the solubilizer performs well in increasing production, and it provides a technical option for the efficient development of shale oil in the Mahu Sag.

The current status of volume fracturing technology is reviewed for continental shale oil reservoirs in China. Considering the limited hydraulic fracture propagation and proppant transport under the prevailing “long-fracture” volume fracturing model in horizontal wells, a new “wide-short fracture” volume fracturing model is proposed to fully stimulate the reservoir in the near-wellbore zone, in accordance with four principles: multi-cluster fracture placement, balanced fracture propagation, appropriate treatment scale, and economics-based parameter selection. Beyond the energy allocation pattern in current fracturing practices, the new model is designed logically to concentrate fracturing energy in the near-wellbore zone region. This redistribution enables balanced propagation of multiple fractures and full-domain propping, thereby enhancing the connectivity between the fracture system and the oil-bearing matrix, expanding the fracture-controlled reservoir volume, and achieving coordinated reservoir control by wells and fractures. Five core elements underpin the proposed fracturing design: refined geological modelling of the in-situ stress field; techniques for controlling balanced fracture propagation; high-density perforating with uniform entry-hole diameters; techniques for full-domain propping of complex fracture systems; and a framework for jointly optimizing well patterns and well spacing. Comparative numerical model predictions for different fracturing models indicate that the proposed model can substantially increase both total ultimate recoverable reserves and the ultimate oil recovery factor at the well-pad scale in continental shale oil reservoirs. These findings can provide a theoretical basis and engineering support for the large-scale, cost-effective development of continental shale oil reservoirs in China.

Dolomite reservoirs are important targets for oil and gas production. However, the correlation among types, spatial distribution, geometric configurations, and seismic responses of large-scale dolomite reservoirs remains unclear, hindering the reservoir prediction and hydrocarbon exploration. This study establishes a database of Neoproterozoic-Lower Paleozoic dolomite reservoirs in the Tarim Basin and conducts comparative and analogical analyses between basin data and global data, in order to investigate the coupling among formation mechanisms, spatial distribution, internal configurations, and seismic responses of large-scale dolomite reservoirs. The database includes data from 16 oil and gas fields/reservoirs in the Tarim Basin, data from some regional exploration wells that encountered dolomite reservoirs but have not revealed oil and discoveries, as well as data from typical global dolomite hydrocarbon reservoirs. The analysis results indicate that the dolomite reservoirs are governed by the superimposition of multiple factors, but their spatial distribution and geometric configurations are primarily decided by three mechanisms: sedimentation, karstification, and tectonism. Accordingly, the dolomite reservoirs are classified into sedimentary, karst, and tectonic types. Through reservoir configurations analysis and global comparison, ten subtypes of dolomite reservoirs are identified. Finally, the patterns of coupling among types, spatial distribution, geometric configurations, and seismic responses of dolomite reservoirs are clarified, and the geological models and seismic identification markers for each subtype are established, providing reference for geological survey and practical exploration of oil and gas in dolomite reservoirs.

The Sinian Dengying Formation in central Sichuan Basin is characterized by complex hydrocarbon accumulation processes, significant uncertainties regarding the timing of paleo-oil reservoir formation, and a limited availability of absolute age data. In this study, petrographic observations, fluid inclusion analysis, carbonate U-Pb dating, and paleo-oil-water interface reconstruction were integrated to decipher the diagenetic-hydrocarbon accumulation evolution sequence of the Dengying Formation reservoirs in central Sichuan Basin and to precisely clarify the formation timing of paleo-oil reservoirs. The results reveal that the first-stage paleo-oil reservoirs with a limited scale were formed in the Late Cambrian-Early Ordovician, and the second-stage large-scale paleo-oil reservoirs were formed during the Middle Triassic, approximately 30 million years earlier than the previously proposed Late Triassic. The paleo-uplift of the Dengying Formation was more extensive during the Middle Triassic than in the Late Triassic, which controlled a broader distribution of paleo-oil reservoirs. These paleo-oil reservoirs exhibited features of widespread contiguous oil-bearing, quasi-continuous distribution, and relative enrichment in structural highs, providing liquid hydrocarbon precursors for the subsequent development of large-scale oil-cracking gas reservoirs. The findings improve our understanding of natural gas exploration potential for the Sinian strata in the Sichuan Basin and suggest favorable gas exploration prospects for structural-lithologic traps within the Central Sichuan paleo-uplift and its peripheral areas.

Under the dual constraints of carbon neutrality and energy security, this study systematically examines the background, advantages, initiatives, and strategic significance of integrated development of oil and gas industry with new energy, based on resource endowment in China characterized by abundant coal, limited oil and gas, and vast renewable energy potential, together with its high dependence on imported oil and gas. Furthermore, the principle of “inexhaustible energy” is revealed according to three global energy development laws: succession, decarbonization and inexhaustibility. The oil and gas industry possesses inherent advantages such as integrated source-grid-load-storage (SGLS) systems, on-site consumption of renewable resources in oil and gas fields, flexible peak-shaving through natural gas-fired power generation, and the evolution of conventional oil and gas fields toward multi-energy systems encompassing power generation, geothermal energy, hydrogen production and carbon management. These advantages provide a solid foundation for deep coupling between fossil fuels and renewable energy. In terms of implementation, a comprehensive integration framework covering upstream and downstream sectors is established and advanced through three successive stages: the clean substitution and demonstration breakthrough stage, the strategic replacement and large-scale integration stage, and the green transition and carbon neutrality realization stage. Strategically, the integrated development can enhance national energy self-sufficiency and system resilience, accelerate deep decarbonization of the oil and gas industry and its transition toward integrated energy services, provide a Chinese solution for the smart integration of oil, gas and new energy, and strengthen the influence of China in global green energy governance. The integrated development of oil, gas, and new energy represents an indispensable pathway toward safeguarding national energy security, fulfilling China’s dual-carbon goals, and building an energy powerhouse.

This study compares the apparent hydrogen diffusion characteristics of typical rocks, their controlling factors, and the sealing performance of different caprocks. A two-chamber gas diffusion apparatus was used to determine the apparent diffusion coefficient (D_app) of 25 sedimentary, igneous, and metamorphic rock samples under isobaric conditions at 0.1 MPa. Representative samples were further tested for the effects of temperature, effective stress, water content, and counter-diffusing gas composition, followed by one-dimensional diffusion simulations using the measured parameters. The results show that: (1) At an effective stress of 1 MPa, D_app ranges from 2.54×10^-9 to 358.43×10^-9 m²/s, with most values between 10×10^-9 and 100×10^-9 m²/s, and is positively correlated with porosity. Hydrogen diffusion is relatively high in sandstones, coals, and some high-porosity shales and carbonate rocks. The tested basalt, granite, and diabase samples show low to moderate diffusion, whereas the tested serpentinite and salt rock samples exhibit lower diffusion. (2) Increasing temperature from 278.15 to 318.15 K increases D_app by 11.9%-34.4%. Increasing effective stress causes an exponential decrease in D_app, with stress sensitivity decreasing in the order of salt rock, serpentinite, diabase, shale, sandstone, and limestone. Increasing water content markedly suppresses hydrogen diffusion. (3) Compared with N₂, CH₄ causes only minor changes in D_app, whereas CO₂ reduces D_app by an average of 8.6%. (4) Increasing caprock thickness and water content reduces hydrogen diffusion and loss. Among the selected caprock samples, dry salt rock shows the strongest sealing performance, while shale performs no worse than diabase at comparable water contents. Overall, apparent hydrogen diffusion coefficient is jointly controlled by porosity, pore-throat structure, connectivity, effective stress, and water content. Caprock sealing evaluation should therefore consider lithology, thickness, effective connectivity, and in-situ water conditions.

To systematically examine the paradigm shift of sedimentary paleogeography research driven by artificial intelligence, and clarify the technical integration pathways and core challenges, this study combines theoretical analysis and typical case analysis to summarize the multi-dimensional characteristics of the paradigm shift and explore a new framework for intelligent paleogeographic reconstruction. The results show that the paradigm of sedimentary paleogeography research is undergoing a systematic transformation across four dimensions: the data foundation shifts from experience-driven to data-driven, the cognitive mode from qualitative description to quantitative characterization, the prediction target from static representation to dynamic prediction, and the decision-making mode from single-discipline analysis to systematic decision-making. Accordingly, a comparative framework of traditional empirical, digital, and intelligent paradigms is constructed. In three key aspects, i.e. paleogeographic reconstruction, sedimentary process simulation, and reservoir parameter prediction, the methods such as knowledge graphs, physics-informed neural networks, and ensemble learning have demonstrated significant integration effectiveness. Furthermore, a technical workflow framework for intelligent paleogeographic reconstruction is proposed, encompassing core modules including multi-source data fusion, knowledge graph constraints, machine learning prediction, expert validation, and feedback iteration. This work provides a systematic theoretical reference and technical pathway for the digital-intelligence transformation of sedimentary paleogeography.

Based on the core, cast thin section, CT, loggings, test and seismic data, the sedimentary-diagenetic characteristics and controls on favorable reservoirs in semi-restricted carbonate ramp setting were elucidated, through a case study of the Lower Cretaceous Yamama Formation in Oilfield A of the Central Arabian Basin. During the Early Cretaceous, the study area was a carbonate ramp in semi-restricted environment, where low- to medium-energy shallow-water lithofacies were common, and the depositional facies were dominated by large-scale lagoon, locally with grain shoal, point reef, back shoal and tidal flat. Bioclastics were diverse, with algae, benthic foraminifera, bivalve, bacinella, and peloids being the most abundant. The Yamama Formation in the study area underwent intense diagenesis during the penecontemporaneous stage, with cementation and dissolution coupled to control the formation and preservation of secondary pores. The reservoirs in the Yamama Formation are composed of packstone, wackstone and bindstone, indicative of frequently varying lithology with poor lateral correlatability. The reservoirs are porous, dominated by micropores, moldic pores, and skeletal pores, with a low abundance of primary intergranular pores, and the pore throats dominated by 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. Favorable reservoirs in the Yamama Formation are controlled by local high-energy sedimentation, soluble bioclastic enrichment, intense dissolution, and abnormal-high pressure. Local high-energy grain shoals contain well-preserved primary intergranular pores with no intense cementation, forming small-scale favorable reservoirs. In contrast, low- to medium-energy facies such as lagoon and back shoal are locally rich in soluble bioclastics such as algae and bacinella. The bioclastics were intensely dissolved, forming a large number of moldic or skeletal pores, which effectively improved the reservoir physical properties, thus facilitating the formation of large-scale favorable reservoirs. The favorable reservoirs of Yamama Formation are mainly discovered in YA and YB sections, and large-scale reservoirs thereof are located in the central-northern part of the study area. These represent key targets for subsequent exploration and development.