Oil and gas resources serve as the foundation of the oil and gas industry and are vital to the sustained and healthy development of the national economy. Since the implementation of the "Continuously Intensifying Domestic Oil and Gas Resource Exploration and Development" initiative in 2019, domestic natural gas reserves and production have shown rapid growth. The medium- to long-term domestic natural gas consumption demand will continue to rise, making the mission of strengthening domestic self-sustained natural gas supply security both critical and urgent. Based on the progress in natural gas exploration and new geological insights since the 14th Five-Year Plan, a systematic reassessment of conventional and unconventional natural gas in-place resources in 27 onshore basins including Sichuan, Ordos, and Tarim, revealed a total of 191.90 trillion cubic meters, with a proven rate of only 12.7%, indicating a solid resource foundation for the future rapid development. The proven rate of conventional natural gas in-place resources is 16.3%, with remaining unproven resources amounting to 58.48 trillion cubic meters. The foreland and deep layers of three major cratonic basins, i.e., Sichuan, Tarim, and Ordos in central and western China, will continue to be the key targets for future conventional natural gas exploration, with an estimated 5.0-7.0 trillion cubic meters of additional reserves potential over the next five to ten years. The remaining unproven resources of unconventional tight gas is 26.52 trillion cubic meters, with exploration efforts concentrated in the Sichuan and Ordos basins, and an estimated 1.9-2.5 trillion cubic meters of additional reserves potential over the next five to ten years. The remaining unproven resources of unconventional shale gas is 48.50 trillion cubic meters, primarily distributed in the Paleozoic Strata of the Sichuan Basin, with an estimated 2.5-3.0 trillion cubic meters of additional reserves potential. The proven rate of coalbed methane is only 3.9%, with remaining unproven resources amounting to 33.80 trillion cubic meters. Basins such as Ordos, Qinshui, Junggar, Sichuan are key targets for future coalbed methane exploration, with an estimated 4.0 trillion cubic meters of additional reserves potential.

Ultra-deep（burial depth ≥6 000 m）exploration is a distinctive feature of petroleum exploration in the Tarim Basin. Since the implementation of the 14th Five-Year Plan, Tarim Oilfield Company has focused on exploration in ultra-deep new regions and new fields, achieving a series of major breakthroughs and discovering multiple new reservoir-cap rock combinations. This study deeply analyzes the geological conditions for ultra-deep hydrocarbon accumulation in continental oil and gas system of the Kuqa area, marine oil and gas system in platform-basin areas, and marine-continental transitional facies oil and gas system in piedmont areas of the Southwest Tarim. It is concluded that in the Tarim Basin, ultra-deep reservoir-cap rock combinations are either adjacent to or interbedded with source rocks, and trap formation occurred either earlier than or concurrently with the peak gas generation period of the source rocks. Therefore, the conditions for natural gas accumulation are favorable, leading to the development of multiple ultra-deep natural gas accumulation models. This study calculates the natural gas resources of the basin by using multiple methods. The in-place natural gas resources are 18.47 ×10¹² m³, and the ultra-deep in-place natural gas resources with a depth of ≥6 000 m reach 13.40×10¹² m³. The ultra-deep natural gas is predominantly distributed in the Cretaceous-Jurassic strata of Kuqa area, Carboniferous-Permian strata in the piedmont area of Southwest Tarim, and the Ordovician-Cambrian strata in the platform-basin region. Favorable exploration zones for ultra-deep natural gas include the Kelasu Structural Belt, eastern segment of the Northern Structural Belt, Zhongqiu-Di'na section of the Qiulitag Structural Belt, periphery of the Kekeya area in the West Kunlun Thrust Belt, Wuqia Structural Belt in the West Tianshan Thrust Belt, eastern part of the Lunnan-Aman Transition Zone, and western margin of the Yingmaili Low Uplift.

After more than 50 years of exploration, the Santos Basin in Brazil has become the continental margin basin with the most deep-water oil and gas discoveries in the world to date. Based on the primary exploration objectives and the process of oil and gas discoveries, the exploration history of the Santos Basin can be divided into three stages: shallow-water clastic reservoir exploration, deep-water gravity flow sandstone exploration, and pre-salt carbonate reservoir exploration. During the deep-water pre-salt carbonate reservoir exploration phase, some large and giant oil and gas discoveries were discovered, establishing the Santos Basin as a global leader in deep-water hydrocarbon exploration. The exploration in the Santos Basin has always been accompanied by innovation in geological understanding and advances in exploration technology. Particularly in the phase of deep-water pre-salt carbonate reservoir exploration, there was a transition from focusing on giant structural traps in the core exploration areas to the peripheral and outer regions. The innovations in oil and gas geological understanding played a key role in determining the direction of exploration into ultra-deepwater frontiers. These innovations primarily include four aspects: the differential distribution of hydrocarbon source kitchens determined by the tectonic framework during the rift phase, the genesis and distribution characteristics of large-scale reservoirs, the distribution patterns of medium and large scale oil and gas fields, and the distribution characteristics of mantle-derived carbon dioxide. During the exploration of the Santos Basin, major international oil companies were actively involved in the oil and gas exploration bidding. However, they exhibited different exploration strategies, and the drilling results were, on the whole, far below expectations. This not only confirmed the basin´s rich oil and gas potential but also revealed the significant variability in hydrocarbon accumulation and reservoir formation within continental margin basins. As a typical passive continental margin basin, understanding the oil and gas accumulation patterns and key factors in the deep-water regions of the Santos Basin has significant reference value for comprehensively understanding and systematically mastering the petroleum geological characteristics of global continental marginal deep-water basins. It also provides guidance for the expansion of new frontiers in deep-water exploration and optimizing exploration planning.

The extensional-convergent tectonic cycle is commonly developed in the carbonate strata of the middle-lower assemblages within small cratons in central and western China. It not only governs the sedimentary differentiation and filling processes but also provides the core driving mechanism for the development and spatio-temporal arrangement of fundamental petroleum geological elements in deep-ultra-deep domains.Taking the Neoproterozoic-Ordovician in the Tarim Basin as an example,by leveraging 42 newly acquired and spliced seismic lines, a 3D data volume spanning 56 000 km² in the Tazhong-Tabei area, more than 70 wells, C-O isotope data (sampled at 5-10 m intervals), and over ten thousand cuttings (core) thin sections, we reconstruct the tectonic-paleogeographic background during key tectonic transformation (sub) stages. Subsequently, lithofacies paleogeographic maps are meticulously compiled in sequence units to clarify the platform type conversions and sedimentary differentiation characteristics within the extensional-convergent cycle and to determine the reservoir-forming assemblages.The results indicate that: (1) The differential sedimentary filling of two types of Nanhua Period paleo-rifts, combined with the inherited paleo-uplifts and the (syndepositional) paleo-uplifts formed by convergent compression in the Middle-Late Ordovician, jointly constitute the foundation for tectonic-paleogeogeographic differentiation. (2) The Sinian-Ordovician can be divided into one first-order sequence and four second-order tectonic sequences, corresponding respectively to four evolutionary stages: the rift-depression transition stage, the cratonic extensional construction stage, the extensional-convergent transition stage, and the convergent strong differentiation-drowned platform stage. During this period, the tectonic-paleogeographic background and paleo-sea level fluctuations controlled the orderly succession and development of muddy slopes, carbonate slopes, rimmed platforms, and drowned platforms. (3) Six sets of large-scale source rocks were developed within the extension-convergence cycle. These source rocks, together with the following five assemblages, constitute five types of source-reservoir-cap assemblages: mudstone of the Cambrian Yuertusi Formation-dolomite of the Upper Sinian, gypsum-salt rock of the Cambrian Miaolingian Series-dolomite of the Cambrian Series 2, tight carbonate rocks and mudstone of the Lower Ordovician-weathered crust of dolomite of the Cambrian Furongian Series, Sangtamu mudstone of the Upper Ordovician-fault-controlled karst weathered crust of the Middle-Upper Ordovician and slope-facies mudstone-collapse body of the Cambrian Furongian Series.

The fault-controlled carbonate rocks of the Fuman Oilfield in the Tarim Basin have attracted much attention due to the continuous discovery of ultra-deep oil and gas, and there is an urgent need to further clarify the role of hydrothermal fluids in modifying such reservoirs. Based on seismic data interpretation, combined with field outcrop observation, core and thin section analysis, geochemical analysis, and production characteristic analysis, an in-depth study is conducted on the hydrothermal alteration effects on the Ordovician ultra-deep fault-controlled reservoirs in the Fuman Oilfield of the Tarim Basin.The study find that there are three types of hydrothermal alteration effects on the ultra-deep Ordovician reservoirs in the Fuman Oilfield: ⑴The dissolution-storage enhancement effect, which develops in an open-semi-open environment. On the one hand, the high temperature of hydrothermal fluids accelerates the chemical reaction rate and promotes mineral dissolution; on the other hand, in the open-semi-open environment, hydrothermal fluids carry the dissolved substances out of the reservoir system, forming good reservoir spaces. (2) The cementation-dissolution synergistic reservoir-controlling effect, which occurs in a closed system with weak late tectonic stress. The coupling of fault activity stages and fluid evolution leads to the upper part being dominated by cementation and filling (enhanced sealing) and the lower part being dominated by dissolution and expansion (improved reservoir performance), forming a dynamic equilibrium structure of "upper blocking and lower storing". (3) The cementation-brittle transformation and fracturing effect, that is, during diagenesis, the cementation caused by hydrothermal fluids enhances the brittleness of the rocks, and subsequent fracturing occurs in the dendritic internal structure of strike-slip faults under the action of tectonic stress or fluid pressure imbalance, forming new reservoirs and enhancing the seepage capacity of the oil reservoir.This study on the alteration effects of ultra-deep hydrothermal fluids on reservoirs in the Fuman Oilfield of the Tarim Basin has deepened the understanding on the mechanism of synergistic reservoir control by hydrothermal fluids and faults, revealed the development law of strong heterogeneity in ultra-deep fault-controlled reservoirs, and further clarified the exploration direction of such reservoirs.

The dolomites of the Middle Permian Maokou Formation in the central Sichuan Basin are important targets for deep oil and gas exploration in the Sichuan Basin. To gain an in-depth understanding of their genesis and reservoir formation mechanisms, this study, based on systematic core and thinsection observations combined with geochemical analysis such as rare earth elements, carbon and oxygen isotopes, and U-Pb dating, has yielded the following insights: (1) The dolomites of the Maokou Formation were primarily formed through three stages of dolomitization: residual bioclastic grain dolomite is the product of penecontemporaneous sea water dolomitization; very fine-crystalline and fine-crystalline dolomite formed in a shallow burial environment, controlled by dolomitization of marine-sourced pore water; while medium- to coarse-crystalline dolomites were related to the Emeishan large igneous province event and formed by the replacement of pre-existing dolomite or limestone through shallow burial structural-hydrothermal dolomititation. (2) The reservoir spaces of the Maokou Formation dolomites underwent a complex diagenetic evolution process, with the diagenetic sequence being: cementation→meteoric freshwater dissolution→penecontemporaneous dolomitization→shallow burial dolomitization→mechanical compaction→tectonic fracturing→hydrothermal alteration→pressure dissolution→hydrocarbon charging. (3) The development of the Maokou Formation dolomite reservoirs is controlled by a "sedimentation-diagenesis-tectonics" triple control mechanism: high-energy platform-margin shoals laid the foundation for primary porosity; penecontemporaneous dissolution and dolomitization were key to the development of large-scale porosity; and tectonic-hydrothermal activities played an important adjusting role in the reservoirs through the dynamic balance between dissolution-enhanced porosity and cementation-reduced porosity. Based on the above understanding, it is inferred that large-scale dolomite reservoirs of the Maokou Formation in the central Sichuan Basin are mainly distributed in high-energy platform-margin shoals or areas adjacent to faults. The results of this study enhance the understanding of the formation process of complex dolomite reservoirs and provide clear directions and solid theoretical support for the next phase of deep oil and gas exploration in this area.

It has been proved that 100-million-ton class oilfield cluster in southwestern Huizhou Sag has an important relationship with the development of high-quality source rocks in Wenchang Formation. The controlling factors of high-quality source rocks in southwest area of Huizhou Sag are not clear enough, which is not conducive to guide the petroleum exploration of peripheral sags. Based on the difference analysis of organic geochemical characteristics of high-quality source rocks, the controlling factors for the development of high-quality source rocks in southwestern Huizhou Sag are studied from the aspects of structure, sedimentation, organic matter sources and preservation conditions. The results show that: (1) The scale and distribution of high-quality source rocks in southwestern Huizhou Sag are controlled by tectonic activities and source supply, especially, during the depositional period, a relatively large fault throw and a low source-to-sink ratio are conducive to the development of high-quality source rocks. The tectonic activity controlled the migration of the subsidence center and sedimentation center from south to north, with HZ26 sub-sag in the early stage and XJ24 sub-sag in the late stage as the central area respectively. (2) The quality of high-quality source rocks depends on the source of organic matter and preservation conditions. The aquatic algal dominance, brackish water-fresh water and hypoxic reduction preservation conditions during Wenchang Member 4 period are more conducive to the development of high-quality source rocks. (3) Strong fault activity, limited distribution of sedimentary sand bodies, input of oil-prone aquatic-terrestrial organic matter, brackish water and strong anoxic environment are important controlling factors for the development of high-quality source rocks in HZ26 sub-sag. This study helps to further understand the potential of source rocks in peripheral sub-sags, and provide important support for the exploration of potential hydrocarbon-rich sags.

The Permian Taiyuan Formation tight limestone in the Ordos Basin exhibits significant exploration potential. Multiple high-risk exploration wells, such as YT1H well and ZT1H well, have yielded high industrial gas flows, making this formation a key target for natural gas exploration. However, strong reservoir heterogeneity and poorly understood microscopic pore structure characteristics and controlling factors have hindered further gas exploration planning in this area. Based on observations of core observations of, cast thin sections, and field emission scanning electron microscopy (FE-SEM), combined with low-temperature nitrogen adsorption experiments, and high-pressure mercury intrusion porosimetry (MIP), this study systematically investigates the microscopic pore structure characteristics and their controlling factors in the tight limestone reservoirs of the Taiyuan Formation. The influence of differential dissolution during the early diagenetic stage on pore structure is revealed. The results indicate: (1) The Taiyuan Formation develops reservoir rocks including bound bioclastic limestone, micritic bioclastic limestone, and bioclastic micritic limestone. Main types of reservoir space include moldic pores, intraskeletal pores, framework pores, intercrystalline pores, and dissolved micro-fractures. Porosity ranges from 0.38% to 9.34%, and permeability ranges from 0.002×10^-3 μm² to 0.776×10^-3 μm², characterizing a low-porosity, low-permeability tight reservoir. (2) The pore structure exhibits strong heterogeneity, with multimodal pore size distribution showing peaks in ranges such as 3-4 nm, 50-100 nm, and 700 nm-2 μm. The reservoir contains coexisting micro-scale and nano-scale pore systems, where storage capacity is mainly contributed by macropores and micropores, while adsorption capacity is dominated by micropores and mesopores. (3) Reservoir properties are controlled by heterogeneous pore structure. Porosity and permeability show positive correlations with average and median pore-throat radii, but a negative correlation with pore-throat sorting coefficient. Compared to porosity, pore-throat size and uniformity exert a greater influence on permeability. (4) The heterogeneity of the microscopic pore structure is closely related to differential dissolution during early diagenesis. Moderate karstification improves pore structure, whereas excessive dissolution leads to deterioration. In the slight dissolution stage (selective dissolution), pores are mainly micropores and mesopores, with fine throat types. Under moderate dissolution (mottled dissolution), enhanced karstification transforms micropores and mesopores into macropores and micrometer-scale pores, resulting in medium pore-throat systems. In the over-dissolution stage (karst brecciation), the karst system disrupts the bedrock, leading to degraded pore structure characterized by medium pores and fine throats.

In order to clarify the unconventional oil and gas exploration plays in the Sichuan Basin, a comprehensive analysis is conducted to study the characteristics of mixed sedimentation of the Jurassic Da'anzhai Member and their significance for oil and gas accumulation by integrating data from outcrops, drilling, seismic and others. The priority plays for the next phase of unconventional oil and gas exploration are also identified. This study reveals that: (1) The Da'anzhai Member is characterized by high-frequency alternation of lacustrine carbonate rocks and clastic rocks. High-quality source rocks (shales) are closely associated with favorable reservoirs. This constitutes a superior hydrocarbon accumulation assemblage characterized by "source reservoir integration" or "source reservoir proximity". (2) The Da'anzhai Member has great potential for stereoscopic exploration of tight oil/gas and shale oil/gas. The thick shale in the second sub-member of Da'anzhai is not only served as source rock, but also has the potential to form reservoirs for shale oil and gas. The thick shell limestone in the first and third sub-member of Da'anzhai has the potential to form reservoirs for tight oil and gas. (3) The Yilong-Zhongjiang-Shehong-Suining-Guang'an area, which is closely adjacent to the source rocks of the second sub-member on the plane and develops thick shell limestones, features a "source-reservoir interbedding" and "upper source and lower reservoir" type source-reservoir configuration, making it the most favorable area for integrated exploration of unconventional oil and gas in the mixed rocks of the Da'anzhai Member.

The controlling mechanisms of physical properties and distribution laws of deep water and low-permeability reservoirs have become key scientific issues urgently to be solved in China offshore oil and gas exploration and development. Taking the 3rd member of Lingshui Formation reservoir in YL10 structure on the southern slope of Baodao Sag, Qiongdongnan Basin as the research object, this paper systematically studies the petrological characteristics, pore-throat structure and physical property distribution laws of the reservoir by comprehensively using experiments such as cast thin sections, scanning electron microscopy (SEM), high-pressure mercury intrusion and fluid inclusions. The results show that: (1) The 3rd member of Lingshui Formation in the study area has strong heterogeneity and complex pore-throat structure, generally developing medium-porosity, low to ultra-low permeability reservoirs, with "sweet spot" reservoirs of high porosity and high permeability existing in some areas. (2) The difference in reservoir physical properties is controlled by the sedimentary-diagenetic coupling effect. Sedimentation lays the material foundation for the Lingshui Member 3 reservoir, and diagenesis is the main controlling factor affecting the reservoir type. Compaction, affected by burial depth, is the main cause of reservoir differentiation. Cementation intensifies the differentiation of reservoir physical properties, and the differences in the type, content and occurrence of cements lead to the differentiation between low-permeability and ultra-low-permeability reservoirs. Dissolution controlled by oil and gas charging plays a constructive role in reservoir porosity, and the formation of a large number of mold pores results in maintaining medium porosity while low permeability in the deeply buried reservoir. (3) The shallow, weak-diagenetic zone in the south is a favorable reservoir distribution area, where thick underwater distributary channel sand bodies exhibit high porosity and permeability characteristics; the deep reservoirs in the north require special attention to zones with developed dissolution pores and weak cementation.

The Permian System in the southern Sichuan Basin serves as the primary target for major natural gas reserve growth in the region. Recent significant breakthroughs in syncline zone have demonstrated that high-yield gas reservoirs in southern Sichuan Basin are not completely controlled by positive structural belts. Instead, strike-slip faults have some control effects on karst paleogeomorphology, high-quality reservoir development and natural gas enrichment in southern Sichuan Basin. However, because the large fold-thrust zones on the shallow surface result in the low seismic resolution and the weak seismic reflection, the strike-slip fault and the characteristics are difficult to determine, and the controlling effect on natural gas enrichment and high yield is unknown, which seriously restricts the exploration and development of fault-controlled gas reservoirs in this area. Therefore, based on artificial intelligence fault identification technology, this paper carries out the identification of deep strike-slip faults, determines the identification marks of strike-slip faults, implements the distribution and characteristics of strike-slip faults in southern Sichuan Basin. Moreover, the controlling effect of strike-slip faults on high-yield gas reservoirs is analyzed based on actual drilling data. The results show that: (1) The artificial intelligence method based on deep learning can improve the identification accuracy of deep hidden strike-slip faults, and can effectively identify hidden strike-slip faults under thrust structures in southern Sichuan Basin. (2) Four planar identification marks and five sectional markers for strike-slip faults in southern Sichuan Basin are defined, thus verifying the development of a rhombus strike-slip fault system in the pre-Permian strata, with a total length of 940 km. (3) The strike-slip fault in southern Sichuan Basin has obvious classification, stratification and staging characteristics. There develop various types of structure such as linear structure, en echelon structure, flower structure and fault horst. Under the geological background of multi-stage extension-convergence, the strike-slip faults develop inheritively from the tension-torsion of the Sinian-Cambrian to the compression-torsional of the Upper Cambrian-Upper Ordovician on the basis of the weak zone of the early basement. (4) The strike-slip fault can connect multiple sets of source rocks in the Cambrian and Silurian, which plays an important role in controlling oil and gas migration and accumulation, and controls the distribution of high-yielding gas reservoirs of the Permian Maokou Formation together with the Permian reverse fault. Deep Cambrian-Ordovician strike-slip faults are a key factor for the high enrichment and productivity of fracture-cave type gas reservoirs controlled by faults in southern Sichuan Basin.

The Lower-Middle Jurassic tight sandstone gas reservoirs in the Turpan-Hami Basin exhibit substantial resource potential, representing a crucial exploration field for natural gas reserve growth and production enhancement. However, due to complex geological conditions, the hydrocarbon accumulation mechanisms remain unclear, which hinders resource potential evaluation and the optimization of exploration directions. Through systematic analysis of source rock characteristics, reservoir characteristics, and preservation conditions, this paper establishes an accumulation model and identifies three key controlling factors for tight sandstone gas accumulation: (1) effective hydrocarbon kitchens control the lateral distribution of hydrocarbons; (2) high-quality reservoir facies belts determine the degree of hydrocarbon enrichment; (3) stable tectonic settings are conducive to the preservation of large-scale gas reservoirs. Integrated resource evaluation employing the small-bin volume method, resource abundance analogy, and Monte Carlo simulation was conducted for three main target intervals: the third member (J₂x³) and first member (J₂x¹) of the Xishanyao Formation, and the second member (J₁s²) of the Sangonghe Formation. Results show that the total geological resource of tight gas in Taibei Sag amounts to 6 793.02×10⁸ m³, exhibiting stepwise increase with burial depth. Specifically, the J₂x³, J₂x¹, and J₁s² members contain 1 783.51×10⁸ m³, 1 923.53×10⁸ m³, and 3 085.98×10⁸ m³, respectively. Resource classification reveals: Type Ⅰ resources (1 596.36×10⁸ m³) are concentrated in the northeastern slope of the Shengbei Sag, Baka structural belt, southern slope of the Qiudong Sag, and southern slope of the Xiaocaohu Sag, serving as priority targets for near-term exploration breakthroughs; Type Ⅱ resources (2 560.97×10⁸ m³) are mainly distributed in the Gedatai-Hongtai structural belt and Qiudong-Xiaocaohu piedmont zones, representing favorable directions for medium- and long-term exploration expansion. These findings provide a scientific basis for efficient tight gas exploration in the basin.

The upper gas layer of the Longmaxi Formation in the Sichuan Basin represents a crucial strategic replacement field for shale gas exploration. Based on biostratigraphic methods, through systematic fine correlation of graptolite-bearing shale intervals and analysis of drilling results from typical wells, the main controlling factors for the differential enrichment and the distribution patterns of favorable areas of the upper Longmaxi gas layer have been clarified. The results show that: (1)The development of the Aeronian LM7-LM8 graptolite zones and their associated high TOC shale is a prerequisite for the enrichment of the upper Longmaxi gas layer. In the Jiaoshiba area, successful wells are predominantly located in structural highs where this specific shale unit, characterized by relatively high TOC, porosity, and gas content, is developed. In contrast, poorer results in areas like Changning and Weiyuan are primarily due to the absence or inferior quality of this shale unit. (2)Structural morphology exerts a significant control on the enrichment of shale gas in the upper gas layer. Due to higher horizontal permeability compared to vertical permeability, gas tends to migrate updip. This leads to higher enrichment degrees in structural highs of anticlines (e.g., Jiaoshiba), while synclines (e.g., Wulong) and anticlinal limbs show lower enrichment levels and generally poorer exploration results. Based on the identified controls, it is recommended to enhance research on the development characteristics of the LM7-LM8 organic-rich shale, and conduct systematic evaluation and target optimization for the upper gas layer integrating actual drilling results. These findings provide a geological basis for optimizing favorable areas and exploration deployment of the upper Longmaxi gas layer in the Sichuan Basin.

The Permian Guofeng Formation (Member) in the Yangtze Region is a set of marine organic-rich black shale series exhibiting distinct diachronous characteristics, serving as a key replacement stratigraphic unit for shale gas exploration. This paper systematically analyzes and summarizes the spatiotemporal differentiation patterns, hydrocarbon generation characteristics, reservoir characteristics, and preservation conditions of the Permian Gufeng Formation (Member) in the Yangtze Region. From west to east, the Gufeng Formation (Member) exhibits a pattern of "east-west differentiation and multi-center sedimentation" with its distribution controlled by the synergistic effects of paleo-tectonics, sea-level fluctuations, and sedimentary environments. The reservoir lithologies are dominated by siliceous and carbonaceous shales, exhibiting a mineral combination characterized by " high silica, rich calcium, and low clay content ". The content of brittle minerals is high (averaging 85%), indicating excellent fracturability. Reservoir space types are diverse, dominated by organic pores and dissolution pores, with mesopores constituting the main pore size distribution. Pore development and gas content exhibit significant regional differentiation, characterized by "better in the west, poorer in the east". In the Upper Yangtze Region, the hydrocarbon generation quality is excellent (TOC 3%-10%, Type Ⅰ-Ⅱ₁ kerogen), reservoir physical properties are good (average porosity 4.46%), gas content is high (average >4 m³/t), and preservation conditions are favorable, making it the core area for shale gas enrichment. In the Middle Yangtze Region, shallow burial depth (<2 000 m) and moderate thermal evolution provide engineering cost advantages, but reservoir heterogeneity is strong. In the Lower Yangtze Region, burial depth is moderate, but reservoir physical properties (average porosity 1.99%), gas content, and preservation conditions are generally poor, limiting exploration potential. Comprehensive evaluation indicates that the Upper Yangtze Region (Guangyuan-Bazhong-Dazhou, Fengjie-Enshi) is the most favorable Class Ⅰ exploration area, though deep engineering challenges must be overcome; the Middle Yangtze Region (Jingshan-Wuhan) is a Class Ⅱ favorable exploration area where geological-engineering "sweet spots" should be targeted; the Lower Yangtze Region (Wuwei-Xuancheng) is a Class Ⅲ potential risk zone.

In response to the "one well, one reservoir" characteristics of the Taiyang shallow shale gas fields in the the Zhaotong Demonstration Zone, the main controlling factors for gas enrichment and high production have been clarified by focusing on analyzing the structural deformation features, the pore evolution process of shale reservoirs, and the coupling relationship between hydrocarbon supply processes and sealing capacity of the key target layers (Wufeng Formation-Longmaxi Formation). The main three understandings are as follows: (1) Based on the pattern of regional "north-south zoning, east-west blocking" as well as characteristics such as faults, folds, and fractures, the gas field is divided into eight shale gas occurrence and development units. (2) Gas reservoirs have typical characteristics of self-sourcing, self-reservoiring, and self-sealing, with continuous and stable distribution. The gas drive mechanism is elastic gas drive without edge or bottom water. (3) After undergoing multiple stages of burial-uplift cycles and multiple episodes of hydrocarbon generation, the current gas-rich and high-production potential of shale reservoirs is mainly controlled by the combined effects of later structural modification intensity and sealing preservation conditions. The overall performance of the gas field shows that the wide and gentle inclined fold zone is conducive to shale gas enrichment, while the narrow and steep anticline fold zone is relatively poor in shale gas. The new progress clarifies the controlling effect of the hydrocarbon supply-sealing coupling relationship on high production. It also establishes a development unit classification scheme based on structural characteristics, providing a geological basis for subsequent directional drilling and engineering optimization.

Accurate interpretation of oil saturation (S_o) traditionally relies on core analysis and empirical formulas, yet this process is challenged by scarce labeled samples, missing logging curves, and significant noise in logging data. To address these issues, this paper proposes a masked self-supervised Transformer-based method for oil saturation prediction from well logs, termed MWLT-So. First, multiple conventional logging curves are thoroughly aligned and standardized, and a random masking reconstruction task is designed to enable self-supervised pretraining on a large amount of unlabeled well interval, thereby learning generalizable representations with cross-well transferability. The pretrained model is then fine-tuned on a limited number of labeled samples using a regression objective, while multi-scale positional encoding and feature fusion are incorporated to enhance long-range dependency modeling. Comparative experiments across different blocks and various logging-curve combinations demonstrate that:(1) Under both random data split and rigorous well-wise split evaluation settings, MWLT-So achieves the best performance on the primary regression task. (2) MWLT-So shows clear advantages in terms of geological profile consistency and error distribution, accurately capturing boundary transition zones and high-S_o plateau intervals, while effectively overcoming common deficiencies of traditional methods such as over-smoothing, overshooting, and phase lag. Its residuals are more concentrated with thinner tails, and both the median error and dispersion are lower, indicating superior accuracy and robustness. (3) In the oil-bearing/non-oil-bearing identification task based on the threshold S_o = 0.5, MWLT-So attains the best classification performance with the lowest false-positive and false-negative rates, confirming its capability to reduce misclassification risk in threshold-based stratification scenarios. Overall, the proposed method provides effective technical support for rapid evaluation of complex reservoirs and identification of remaining oil.

Focusing on the core issue of unclear natural gas genesis and the dominant controlling factors of hydrocarbon accumulation in the Sinian Dengying Formation in southwest Sichuan Basin, this study utilizes drilling and outcrop data to investigate the development characteristics of source rocks, as well as the components, carbon and hydrogen isotopic compositions, gas-source correlation of natural gas in Dengying Formation, and further establish a hydrocarbon accumulation pattern. The results show that: (1) Three sets of source rocks with good hydrocarbon generation potential and large-scale development are present in southwest Sichuan Basin, including the Lower Cambrian Qiongzhusi Formation, the argillaceous shale of the Sinian Doushantuo Formation, and the carbonaceous slate of the Middle Proterozoic Ebian Member 3. (2) Natural gas in the Dengying Formation is mainly composed of hydrocarbon gases, with a high dryness coefficient and characteristics of low sulfur and high helium content. The δ¹³C₁ value ranges from -31.5 ‰ to -30.9 ‰, which are heavier than that in Gaoshiti-Moxi area of central Sichuan Basin. The δ ²H_CH4 value is -153‰ to -149‰, which are lighter than that in Gaoshiti-Moxi area. (3) Based on the analysis of δ¹³C₁, δ²H_CH4, and ⁴⁰Ar/³⁶Ar geological dating, it is believed that the natural gas in the Dengying Formation is contributed by source rocks from the Lower Cambrian Qiongzhusi Formation and the Sinian-pre-Sinian systems, with a higher contribution from the Sinian-pre-Sinian source rocks compared to the Gaoshi-Moxi area. (4) The three sets of source rocks have favorable spatial relationships with high-quality reservoirs of platform margin in the Dengying Formation, where underlying basement-involved faults provide pathways for hydrocarbon migration, and the overlying salt-gypsum rocks of the Triassic Leikoupo Formation serve as effective cap rocks. This study proposes a hydrocarbon accumulation pattern for the Dengying Formation characterized by "multi-source bidirectionally supplying hydrocarbon and dual-structure controlling accumulation". These findings provide geological support for hydrocarbon exploration in the Dengying Formation in southwest Sichuan Basin.

Taking the marine shale of the Permian Wujiaping Formation in the Kaijiang-Liangping Trough, Sichuan Basin as the research object, this study quantitatively characterizes the pore structure characteristics of different shale lithofacies through experimental analyses such as X-ray diffraction (XRD), gas adsorption, and high-pressure mercury intrusion (HPMI). Based on equations like V-S and FHH, the fractal dimensions of shale pores are calculated to reveal the pore heterogeneity characteristics of shale reservoirs. Furthermore, the influencing factors and geological significance of pore development heterogeneity in different lithofacies are clarified. The results show that: (1) The lower part of the Wujiaping Formation consists of argillaceous shale, which transitions upward into mixed shale and eventually evolves into siliceous shale in the upper section. Correspondingly, the dominant pore types shift progressively from clay mineral intercrystalline pores to dissolution pores, brittle mineral intercrystalline pores, and organic matter pores. (2) The pores of siliceous shale are dominated by nanoscale organic pores, and their development characteristics are controlled by the distribution morphology and abundance differences of organic matter, showing significant heterogeneity. This results in the highest fractal dimension of micropores in siliceous shales. The mixed shale primarily contains mesopore-scale intercrystalline and dissolution pores, with pore development strongly influenced by diagenetic processes and exhibiting a discrete distribution, leading to the highest fractal dimension of mesopores in this lithofacies. Clay minerals are prone to deformation due to compaction, which makes argillaceous shale highly heterogeneous at the macropore-scale. (3) The TOC content has the greatest influence on the mesopore fractal dimension of siliceous shale, while the macropore fractal dimension increases with the increase of clay mineral content. Comprehensive analysis suggests that highly to moderately organic-rich siliceous shale has the highest overall fractal dimension and strongest adsorption effect on shale gas, making it the dominant lithofacies of the Wujiaping Formation in the Kaijiang-Liangping Trough.

Early marine carbonate cements are an important component of marine carbonate depositional systems. They record key information on paleo-seawater chemistry and early diagenetic processes and play a significant role in the formation and evolution of carbonate reservoirs. Considering the limited research conducted in China and the great resource potential of marine carbonate reservoirs, this study systematically reviews and synthesizes previous studies on early marine carbonate cements worldwide. Their spatial and temporal distribution, morphological characteristics, mineral compositions, and major controlling factors are summarized. Previous studies indicate that early marine carbonate cements are widely developed in both ancient and modern carbonate depositional systems. Their primary mineral compositions are mainly aragonite and high-Mg calcite, and their common morphologies include acicular, fibrous, columnar, granular and others. The mineralogical and morphological evolution of these cements is mainly controlled by multiple factors, including seawater Mg/Ca ratio, CO₃²⁻, phosphate ions, SO₄²⁻, organic matter, temperature, salinity, sediment substrate, and crystal habits. Early marine cementation can significantly modify the pore structure of primary sediments and enhance the stability of the rock framework, thereby exerting an important influence on pore preservation and subsequent diagenetic evolution of carbonate reservoirs. A comprehensive understanding of the formation characteristics and controlling factors of early marine carbonate cements is crucial for revealing carbonate sedimentation-diagenesis processes and reservoir formation mechanisms, and it provides important theoretical guidance for hydrocarbon exploration in carbonate reservoirs.

Typical oil and gas reservoirs with radioactive minerals, characterizing by high natural gamma and low resistivity of logging, are developed in the Zhujiang Formation of Wenchang 16 structure in the Pearl River River Mouth Basin. The shale content calculated with conventional interpretation methods is often significantly high, which leads to large errors in reservoir parameter calculation, resulting in the missed identification of effective oil and gas layers. Based on the advantages of precise characterization of reservoir pore structure using nuclear magnetic resonance(NMR) logging data, the differences in logging response characteristics between typical mudstone and low-resistivity oil and gas reservoirs in the study area are systematically analyzed. By optimizing the traditional volume model and innovatively introducing the R_kn parameter of NMR logging, an improved volume model response equation is established. By combining this equation with conventional logging data, an optimization algorithm is used to accurately calculate the relative content of reservoir components (including silt, shale, etc.), and further improve the calculation accuracy of key reservoir parameters such as porosity and saturation. The practical application shows that this method has achieved remarkable results in the evaluation of high-gamma reservoirs of many oilfields in the Pearl River Mouth Basin, and effectively solved the problem of parameter calculation caused by the interference of radioactive minerals. This method has important application value for the evaluation of shallow unconsolidated sandstone reservoirs with similar geological characteristics, and provides a new technical idea for the fine evaluation of complex reservoirs.

The Shangganchaigou Formation (N₁) in the northwestern Qaidam Basin mainly consists of fine-grained mixed rocks deposited in a saline lake basin, representing an important field for unconventional oil and gas exploration. However, current research on cyclostratigraphy and high-precision astronomical sedimentary response characteristics in this formation remains relatively weak. By comprehensively integrating core and well-logging data, cyclostratigraphic analysis is performed on two drilling wells, identifying Milankovitch cycles including long eccentricity, short eccentricity, obliquity, and precession in the Shangganchaigou Formation, and a floating astronomical time scale is established based on the 405 ka long eccentricity cycle, thereby determining the sedimentation rate and sedimentary characteristics of the Shangganchaigou Formation. It is shown that: (1) Sedimentation time of N₁ is approximately 4 Ma, and the average sedimentation rate can reach 20 cm/ka, which is significantly higher than that of other continental lacustrine strata in China. (2) The lithofacies characteristics based on sedimentation rate analysis indicate that lithofacies are significantly controlled by the sedimentation rate. Laminated dolomitic limestone with high organic matter content mainly develops in high-rate segments, while massive argillaceous-silty dolomitic limestone with low organic matter content is dominant in low-rate segments. (3) The continuous orogenic tectonic activity during the Himalayan period control the high sedimentation rate of N₁ at a macroscopic scale, and short-term climate alternations shape the oscillatory changes in the sedimentation rate. The identification of astronomical cycles and analysis of sedimentation rates of N₁ in the the northwestern Qaidam Basin are helpful for understanding the sedimentary evolution of favorable exploration intervals in salinized lake basins and can provide new ideas for the subsequent efficient exploration and development of shale oil.

Frequency-dependent AVO inversion based on viscoelastic theory is an effective method that uses dispersion characteristics to guide fluid identification. The formation quality factors obtained by inversion have certain effects in the fluid detection of clastic rock reservoirs. However, at present, most of the inversion methods for quality factors are linear inversions based on linear reflection coefficient approximation equations. Moreover, the nonlinear inversion method based on the highly accurate and less assumption-based exact Zoeppritz equation fails to provide stable solutions, and has low computational efficiency, which restricts its large-scale application ability in three-dimensional work areas. To address the above issues, based on Bortfeld′s nonlinear approximation, this study derived the nonlinear reflection coefficient equation considering seismic frequency. While ensuring the accuracy of the equation, it reduce its complexity. On this basis, a new pre-stack nonlinear two-step frequency-dependent inversion method is developed to predict the quality factor of the stratum, and reasonable and effective fluid identification results are obtained. It provides a strong basis for the prediction of gas-bearing clastic rock reservoirs. The applicability of this method in reservoir containment assessment is verified by the synthetic record tests and actual work area applications.

The Erlian Basin is mainly focused on oil exploration, with a relatively low degree of natural gas exploration. Natural gas has been discovered in the Permian, Jurassic and Cretaceous strata. Based on geochemical analysis of the gas components and carbon isotopic compositions, the natural gas in the Erlian Basin can be classified into four genetic types: biogenic gas, oil-type gas, coal-type gas, and non-hydrocarbon gas. Gas maturity assessments and gas-source correlations reveal that the basin hosts multiple sets of gas-prone source rocks, including immature to low-mature coal and dark mudstone in the shallow Saihantala Formation of the Cretaceous, mature to high-mature dark mudstone in the middle-deep Arshan Formation of the Cretaceous, low-mature to high-mature coal-measure source rocks of the Jurassic, and mature to over-mature dark mudstone of the Carboniferous-Permian. The coal seams are thin but widely distributed, while the dark mudstones are nearly 1 000 m thick and extensively developed in the basin, with organic matter types of II₂-III, providing a source rock foundation for natural gas generation. Natural gas accumulates in near-source structural highs, and there are five main favorable reservoir-seal assemblages, based on which accumulation models for shallow biogenic gas, mid-deep oil and gas, and deep natural gas are established. Using the genetic method and analogy method, the natural gas resources are evaluated. The calculated in-place resources are 2 411×10⁸ m³ for the Carboniferous-Permian, 2 311×10⁸ m³ for the Jurassic, 707×10⁸ m³ for the Cretaceous Arshan Formation in four sags, and 1 425×10⁸ m³ for the Cretaceous Saihantala Formation and Teng-2 member. Overall, favorable exploration targets include the near-source structural highs of the mature Arshan Formation in the sags, and the shallow biogenic gas traps of the Cretaceous Saihantala Formation and Teng-2 member. The Carboniferous-Permian in the eastern sags, and the Jurassic in inherited sags such as Honghaorshute, Aqituwula, and Gaolihan, have good exploration prospects.

In recent years, with the continuous emergence of new theories, understandings, and achievements in exploration, the results of the "13th Five-Year Plan" resource evaluation have shown an unsuitability to the current needs of exploration work, and a new round of resource evaluation is urgently needed to provide a basis for accelerating natural gas exploration and development in the Songliao Basin. By analyzing the geological conditions of natural gas in the northern Songliao Basin, focusing on four main source rocks of the Nenjiang Formation, Qingshankou Formation, Yingcheng Formation, and Shahezi Formation, and targeting four sets of oil and gas combinations in the upper, middle, lower, and deep parts， four reservoir formation models are established, including bedrock weathering crust gas reservoir, volcanic rock gas reservoir, paleouplift cap rock gas reservoir, and intra-source tight gas. Two major categories and five types of analog calibration areas are selected, and natural gas resource evaluation is mainly carried out using the analogy method. The estimated in-situ natural gas resources in the Songliao Basin are 27 002×10⁸ m³, including 17 100×10⁸ m³ of conventional gas and 9 902×10⁸ m³ of tight gas. Based on the distribution of remaining resources and combined with the analysis of geological conditions for natural gas accumulation and enrichment, the next exploration direction has been further clarified. It is believed that the tight gas of the Shahezi Formation in the Xujiaweizi Fault Depression, the volcanic gas of the Yingcheng Formation in the Yingshan-Gulong Fault Depression, and the buried-hill gas of the bedrock in the Central Paleo-uplift Belt are the realistic areas for increasing reserves in the near future.

The Sichuan Basin is rich in oil and gas resources, with its basement structure controlling hydrocarbon distribution from the ultra-deep Sinian to the shallow Jurassic Strata. With the application of ultra-deep gravity-magnetic-electric-seismic joint exploration techniques since 2010, the Neoproterozoic extensional structures in the Sichuan Basin has been continuously confirmed through exploration. Based on the high-resolution gravity-magnetic-electric data and "double-high" (high fidelity and high resolution) seismic data, combined with the outcrop observations along the basin margin and borehole data from 8 wells drilled into the Sinian Doushantuo Formation, a comprehensive interpretation study is carried out. It is proposed that the Sichuan Basin has developed "western Sichuan rift", which has mainly experienced three evolutionary stages from a rift to a depression. Stage 1: Nanhua rift stage, which was dominated by multiple near NE-trending horsts and grabens. Stage 2: the intra-cratonic depression stage happened during the deposition of the Sinian Doushantuo Formation, which was formed by merging the Northwest Sichuan Depression and the Central Sichuan Uplift. Stage 3: intra-cratonic depression stage happened during the deposition of the Sinian Dengying Formation, forming a nearly SN-trending extensional trough which opens towards northwest. Further study shows that strike-slip faults could easily occur during the evolution of the western Sichuan rift. The rift provides conditions for hydrocarbon accumulation in the Nanhua-Sinian Strata where oil and gas can be generated by lower strata, transported by faults and stored by upper strata. The Nanhua-Sinian petroleum system in the western-central Sichuan area is a new potential exploration area.

The shale of the Nenjiang Formation in the Songliao Basin generally exhibits a high total organic carbon content(TOC), locally exceeding 10%. However, the shale is mainly at low-to-medium maturity stage, making it a potential target stratum for in-situ conversion development. Although it is generally believed that higher TOC indicates greater hydrocarbon generation potential, there is still a lack of sufficient understanding regarding whether the in-situ conversion characteristics of different intervals depend solely on their TOC. Optimizing the most economical development intervals under a high TOC background requires additional selection criteria. In this study, two typical Nenjiang Formation shale samples with different organic abundance (with TOC of 9.63% and 5.08% respectively) are selected. Hydrocarbon generation kinetic parameters are obtained through thermal simulation experiments. By coupling the temperature field, an electric-heating in-situ conversion model is established to evaluate the in-situ development potential of the two typical Nenjiang Formation shales with varying abundances. The results indicate that both shale samples from the Nenjiang Formation predominantly generate oil. The high organic abundance shale yields more oil, whereas the low organic abundance shale has a slightly higher gas-oil ratio (GOR). With increasing heating time, the equivalent vitrinite reflectance (Easy R_o%) gradually increases from the heating well center to the periphery. By the third year, the Easy R_o% in the area within a 13 m radius from the heating well had exceeded 1.2%, indicating that the thermal maturation of organic matter in the main hydrocarbon generation zone is essentially completed. Under in-situ conversion conditions, both shales begin to generate significant amounts of oil after approximately two years of heating, reaching over 80% of their peak oil production rates in the third year. Furthermore, the cumulative oil production of the high organic abundance shale is about twice that of the low organic abundance shale. Given its higher cumulative oil production, the high organic abundance shale demonstrates superior in-situ development potential. These findings provide important theoretical support and exploration directions for the in-situ development of low-to-medium maturity shales of the Nenjiang Formation in the Songliao Basin.

To address the issues of strong heterogeneity in the 4th member of the Dengying Formation reservoir in the Sichuan Basin and insufficient constraints for reservoir prediction using subsurface data, a well-exposed (algae) mound-shoal complexes profile of the 4th member of the Dengying Formation in Ningqiang area, northern margin of the Sichuan Basin is selected as a field prototype model. Based on detailed field surveying, sampling, and rock thin section analysis, this study establishes a dolomite reservoir model and defines the spatial relationship between reservoir parameters and lithofacies architecture. The following insights are obtained: (1) The 4th member of the Dengying Formation in Ningqiang area can be divided into lower, middle, and upper sub-members, forming a shallowing-upward cycle from middle ramp to weakly rimmed platform margin to strongly rimmed platform margin. The main rock types are microbial dolomite and crystalline dolomite, with microbial dolomite being the dominant type, including algal peloidal dolomite, algal stromatolite dolomite, algal laminated dolomite, algal framework dolomite, and algal thrombolite dolomite. The upper sub-member develops typical platform-margin (algae) mound-shoal complexes, in which algal framework dolomite, algal stromatolite dolomite, and algal thrombolite dolomite have porosity > 4.5%; algal peloidal dolomite and fine-crystalline dolomite have porosity between 2.5% and 3.5%. Toward the interior of the platform, algal laminated dolomite, very fine-muddy crystalline dolomite have porosity < 2.5%. (2) The reservoir spaces in algal framework dolomite and algal thrombolite dolomite are characterized by large pores and throats; those in algal stromatolite dolomite, algal peloidal dolomite and fine-crystalline dolomite are characterized by medium-sized pores and throats; and those in algal laminated dolomite, very fine-muddy crystalline dolomite are characterized by small pores and throats, exhibiting a dual pore-throat structure. (3) The stacking pattern of the lithofacies is clear: algal peloidal dolomite and fine-crystalline dolomite represent clastic shoal deposits in the mound base and inter-mound areas; algal stromatolite dolomite represents deposits during the colonization stage of microbial mounds above the mound base; algal framework dolomite represents mound core construction; and algal thrombolite dolomite represents mound-flank deposits, exhibiting a "small mound, large shoal" pattern. These results indicate that the platform-margin mound-shoal complex in the upper sub-member of the 4th member of the Dengying Formation in northern Sichuan Basin is extensively developed, representing a favorable zone for high-quality reservoir development.

The fracture development characteristics and fluid distribution in shale reservoirs are key factors for evaluating shale gas exploration and development. However, the influence of pore shape on reservoir elasticity and physical properties is often neglected by existing methods, resulting in limited prediction accuracy. To address this issue, this study proposes an improved method centered on considering the effect of pore shape. Firstly, based on the cross-plot analysis of logging petrophysical parameters, the Gassmann fluid term is selected as the fluid identification factor for gas-bearing shale in the target area. Secondly, shale reservoirs with high-angle fractures are approximated as horizontal transverse isotropy (HTI) media. Combined with petrophysical modeling, an anisotropic reflection coefficient equation for HTI media (considering the effect of pore shape) is derived and established. On this basis, a two-step pre-stack anisotropic inversion method based on the Bayesian framework is constructed to realize the direct inversion of fluid identification factors and fracture parameters. Synthetic seismogram tests show that the inversion results of this method have high consistency with model values and strong noise resistance. Field test results of the shale gas reservoirs of the Wufeng-Longmaxi Formations in the Daozhen syncline, Northern Guizhou area indicate that the inversion results have high consistency with logging interpretation, and can effectively characterize the development characteristics of high-angle fractures and the distribution of gas-bearing shale. The research results provide new theoretical and technical support for fracture prediction and fluid identification in shale reservoirs, and have important practical application value.

The exploration breakthrough of the Hengshan Gasfield in the Permian Taiyuan Formation limestone, regarded as a non-effective reservoir in a long term, has demonstrated its significant accumulation potential in the central-eastern Ordos Basin. This study systematically analyzes the geological conditions controlling natural gas accumulation and reveals a "sandwich-type" accumulation model, in which the coal seams of No. 5 in the Shanxi Formation and No. 8 in the Benxi Formation respectively served as source rocks, directly contact the limestone reservoir, and a high source-reservoir pressure difference about 8-12 MPa drives efficient gas charging. Bioclastic shoals (porosity of 2.6%, and thickness of 4-10 m) and bioherms (thickness of 2-6 m, dissolution pores developed) are identified as high-quality reservoirs, with fractures and penecontemporaneous karstification jointly improving reservoir performance. By integrating the volumetric method, small-element volumetric method, resource abundance analogy, and basin modeling, the total in-place natural gas resources of the Taiyuan Formation limestone are estimated at 1.553 5×10¹² m³, with the remaining unproven resources amounting to 1.544 7×10¹² m³. The bioclastic shoal facies has the highest enrichment (about 53.1% of the remaining unproven resources), being the priority exploration target. This study provides a critical basis for increasing natural gas reserves and production in the Ordos Basin and for evaluating similar tight carbonate gas reservoirs.

The lateral migration of deepwater channel-lobe complexes, driven by the gravity flow-bottom current interaction, is a critical yet poorly understood process in deepwater deposition. Using ANSYS finite element analysis, this paper conducts the numerical simulations to replicate the sediment distribution patterns and investigate the sedimentary dynamics during Late Eocene in the Rovuma Basin. Our simulations reveal the two primary mechanisms governing sedimentation and erosion in its migrating channel-lobe complexes: (1) Bottom current primarily affect fine muddy particles in gravity flow, while having minimal influence on coarser sand particles. This selective transport causes muddy particles to drift in the downstream direction of the bottom current, leading to the formation of asymmetric muddy overflow levees. (2) Bottom current shift the high-velocity core of channel flow toward the counter-bottom current side, creating additional lateral erosion on that side of the channel wall. The continuous interplay of these sedimentation and erosion processes enhances geomorphic asymmetry, driving the progressive migration of channel-lobe complexes toward the counter-bottom current side. These findings provide new insights into the sedimentary dynamics of gravity flow-bottom current interactions, enhancing our understanding of deep-water depositional processes.

In recent years, driven by the reef-shoal hydrocarbon accumulation theory, it has been confirmed that the intra-platform shoals of the Changxing Formation in the eastern part of southern Sichuan Basin have good gas-bearing properties. However, the sedimentary system and reservoir distribution of the thick-bedded limestone reservoirs remain unclear, thus restricting the deployment of oil and gas exploration. Based on outcrop, thin section, and well-seismic data, this paper carries out sequence division and third-order framework construction of the Changxing Formation, identifies sedimentary facies by integrating lithofacies, logging facies, and seismic facies, and accordingly analyzes the dominant facies belts of high-quality reservoirs and their favorable distribution areas. The results show that：(1) Three sequence boundaries (SB1, SB2 and SB3) are identified in the Changxing Formation in the eastern part of southern Sichuan Basin, which can be further divided into two third-order sequences (Sq1 and Sq2) from bottom to top. In the early stage, carbonate deep-shallow ramp developed; in the middle-late stage, ramp-type carbonate platform developed. Among these, the intra-platform shoal subfacies of the open platform facies mainly developed during the Sq1-HST and Sq2-HST depositional periods, with the most extensive development occurring particularly in the Sq2-HST period. The shoal bodies exhibite a lateral migration trend in the planar distribution and are only locally superimposed vertically. (2) The reservoir lithology is predominantly bioclastic limestone, with pore spaces and fracture-vug systems serving as the main reservoir spaces. The formation of reservoirs is primarily controlled by sedimentary facies and dissolution processes, and favorable reservoir zones concentrated in the intra-platform shoal subfacies, displaying a scattered patchy distribution. (3) According to the sedimentary facies, the development location and thickness of shoal bodies, and the development thickness of reservoirs, three favorable reservoir development areas and two potentially favorable reservoir development areas are evaluated and predicted: the area around Z207-Z201-Z202 well area, the B28-B61 well area, the B24-G11 well area are classified as favorable reservoir development zones; the BH2-BH3 well area and F7-N49 well are the potential favorable reservoir development zones. The systematic study on the sedimentary facies and reservoir characteristics of the thick-bedded limestone of the Upper Permian Changxing Formation in the eastern part of southern Sichuan Basin provides strong guidance for the next step of oil and gas exploration in the reef-shoal field of this area.

The Jurassic coal-measure total petroleum system in the southern and northern margin of the Tianshan mountains possess enormous oil and gas resource potential and represents a crucial area for domestic oil and gas reserve growth and production increase. However, it faces key challenges such as ultra-deep burial, ultra-high temperature and pressure, intense tectonic compression, and rapid sedimentary facies migration rates, and the typical reservoir development characteristics and spatial distribution patterns remain unclear. Based on drilling, logging, experimental testing,and outcrop data, and drawing on years of oil and gas exploration practice in the Kuqa Depression and the southern margin of the Junggar Basin, this study applies the theory and technical methods of the total petroleum system to systematically clarify the characteristics of all-type of reservoirs and new exploration directions.It is concluded that: (1) The Jurassic coal-measure strata develop a full-grain sequence sedimentary system comprising glutenite-sandstone-coal-mudstone/shale, forming all-type of reservoirs including pore-type, fracture-pore-type, fracture-type and organic-pore-type reservoirs, constituting a full-scale pore structure sequence covering millimeter-micrometer scale fractures, micrometer-scale pores and nanometer-scale pores. (2) The Jurassic coal-measure strata has also developed a continuous distribution feature of medium-low porosity and medium-low permeability conventional reservoirs, low porosity and low permeability conventional reservoirs, extremely low porosity and medium-low permeability tight reservoirs, and extremely low porosity and extremely low permeability unconventional reservoirs.The three main reservoir-forming mechanisms are: weak tectonic compression, weak compaction, and weak cementation preserving pores; strong tectonic compression creating fracture networks and enhancing porosity and permeability; and acidic fluid dissolution increasing porosity along with overpressure boosting permeability. The orderly distribution of all-type of reservoirs is controlled by the combined effects of sedimentary systems, structural compression, and organic matter evolution. (3) The fault-fracture body reservoirs (near-source tight gas ) and fracture-pore-type reservoirs (inter-source tight gas) in the thrust belt, the pore-type reservoirs (inter-source tight gas) in deep depression zone, and the medium-high maturity organic-pore reservoirs (intra-source coal and shale gas) in the slope zone will be the new exploration fields and types of the Jurassic total petroleum system.

Marine carbonate rocks in China are primarily distributed in the Sichuan, Tarim, and Ordos cratonic basins, which contain abundant hydrocarbon resources. After more than 70 years of exploration, a number of large oil and gas fields have been discovered, including Weiyuan, Anyue, Puguang, Tahe, Fuman, and Jingbian. With the intensification of deep to ultra-deep exploration efforts, there remains enormous potential for the discovery of additional large oil and gas fields in the future. This paper systematically reviews the formation conditions of large marine carbonate oil and gas fields and provides an in-depth summary of their distribution characteristics. The formation of large marine carbonate oil and gas fields requires three fundamental conditions: (1) The main source rocks have undergone multiple phases of hydrocarbon generation and remain effective and substantial to this day. (2) Multiple types of reservoirs are developed, jointly controlled by various reservoir-forming mechanisms, and the reservoirs remain large-scale even under deep to ultra-deep conditions. (3) The source-reservoir-seal assemblages are favorable, and the timing of hydrocarbon accumulation matches the period of trap formation. The distribution patterns are mainly reflected in three aspects: (1) Intra-cratonic differentiation controls the distribution of the main hydrocarbon kitchens and platform-margin belts, around which multi-story "building-like" composite hydrocarbon accumulation zones are formed. (2) Constructive diagenesis, fault activity, and sedimentary facies belts are coupled to control the development of large-scale reservoirs at deep to ultra-deep levels, forming fault-controlled hydrocarbon accumulation zones. (3) The tectonic modification interfaces within the craton match the intra-platform shoals in paleo-uplifts and slope areas, forming distal-source, large-scale lithologic-stratigraphic hydrocarbon accumulation zones.

The South China Sea, as the largest marginal sea in the Western Pacific, hosts 28 Cenozoic sedimentary basins along its periphery, constituting a highly representative petroleum-bearing basin group on the East Asian continental margin. Under the multi-stage and multi-type geodynamic interactions among the Indo-Australian, Eurasian, and Pacific plates, the structural characteristics and sedimentary fill of these basins exhibit diverse and complex spatial-temporal differentiation. Based on regional gravity, magnetic, seismic, and drilling data, and guided by the theories of plate tectonics and sequence stratigraphy, this study focuses on the controlling effects of the spreading of the South China Sea on basin evolution and the structural differences among the peripheral basins. Taking the differentiated evaluation of petroleum geological conditions in the peripheral basins of the South China Sea as the application objective, and integrating the geodynamic mechanisms of marginal sea basin formation and evolution and the fault-depression dual-layer structural features, a structural classification scheme for the Cenozoic sedimentary basins around the South China Sea is proposed. They are divided into four types: fault-depression inherited type, fault-depression subsidence type, fault-depression uplift type, and volcanically modified type. The classification criteria are established comprehensively based on geodynamic mechanisms of basin evolution, basement properties, continental crustal thickness, basin architecture, sedimentary fill, volcanic distribution, and tectonic activity. The study further reveals the macroscopic spatial differentiation pattern that these four types of basins exhibit a stepwise progression from land to sea and an asymmetric zonal distribution along the periphery of the South China Sea. Based on the differences in tectonic framework, sedimentary fill, and hydrocarbon distribution, the differentiated enrichment mechanisms and distribution patterns of hydrocarbons in different basin types are elucidated, and potential exploration fields and directions for hydrocarbon exploration in deepwater basins are proposed.

The exploration of deep to ultra-deep (burial depth > 6 000 m) marine carbonate rocks in the Tarim Basin has undergone four major shifts in exploration thinking: paleo-structure→buried-hill karst→reef-shoal body karst→interlayer karst→fault-controlled karst. The "facies-fault-karst" three-element reservoir-controlling model and the "source-fault-reservoir-cap" four-element jointly controlled hydrocarbon accumulation model have been established. Supporting key technologies, including high-density wide-azimuth 3D seismic acquisition in desert areas and strike-slip fault characterization have been developed. The exploration strata have extended from the Ordovician to the strata below the Cambrian salt at depths of 10,000 m, and the exploration domain has expanded from paleo-uplifts to slopes and depressions. Large oil and gas fields such as Tazhong No.1, Halahatang, and Fuman have been discovered in the Middle-Upper Ordovician. Breakthroughs have been successively achieved within the Upper Cambrian-Lower Ordovician in wells Xiongtan-1 and Guotan-1, with the favorable exploration area for inner dolomite exceeding 30,000 km². Furthermore, Well Shendi Take-1 obtained natural gas discovery in the 10,000-m-deep subsalt Cambrian, confirming the hydrocarbon exploration potential of ultra-deep strata. This paper systematically reviews the theoretical and technological innovations driven by the four exploration thinking shifts and the implications gained from their field application, and looks forward to the multi-layer three-dimensional exploration prospects and key research directions of the Sinian-Ordovician carbonate sequences during the 15th Five-Year Plan period, providing theoretical support and practical paradigm for the sustained reserve growth and production enhancement of ultra-deep marine carbonate oil and gas in the Tarim Basin.

Exploratory breakthroughs have been achieved in ultra-deep shale gas from the Permian Dalong Formation in Puguang area of Sichuan Basin. However, due to variable sedimentary environments, diverse lithofacies types, and great burial depths, the pore structure characteristics of different lithofacies remain unclear, which severely constrains subsequent shale gas development. Through experiments on geochemistry, petrology, and pore structure characterization, the reservoir space characteristics and controlling factors of different lithofacies of the Dalong Formation in Puguang area are systematically analyzed. The results indicate: (1) The Dalong Formation mainly develops organic-rich laminated siliceous shale, organic-bearing layered mixed shale, organic-bearing layered calcareous shale, and organic-lean shale. (2) Eight types of reservoir spaces are identified: pores within organic matter, organic matter-matrix pores, intergranular pores between rigid particles, pyrite intercrystalline pores, dissolution pores, intraparticle clay pores, tectonic fractures, and organic matter shrinkage fractures. Compared with other lithofacies, the organic-rich laminated siliceous shale develops larger-scale and more numerous organic pores, dissolution pores, and microfractures, exhibiting higher porosity, pore volume, and proportion of medium-large pores and microfractures. In contrast, organic-lean shale has poorly developed organic pores and microfractures, and inorganic pores are mostly isolated. (3) During the high-maturity thermal evolution stage, most organic matter degrades and is consumed, generating large volumes of oil and gas along with organic pores. Meanwhile, high contents of rigid siliceous minerals (such as feldspar and quartz) can not only provide relatively simple and open large-scale intergranular pores but also release more reservoir space through organic acid dissolution. Therefore, as TOC and siliceous content increase, the corresponding porosity, pore volume, and proportion of medium-large pores and microfractures show an increasing trend.

Ordos Basin, one of the most important petroleum-bearing basins in China, is characterized by multiple natural gas-bearing systems, diverse reservoir types, and abundant resources. Since the beginning of the 14th Five-Year Plan period, besides continuously implementing large-scale proven reserves in mature tight sandstone and carbonate gas plays, significant breakthroughs have also been achieved in new fields and new reservoir types such as coal-measure gas, limestone gas, deep carbonate gas, and shale gas. These advances have rendered previous resource evaluation results insufficient to meet the latest exploration situation.This paper reviews the new understandings of natural gas exploration in the Ordos Basin since the 14th Five-Year Plan. The basin hosts coal-measure source rocks in Upper Paleozoic, marine argillaceous carbonate source rocks of the 1th to 3rd members of the Majiagou Formation, and marine shale source rocks of the Wulalike Formation in Lower Paleozoic. Multiple reservoir types are developed, including tight sandstone, carbonate weathering crust dolomite, limestone, coal, marine-continental transitional shale, deep dolomite, and marine shale. The cap rocks are composed of Upper Paleozoic argillaceous rocks, Lower Paleozoic evaporite rocks (gypsum-salt rocks), and argillaceous carbonate rocks. In response to the characteristics of multiple types of gas reservoirs, a resource evaluation method system has been established, primarily based on the volumetric method, flexibly supplemented by various auxiliary methods. The in-place natural gas resources in the basin have been re-evaluated to be 46.9×10¹² m³, with 39.6×10¹² m³ remaining as unproven resources by the end of 2025. The key future exploration targets are identified as coal-measure gas, tight sandstone gas, limestone gas, and dolomite weathering-crust gas in the eastern part of the basin.

The deep to ultra-deep marine carbonate rocks in the Sichuan Basin hosts enormous natural gas resource potential, making it a key field for current reserve and production growth. However, deep gas exploration and development in the basin faces globally recognized challenges, including multi-stage tectonic reworking, intense depositional differentiation, strong reservoir heterogeneity, and complex hydrocarbon accumulation and evolution histories. Based on exploration practice of PetroChina Southwest Oil & Gas Field Company since the 13th Five-Year Plan (from 2016 to present), this paper systematically summarizes the petroleum geological conditions, key geological insights and technological advances in key exploration areas of the basin's deep to ultra-deep marine carbonate rocks, and provides a prospect for exploration directions during the 15th Five-Year Plan period. By deepening the understanding of craton-basin tectono-sedimentary evolution and the distribution of major hydrocarbon-controlling geological units, the reservoir-forming mechanisms of multiple carbonate reservoir types, and accumulation theory of ancient carbonate rocks in superimposed basins, associated with key technologies advance such as high-resolution seismic imaging and fine characterization of reef-shoal bodies, it has guided the discovery of several reserve-growth areas individually exceeding 100 billion cubic meters, including the Sinian-Cambrian around the Deyang-Anyue rift, the large platform-margin belt of the Maokou Formation in central Sichuan Basin, and the Permian-Triassic reef-shoal bodies in northern and eastern Sichuan Basin. The cumulative newly proved reserves exceed 1.27×10¹² m³. Based on this exploration practice, three core implications are drawn: (1) strengthening basic geological research, particularly those concerning regional tectonic-sedimentary evolution and lithofacies paleogeography, to define the distribution of large-scale geological units, is the key prerequisite for achieving large-scale discoveries in deep to ultra-deep strata; (2) continuous progress in key geophysical and well-logging technologies serves as the technical guarantee for translating geological understanding into exploration discoveries; and (3) scientifically formulating exploration strategies that balance both scale and efficiency is an effective path to accelerate resource conversion. Looking ahead to the 15th Five-Year Plan, the Sinian-Lower Paleozoic and Permian-Triassic strata within and adjacent to the paleo-uplifts and paleo-rifts will remain the main battlefields for large-scale conventional deep to ultra-deep gas reserve growth. Meanwhile, driven by the 10,000-meter deep earth engineering, the deep to ultra-deep marine multi-layers in northwestern Sichuan Basin are expected to form a new trillion-cubic-meter-scale exploration replacement zone.

Carbonate rocks host abundant oil and gas resources and represent an important field for current and future exploration. Carbonate rocks mostly are developed in the deep layers of superimposed basins, making the reconstruction and mapping of their lithofacies paleogeography extremely challenging, which has become a bottleneck restricting deep-layer oil and gas exploration. Based on regional seismic framework sections and new drilling data, technical and methodological innovations were made and applied to the lithofacies paleogeographic mapping of key marine carbonate rock formations in China's three major cratonic basins. The following new advances have been achieved: (1) A "three-element" paleogeomorphologic restoration technique and a standard for compiling carbonate lithofacies paleogeographic maps have been established. (2) Paleogeomorphological restoration practices revealed that graben-horst and uplift-depression structures are the main controlling types of the carbonate paleogeomorphologic background in the three major cratonic basins. (3) The practice and iteration of carbonate lithofacies paleogeographic mapping revealed that the carbonate platforms in the three major catonic basins exhibit an evolutionary pattern of "gentle slope—rimmed-evaporative—drowned (eroded)". (4) Two distinctive carbonate depositional models of "multi-slope-break-controlled reef-shoal" and "multi-uplift-controlled reef-shoal" were innovatively established. The research results have enriched the carbonate sedimentological theory, facilitated new discoveries in oil and gas exploration, and provide valuable reference for domestic and international carbonate rock research and oil and gas exploration.

Marine carbonate deep oil and gas is a major field of widespread concern both domestically and internationally. Through long-term exploration practices, China has achieved significant breakthroughs in the exploration of deep/ultra-deep marine carbonate oil and gas resources in the Sichuan, Ordos, and Tarim basins. However, debates persist regarding the genesis, sources, and formation evolution of gas reservoirs. Based on fundamental geological elements and formation conditions of gas reservoirs, and utilizing 940 sample data, this study analyzes the genesis, sources, and formation processes of China's large carbonate gas fields. The results indicate that: (1) Large carbonate gas fields in the three major marine basins share certain commonalities and differences. The commonality lies in the widespread low porosity and low to ultra-low permeability characteristics of reservoirs, with gas reservoirs having proven geological reserves exceeding 100 billion cubic meters being predominantly low-pressure to normal-pressure reservoirs. However, there are notable differences in productive layer distribution, reservoir burial depth, pressure coefficients, and porosity-permeability conditions. (2) The composition and isotopic characteristics of natural gas in these large carbonate gas fields differ significantly among the three basins, suggesting differences in organic matter types and thermal maturity of the parent materials. (3) Natural gas in the three basins primarily originates from high-to-overmature oil cracking gas, supplemented by mature kerogen cracking gas. The primary source is oil-type gas, accounting for approximately 88% according to preliminary estimates, while coal-type gas serves as a secondary source, comprising 12%. These gases have generally undergone secondary alterations such as TSR (thermochemical sulfate reduction) and gas invasion. (4) The natural gas in the three basins is sourced from multiple origins, with five source systems in the Sichuan Basin, two in the Ordos Basin, and two in the Tarim Basin. (5) Four accumulation models for large marine carbonate gas fields in China: (a) In-situ oil cracking gas accumulation in paleo-oil reservoirs under high geothermal gradient conditions, (b) gas-invasion-type reservoirs under low geothermal gradient conditions, (c) dual-source mixed cracking gas accumulation, and (d) three-dimensional accumulation controlled by fault-cap coupling.