Carbonate oil and gas fields represent a significant component of global hydrocarbon resources, accounting for over 60% of the total conventional reserves. This paper systematically reviews the distribution characteristics of giant carbonate oil and gas fields worldwide. Through analysis of typical fields, it summarizes the primary controlling factors for hydrocarbon accumulation and identifies new frontiers for exploration. The results indicate that these giant fields are predominantly located in regions such as the Persian Gulf Basin in the Middle East, the Pre-Caspian Basin in Central Asia, the Permian Basin in North America, and the Santos Basin in Brazil, with reservoir ages ranging primarily from the Mesozoic to Cenozoic. The key factors controlling hydrocarbon accumulation include: (1) sedimentary background, which determines the scale of source-reservoir-cap rock systems; (2) tectonic and diagenetic modifications, which create large-scale reservoirs; (3) tectonic stability and seal integrity, which are crucial for reservoir preservation. Future exploration should focus on new frontiers such as ultra-deep formations, deep-water environments, complex tectonic zones, and unconventional carbonate reservoirs, which are expected to become vital successors for future resource supply.

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.

Marine carbonates have played a crucial role in the over 70-year natural gas exploration history of the Sichuan Basin, and will remain a primary target field for natural gas exploration and development for a long time to come. Based on the study of tectonic and lithofaies paleogeographic evolution of the entire marine strata, a systematic analysis of the macro-control factors and the influencing factors of the reservoirs of different formations has been conducted in order to explicitly define the distribution and exploration directions of large scale high-quality marine carbonate reservoirs in the Sichuan Basin. The study concludes that: (1) The marine strata of Sichuan Basin has undergone four major tectonic cycles, with 13 significant tectonic movements. Of these, two tension-dominated movements created the paleogeographic pattern of the trough-platform alternation, while eleven uplift-dominated movements governed the sedimentary characteristics of the large platform/ramp. (2) The conventional marine carbonate reservoirs in the Sichuan Basin can be simply divided into two main types: sedimentary facies-controlled reservoir and karst reservoir. The development of high-quality reservoirs is macroscopically controlled by tectonic processes, mainly distributed in the inclined areas of ancient uplifts and the geomorphic high zone on both sides of the ancient rifts. (3) Six potential areas for large-scale exploration of carbonate rocks in the future in the Sichuan Basin are proposed: the platform-margin zone of the Dengying Formation on the west side of the Deyang-Anyue rift trough, the dolomitization shoal of the Lower Paleozoic on the east edge of paleo-uplift in the central Sichuan Basin, the multi-layered platform-margin zone of the Upper Paleozoic on the west side of the Sichuan Basin, the dolomitization shoal of the lower part of the lower second member of Maokou Formation in Xuanhan-Wanzhou area of the eastern Sichuan Basin, the dolomitization shoal of the third member of Maokou Formation in Yilong-Quxian area of the eastern Sichuan Basin, and reef-shoal limestones of the Changxing Formation along and within the Pengxi-Wusheng intra-platform sag.

The microbial carbonates of the Lower Cretaceous Barra Velha Formation in the Santos Basin, Brazil, primarily formed in a high-salinity alkaline depositional environment, and have recently become a hotspot for hydrocarbon exploration and development in deep-water areas. However, research on the characteristics of microbial carbonate reservoirs formed in such unique environment is relatively limited and controlling factors of reservoir formation remains poorly understood. Based on integrated core samples, thin sections, well logs, and petrophysical test data, this study systematically investigates the lithofacies, reservoir space types, and physical properties of microbial carbonates in the basin. It clarifies the diagenetic sequence and pore evolution of the reservoirs and explores the main controlling factors and models for the development of high-quality reservoirs. The research results show that: (1) The main rock types of microbial carbonate reservoirs of the Lower Cretaceous Barra Velha Formation in the Santos Basin include stromatolite, spherulitite, laminite, rudstone, grainstone and breccia. The formation can be divided into two third-order sequences, primarily consisting of four microfacies types: microbial reef, grain shoal, microbial spherulitic shoal, and inter-shoal deposits. (2) The reservoir space is mainly composed of biological framework pore, framework dissolution pore, intergranular pore, intergranular dissolution pore, intragranular dissolution pore, intercrystalline pore, and dissolution fracture. Porosity and permeability generally exhibit a positive correlation, indicating the dominance of pore-type reservoirs. Statistics show that the microbial reef and grain shoal microfacies have better reservoir properties, while the microbial spherulitic shoal and inter-shoal microfacies show relatively poorer reservoir quality. (3) The diagenetic sequence and pore evolution of microbial carbonate reservoirs have been clarified. In the early diagenetic stage, meteoric water dissolution and dolomitization played constructive roles in reservoir evolution. In contrast, mid-to-late hydrothermal activity led to silica filling of reservoir pores particularly in areas adjacent to faults, which not only damaged the reservoir but also increased reservoir heterogeneity. (4) Paleoclimate, paleo-water condition, sequence stratigraphy, and sedimentary microfacies types are the main factors controlling the development and distribution of high-quality microbial carbonate reservoirs. Combined with diagenetic evolution, an evolution model of microbial carbonate reservoirs has been established in this study.

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.

There are relatively few summaries and comparative studies on the formation conditions, hydrocarbon accumulation models, and main controlling factors of carbonate oil and gas fields in the South China Sea (SCS), making it difficult to guide oil and gas exploration in similar areas of the SCS. Based on the tectonic background and basement control factors, the carbonate platforms in the SCS are classified into three types: stable, fault-block and inverted. Typical oil and gas fields in each type of platform are selected for dissection to analyze the characteristics of hydrocarbon source- reservoir-cap conditions, hydrocarbon accumulation patterns and main controlling factors. The research suggests that: (1)The source rocks of carbonate reservoirs in the SCS are mostly Oligocene-Miocene coal rocks and coal bearing mudstones form. The reservoirs are mostly composed of Middle-Upper Miocene biogenic reef limestone and calcarenites, with porosity mainly ranging from 20% to 25%, and permeability mainly at the range of (100-200) × 10^-3 μm². The cap rock is Upper Miocene marine mudstone. (2)The three types of platforms exhibit distinct hydrocarbon accumulation models: stable platforms follow a "lower generation, lateral reservoir" model with long-distance migration; fault-block platforms adhere to a "lower generation, lateral reservoir" model with short-distance migration; inverted platforms exhibit a "lower generation, upper reservoir" model with short-distance migration. (3)The three types of carbonate platforms have different potential exploration areas: stable platforms focus on carbonate buildups developed above unconformities or sandstone bodies; fault-block platforms focus on the carbonate buildups on the horst adjacent to the fault depression. For reversed platforms, priority should be given to the carbonate buildups directly developed on the depression, which is also the most important exploration area for carbonate reservoirs in the SCS at present.

Three marine shale formations of the Middle-Upper Permian—the Gufeng Formation (P₂g), the 3^rd member of the Wujiaping Formation (P₃w₃) and the 1^st member of the Dalong Formation (P₃d₁), are well developed in the northeastern Sichuan Basin, representing promising new targets for enhancing shale gas reserves and production. Based on extensive core testing data, this study analyzes their geochemical characteristics, reservoir features and proposes corresponding development strategies to provide theoretical support for shale gas exploration in China. The key findings are as follows: (1) All three shale formations exhibit high organic matter abundance, with average total organic carbon (TOC) contents of 9.82% (P₂g), 6.60% (P₃w₃) and 6.01%(P₃d₁), respectively. The organic matter is classified as type II₁, and the maturity(R_o) exceeds 2.0%, indicating significant hydrocarbon generation potential. The Gufeng Formation is dominated by siliceous shale and calcareous shale facies, whereas P₃w₃ and P₃d₁ primarily consist of siliceous shale and mixed shale facies. The brittleness index of all three formations exceeds 70%. Organic pores are the dominant pore type, with mesopores serving as the primary pore category. (2) The P₃w₃ exhibits well-developed laminated fractures, highest pore connectivity index (average value of 5.17), high porosity and high gas content; the P₂g has moderate pore connectivity index (average value of 2.57), high porosity and gas content; the P₃d₁ shows poor laminated fracture development, the lowest pore connectivity index(average value of 1.69), the lowest porosity value and relatively high gas content.(3) Compared to the Longmaxi Formation in southern Sichuan Basin, these three shale formations are characterized by high TOC content, high brittleness index, high gas content, thin thickness and deep burial depth. Targeted development technologies are thus required. Favorable areas for shale gas enrichment of these three formations are primarily distributed in the southeastern segment of the Kaijiang-Liangping Trough and the Chengkou-Fengjie-Lichuan-Shizhu area of the Chengkou- E'xi Trough.

Taking the middle and upper sections of the Pinghu Formation on the Pinghu slope in Xihu Sag as an example, by synthesizing the research achievements of coastal sedimentary systems at home and abroad, this study innovatively integrates paleogeomorphology, sedimentary characteristics of tidal flat areas, and coastal sedimentary models to explore their impacts on tidal dynamics and sedimentary system distribution, providing key basis for subsequent large-scale lithologic trap oil and gas exploration and development. Comprehensive application of drilling and logging data, seismic data, and sedimentary process numerical simulation techniques is conducted to simulate the spatio-temporal evolution of the sedimentary system. Through qualitative description and quantitative measurement, the distributions of unique sedimentary units such as tidal channels, tidal gullies, tidal sand ridges, and tidal sand sheets are clarified, the controlling effects of coastal topography and sea-level changes on tidal sedimentary sand bodies are revealed, and three sedimentary models, namely barrier coast, barrier-free underwater low-relief coast, and barrier-free gentle slope coast, are constructed to improve the theoretical framework of coastal sedimentary systems. Further comparative analysis between numerical simulation and actual data shows that barrier coast sand bodies are sheet-like distributed during low sea-level periods, while underwater low-relief coast sand bodies are ribbon-like distributed during high sea-level periods. For the first time, large-scale tidal sand ridges in barrier and underwater low-relief sedimentary environments and restricted tidal channel sand bodies are identified as key targets for oil and gas exploration.

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.

The cratonic strike-slip fault zone is an important hydrocarbon accumulation zone in the ultra-deep carbonate rock field of Tarim Basin. At present, the natural energy of the oil reservoirs in the strike-slip fault zone is insufficient, and the decline rate of the oil reserves is fast. It is urgent to deepen the understanding of the geological characteristics of such oil reservoirs, explore new development methods, and investigate countermeasures for enhancing recovery rate. Based on the detailed study of the 12th and 17th fault zones in Fuman Oilfield through comprehensive analysis of outcrops, drilling, seismic surveys, core thin sections, production dynamics, well tests and other data, the types of reservoir space, internal structural characteristics and hydrocarbon accumulation features of the fractured breccia reservoirs are precisely characterized. Appropriate countermeasures for enhancing recovery rate are proposed. The research results indicate: (1) The fractured breccia reservoirs belong to vertical plate-shaped oil reservoirs. The reservoirs develop in the fault core and fracture zone, their reservoir space types are breccia interstitial pores, cavities and structural fractures formed by cataclasis. (2) The ultra-deep fractured breccia reservoirs are initially deposited as tight lithofacies, with very low pre-existing formation porosity and permeability, preserving a low amount of original formation water. There was no significant dissolution of atmospheric water in the later stage, which led to the fractured reservoir bodies having the characteristics of high oil column (up to one thousand meters) and being water-free or having little water content. (3) In terms of geological understanding, detailed description of reservoirs and development methods, three aspects of understanding transformation have been formed: from fault-controlled karst reservoir to fractured breccia reservoir, from description of fault-karst oil reservoir to the internal structure description of fractured breccia oil reservoir, from water injection development to gas injection development.

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 Asmari Formation in Iraq B Oilfield was deposited in a remnant ocean basin environment formed during the closure process of the Neo-Tethys Ocean. Influenced by the intermittent uplift of the Arabian Shield from the Oligocene to Miocene, the study area developed a multi-stage terrigenous clastic supply system. Under the depositional background of a gentle slope, frequent sea-level fluctuations have led to complex mixed sedimentary characteristics of sandstone, dolomite, limestone, and mixed rocks in vertical and planar distributions, whose lithological distribution laws remain to be further clarified. This study takes Iraq B Oilfield as the research object, and systematically reveals the main controlling factors of complex lithology development under the gentle slope background through detailed core observation, thin-section microscopic analysis, and comprehensive interpretation of drilling and logging data. The research has achieved the following understandings: (1) The lithologies of the Asmari Formation can be scientifically classified into three major categories: carbonate rocks, mixed rocks, and terrigenous clastic rocks. Among them, mixed rocks are further subdivided into 8 types based on the 50% ternary classification nomenclature; seven typical lithofacies combination sequences are identified through the coupling analysis of petrological characteristics and logging responses. (2) The spatial distribution of lithofacies shows significant zonation: the northwestern and southeastern regions of the study area are dominated by carbonate facies, the proportion of clastic facies in the central part increases significantly, and the mixed rock facies account for a large proportion in the remaining transition zones. (3) The paleogeomorphology of the study area presents a gentle slope pattern of "low in the northwest and southeast parts and high in the central part". The comprehensive tectonic-sedimentary analysis shows that terrigenous clastic sediments are mainly developed in the paleo-uplift area, carbonate sediments are developed in the paleo-depression area, and mixed sediments are dominant in the transitional slope zone. Finally, a development model of complex lithology controlled by three factors of "paleogeomorphic form—sea-level fluctuation—material source supply" under the gentle slope background is established.

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 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.

The Lower Paleozoic marine carbonate rocks in the Ordos Basin represent a critical natural gas exploration target in China. However, problems such as strong reservoir heterogeneity and complex hydrocarbon accumulation controlling factors have severely restricted large-scale and efficient exploration and development. This study integrates the latest exploration results with regional seismic profiles, focusing on key scientific issues such as lithofacies paleogeographic evolution, genetic types and controlling factors of reservoirs, and source-reservoir configurations, to systematically investigate the distribution patterns of high-quality carbonate reservoirs and evaluate their exploration potential. The main findings are as follows: (1) The Early Paleozoic sedimentary environment underwent a complete evolutionary sequence from mixed sedimentary shelf (Mantou to Xuzhuang Formation) to carbonate ramps (Zhangxia to Majiagou Formation) and finally to rimmed platforms (Upper Majiagou Formation). Among these, the inner ramp grain shoal facies belts around paleo-uplifts and marine basins exhibit the most favorable reservoir properties. (2) Reservoir development is jointly controlled by depositional microfacies, penecontemporaneous dissolution, supergene karstification, and dolomitization. Five types of reservoirs are identified in the Cambrian-Ordovician succession: grain shoal, algal mound, bioturbated, moldic pore, and dissolution vug types. These reservoirs are predominantly distributed along paleo-uplifts, basin margins and slope breaks. (3) Based on comprehensive analysis of tectonic-sedimentary framework, source-reservoir relationships, and sealing conditions, three highly prospective exploration zones are delineated: the eastern Wuyin marine basin, both flanks of the Yitong marine basin, and the western Shenmu-Mizhi platform depression, with a total area of 10.5×10⁴ km². This study provides critical theoretical support and practical guidance for gas exploration in marine carbonate rocks of the Ordos Basin.

The tight gas resource potential of the Lower Jurassic Ahe Formation in Dibei area of the eastern Kuqa Depression is enormous, making it a promising region for increasing oil and gas reserves and production. For a long time, the coupling relationship between sweet spot model and oil and gas enrichment of tight sandstone reservoir in Ahe Formation is unclear, which restricts the efficient exploration and development of tight oil and gas reservoirs.Based on microscopic reservoir characterization, geological modeling, fault-fracture characterization and reservoir analysis, this paper investigates the sweet spot characteristics and hydrocarbon enrichment patterns of tight sandstone reservoirs in the Ahe Formation, and evaluates their resource potential. The study reveals that the Ahe Formation reservoirs exhibit an alternating distribution of tight layers and low-porosity/high-permeability zones laterally. Reservoir properties are significantly enhanced by fault-fracture modification, developing sweet spot areas at four hierarchical scales. The fracture-pore systems controlled by class I-II faults extend east-west direction, characterized by large scale and favorable porosity-permeability properties. The fracture-pore systems controlled by class Ⅲ-Ⅳ faults/fractures are small in scale and pinch out within tight sandstones. The first hydrocarbon charging event in the Ahe Formation reservoirs occurred between 18 and 12 Ma, with porosity ranging from 15% to 18% during this phase. The primary charging fluid was crude oil, which accumulated in structural highs to form conventional oil reservoirs. However, these reservoirs were subsequently severely disrupted, leading to complete dissipation of the accumulated hydrocarbons. The second hydrocarbon charging phase commenced since 5 Ma, during which the reservoir underwent rapid densification, with porosity reduced to 6%-8%. Natural gas efficiently migrated along faults and fractures, accumulating preferentially within sweet spot zones of the reservoir. Class Ⅲ and Ⅳ faults/fractures zones establish effective connectivity between sandstone units within the Ahe Formation, forming optimal configurations with adjacent tight reservoirs and overlying mudstones. These structural features constitute critical controls on both trap effectiveness and hydrocarbon accumulation. The favorable area for oil and gas enrichment in tight sandstone of the Ahe Formation can reach 106 km², mainly concentrated in the central and southern platform areas of the Dibei Slope. The lithological trap resources of natural gas are 1 699 × 10⁸ m³ and petroleum are 778 × 10⁴ t.

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.

In recent years, natural gas exploration breakthrough has been made in the Ordovician Majiagou Formation of Ordos Basin, but the formation and evolution of natural gas have not been thoroughly studied. Taking Daniudi gas field as an example, the typical characteristics of oil-cracked gas in Majiagou Formation are determined through the identification of bitumen in the core and thin section, the occurrence of hydrocarbon inclusions and Raman spectroscopy testing, and the analysis of geochemical data of natural gas. The formation conditions of oil-cracked gas are comprehensively analyzed, and the formation and evolution process of oil-cracked gas in Majiagou Formation are analyzed through the simulation of burial history and thermal history. The results show that: (1) Bitumen filling with diverse occurrences is found in the fractured porous reservoir of Majiagou Formation, and it is a dry bitumen with high degree of thermal evolution. Three phase hydrocarbon inclusions of oil, gas and bitumen are captured in calcite veins of Majiagou Formation, which confirms the existence of oil cracking gas process. (2) Based on the crossplot of geochemical index such as ln(C₁/C₂) and ln(C₂/C₃) of natural gas, it shows that the internal natural gas of Majiagou Formation is mainly oil-cracked gas. (3) During the deposition period of 3^rd member of Majiagou Formation, Daniudi and its surrounding areas were situated at the margin of a saline depression, where thick source rocks of argillaceous dolomite and dolomitic mudstone developed with interbedded evaporates, creating favorable conditions for thermochemical sulfate reduction (TSR). (4) In the Early Jurassic, source rocks produced a large amount of oil. Under the effect of the relatively high paleotemperature in the Early Cretaceous, high-temperature oil cracking occurred, and TSR reaction occurred with significantly increased H₂S content in the natural gas of O₁m₅⁵-O₁m₅⁶ of Majiagou Formation in Daniudi gas field. (5) In Daniudi and surrounding areas, the source rocks of Majiagou Formation became mature earlier in the south and later in the north, and natural gas mainly migrated and accumulated from south to north along the strike-slip faults. This study has certain significance for the internal gas exploration of Majiagou Formation in Ordos Basin.

This study addresses the core issues of unclear sequence architecture and sedimentary evolution patterns of the bioclastic limestone member of the Carboniferous Bachu Formation in eastern Tazhong area, Tarim Basin. Based on a wealth of data, including core, thin section, logging, and geochemical data, we conduct an in-depth analysis of the petrological characteristics of the bioclastic limestone member, construct the sequence stratigraphic framework for this member, and explore its control on sedimentation and reservoir formation. The research findings demonstrate that: (1) The bioclastic limestone member in the eastern Tazhong area represents a mixed siliciclastic-carbonate sedimentation within a marine-terrestrial transitional setting, mainly composed of micritic to peloidal limestone/dolomite, calcarenite/doloarenite to calcirudite/doloyunrudite, mixed rocks, and transitional lithologies, with a relatively high content of terrigenous clastics. The distribution of lithologies exhibits distinct vertical segmentation and lateral zonation patterns. (2) Based on variations in lithology and sedimentary facies, the bioclastic limestone member, along with the underlying Donghe sandstone member, the lower mudstone member, and the overlying middle mudstone member, forms a complete three-order sequence. The bioclastic limestone member itself represents a complete transgressive-regressive sequence, with the middle submember recording the relatively deepest marine flooding conditions during deposition. (3) The eustatic cycles exert a decisive influence on the evolution of sedimentary microfacies and diagenetic processes. The lower and upper submembers, deposited in shallow waters, are dominated by supratidal dolomicrite (dolomudstone) facies within evaporitic tidal flats. During relative sea-level rise in the middle submember, high-energy grain shoal complexes developed within intertidal settings, where superimposed high-frequency exposure events drove meteoric dissolution and penecontemporaneous dolomitization, thereby generating high-quality reservoirs with superior storage capacity. These dolomitized grain shoal and dolomicrite flats with pinprick vugs together constitute the most favorable reservoir facies of the bioclastic limestone member in the eastern Tazhong area, Tarim Basin, and represent the primary targets for future exploration and development.

Large carbonate hydrocarbon fields have long been a global research focus. Statistical analysis of IHS data reveals that Africa's giant carbonate oil and gas fields are mainly distributed in five basins: the Sirte, Pelagian, and Eratosthenes basins in North Africa, and the Lower Congo and Kwanza basins in West Africa. Among them, Sirte Basin accounts for 48.2% of Africa's total carbonate oil and gas reserves, making it the most prolific. Through detailed analysis of 19 large carbonate oil and gas fields, the conclusions are drawn as following: (1) The passive-margin marine transgressions associated with the Late Cretaceous-Eocene opening of the Neo-Tethys Ocean and South Atlantic are prerequisites for large-scale hydrocarbon accumulation in carbonate rocks, with the main reservoirs developed in the Cretaceous, Paleocene, and Eocene strata. (2) Unlike deep-water carbonate rocks, the shallow marine sedimentary environment and low latitude warm and humid climate after the breakup of Gondwana continent control the scale distribution of reservoirs and source rocks, forming various types of reservoirs mainly composed of bioclastic limestone, with dolomite, foraminifera limestone, oolitic limestone, and reef limestone as secondary reservoirs, and high-quality source rocks mainly composed of shallow marine shale. (3) During the base-level rise period (lowstand to transgressive system tracts), multiple sets of marine shale (source)-carbonate rock (reservoir)-shale (cap) combinations tend to develop. Subsequently, through sedimentary burial and tectonic processes, structural traps and stratigraphic-lithologic traps are primarily formed, leading to hydrocarbon accumulation. (4) The widely developed limestones, grainstones, and dolomites, along with diagenetic processes, governs the effective reservoirs and physical properties of large carbonate oil and gas fields. Large oil reservoirs are characterized by moderate to high porosity and moderate to low permeability, whereas large gas reservoirs typically exhibit moderate to low porosity and moderate to high permeability. From the distribution of recoverable oil and gas reserves in African carbonate rocks, there is still a huge exploration space, and the mature theoretical techniques in the genesis and characterization of carbonate reservoirs in China are worthy of further referencing.

The Maokou Formation of Middle Permian has huge resource potential and is an important target for natural gas exploration in Sichuan Basin. In recent years, significant exploration breakthroughs have been made in the dolomite of the 2^nd member of Maokou Formation in central Sichuan Basin, and the gas production of several wells has exceeded one million cubic meters, which reveals the huge exploration prospect in this field. However, the genesis of dolomite is still unclear, which restricts the prediction of dolomite distribution. Focusing on the core exploration wells in Hechuan area, a detailed description of the petrological characteristics based on core and thin sections is carried out, and representative samples of dolomite and limestone are selected for carbon oxygen isotope, strontium isotope, rare earth element, and U-Pb dating analysis. Taking into account the geological background, it was clarified that: (1) Dolomite is mainly developed in the middle-upper part of the 2^nd member of Maokou Formation, with a thickness of 1-25 m, and its original rock is grainy limestone. (2) The dolomitization fluid is mainly seawater, and dolomitization occurred in the quasi-contemporaneous period-early burial period. (3) The shoal developed in a relatively paleogeomorphologic high part of the 2^nd member of Maokou Formation was susceptible to syngenetic karstification, and a large fracture-cavern system developed in the phreatic zone. Fracture-cavern system were filled with bioclastic particles, marl and Mg²⁺ rich seawater, and dolomitization occurred during the shallow burial process. Based on the new research results of dolomite genesis, it is clear that the paleogeomorphologic high part is the favorable area of dolomite of the 2^nd member of Maokou Formation, which provides a basis for the prediction of dolomite reservoir distribution in the study area and effectively guides the exploration deployment.

Taking the Cambrian Xiaoerblak section in the Keping outcrop area as an example, this study aim to clarify the differences in the characteristics and distribution patterns of dolomite reservoirs of the Upper Cambrian Xiaqiulitage Formation in the western Tarim Basin. Based on a systematic analysis of rock thin section, carbon and oxygen isotope compositions, and U-Pb dating, the conclusions are drawn as follows:(1) The Xiaqiulitage Formation, with a total thickness of 350 m, is divided into six members, and is composed of grain dolomite, thrombolite dolomite, stromatolite dolomite, and laminated microbialite dolomite. Seven lithofacies association and two third-order sequences are identified in the Xiaqiulitage Formation, reflecting the overall transition of tidal flat subfacies to inner platform shoal subfacies from bottom to top. (2) The reservoir spaces are dominated by matrix dissolution pores, vugs (dissolution cavities), and intergranular fractures within breccias. The columnar stromatolitic dolomite and thrombolitic dolomite exhibit the best physical properties, followed by grain dolomite, with the overall characteristics of moderate-to-high porosity and moderate-to-low permeability. A comprehensive evaluation indicates that the reservoir properties are optimal in Member 1, Member 2, and Member 6, while Member 5 ranks slightly lower. (3) The dolomite was formed during the early diagenetic stage, and reservoir development is primarily controlled by the combined effects of sedimentary microfacies, unconformity surfaces, and high-frequency sequences. The reservoirs can be classified into two types: unconformity-karst dolomite reservoirs and inner mound-shoal dolomite reservoirs. This research provides critical support for evaluating favorable exploration zones in the Cambrian dolomite plays of the western Tabei area, and offers reliable evidence for hydrocarbon reservoir assessment, particularly in the Xiongying region.

The development potential of the Middle-Upper Jurassic Callovian-Oxfordian carbonate rocks in the western right bank of the Amu Darya River in Central Asia is limited by the poor understanding of the distribution of intra-platform shoals. Based on the high-frequency sequence division technology of INPEFA and wavelet transform, the high-frequency sequence stratigraphic framework is established. Through the integrated use of 3D seismic data, the planar distribution of the platform shoal is systematically described and its vertical evolution pattern is studied. The results show that: (1)The Callovian-Oxfordian in the study area can be divided into 5 third-order sequences and 15 fourth-order sequences. The Oxfordian is composed of 3 third-order sequences and 9 fourth-order sequences. The Callovian is composed of 2 third-order sequences and 6 fourth-order sequences, which are significantly affected by the paleotopographic differences and have locally developed onlap deposits. (2) Six types of lithofacies are mainly developed in the study area, including granular limestone and grain-bearing lime mudstone to silt-sized crystalline limestone. In the early stage, it is a carbonate gentle slope model, and the water body deepens from west to east. In the late stage, it transitions to a restricted platform-evaporation platform model, and multiple sets of shoal thin layers are developed. (3)During the Callovian-Oxfordian period, the water body continued to become shallow, and the shoal development exhibited a stage-wise enhancement. The sedimentary evolution shows that the XVac, XVp and XVm formations represent the peak intervals of shoal facies development, and the intra-platform shoals generally show the characteristics of vertical stacking patterns and lateral amalgamation during the late stages.

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.

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.

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.

For the Carboniferous Huanglong Formation, an important natural gas production layer in Sichuan Basin, in low-relief structural zone on the west side of Huayingshan Fault, there are still problems of unclear accumulation conditions and undetermined favorable exploration zones due to low exploration degree. Based on exploration wells, 2D and 3D seismic data, a new round of evaluation is conducted on the distribution of strata, lithofacies paleogeography, and natural gas accumulation conditions of Huanglong Formation on the west side of Huayingshan Fault. The results show that: (1) The residual strata of Huanglong Formation with thickness mainly between 10-40 m are widely distributed (about 13 100 km²), and about 4 000 km² according to the new seismic interpretation is added in the northern Sichuan Basin. (2) The intertidal shoal dolomites are widely developed (about 8 200 km²), mainly in the Huanglong Member 2, followed by the Huanglong Member 3. The newly discovered Pingchang-Bazhong shoal belt covers an area of about 2 000 km². The thickness of dolomite reservoir of the shoal facies in HuangLong Member 2 is mainly 2-20 m. The reservoir has good physical properties, with an average porosity of 3.90%. (3) The source rocks of Wufeng Formation-Longmaxi Formation in the northern Sichuan Basin are widely developed covering an area of about 25 000 km², and the total thickness is 50-150 m in which the high-quality is 10-60 m. The source rocks of Wufeng Formation-Longmaxi Formation and the reservoirs of Huanglong Formation form favorable reservoir combination of lower generation and upper storage. (4) Controlled by the paleo-uplift slope zone, strata denudation zone, and large fault zone, the Huanglong Formation has developed two large trap groups, i.e., Pingchang-Bazhong, and Guang'an-Quxian, with diverse trap types dominated by lithological-stratigraphic traps and good preservation conditions. Four favorable exploration areas are predicted, indicating a promising prospect for natural gas exploration.

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.

With the continuous expansion of oil and gas exploration into ultra-deep and ancient strata in the three major marine cratonic basins, challenges such as unclear favorable exploration zones have emerged. Therefore it is imperative to deepen research on depositional models for critical geological periods. Based on the summary of the Neoproterozoic-Paleozoic tectonic-sedimentary differential evolution characteristics of the three major basins, this paper analyzes the controlling effects of tectonic differentiation on sedimentary evolution. It is pointed out that the three ancient marine cratonic basins exhibit a tectonic differentiation pattern of "rift-depression-uplift", driving carbonate platforms undergoing an evolutionary cycle of "isolated platform-ramp-rimmed platform", and the formation and evolution of rifts control the sedimentary differentiation of platforms and the similarity of the vertical sourced-reservoer-cap assemblages. Four new models of carbonate sedimentation were established: "multi-type platform margins" and "double shoals" ramp models, carbonate-gypsum/salt symbiotic system model, fault terrace platform margin model of Dengying Formation in Sichuan Basin, and continuously expanding platform margin sedimentary model of Cambrian in Tarim Basin. The "multi-type platform margins" and "double shoals" ramp model reveal that the continental margin and rift margin, depression margin, paleo-uplift of inner ramp and lagoon periphery are favorable mound-shoal development areas. The carbonate-gypsum/salt symbiotic system model reveals that the margin of the paleo-uplift during transgression period is a favorable shoal development area. The fault terrace platform margin sedimentary model indicates that multiple syndepositional fault systems control the formation of step-like platform margins of the 2nd member of Dengying Formation in Sichuan Basin, with thick mound-shoal complexes developed on high fault blocks. The continuous extension platform margin sedimentary model reveals that the Cambrian platform margin belt of Lunnan-Gucheng area in Tarim Basin has undergone the evolution of mud-rich ramp→low-angle progradational ramp/weakly rimmed platform→vertically aggrading platform→laterally prograding rimmed platform. The new understanding of carbonate sedimentary models confirms that the mound-shoal belts around the paleo-rift of the three ancient marine craton basins are still important areas for increasing oil and gas reserves and ensuring resource succession. In addition, new fields such as gravity flow deposits in slope facies and marlstones in evaporative lagoon facies are worthy of exploration. The establishment of the new models of carbonate sedimentation strongly supports the deployment of oil and gas exploration, and also provides a new direction and ideas for future exploration.

The Volga-Urals Basin is a typical foreland basin on the Eastern European Platform, accounting for a significant proportion of global conventional and unconventional oil and gas reserves. However, the understanding of its basin formation and reservoir accumulation remains limited. Through systematic investigation of geological data, the evolution of the basin and its lithofacies paleogeographic characteristics are comprehensively analyzed based on the sedimentary filling features during different Pre-Mesozoic geological periods. The results show that: (1) Under the influence of different tectonic stresses such as tensional stress and compressional stress, the Volga Ural Basin underwent tectonic evolutionary stages of extensional and compressional regimes, developing four prototype basin types/stages: intracontinental rift, passive continental margin, back-arc depression, and back-arc foreland basin. (2) During different tectonic evolution processes, the basin has undergone multiple-cycle changes from terrestrial to marine and back to terrestrial. During the Meso-Neoproterozoic, the basin remained generally stable with sedimentation confined to its eastern region, dominated by terrestrial clastic deposits; in the Early Ordovician, the opening of the Ural Ocean led to a marine transgression across the East European Platform, characterized primarily by shallow marine carbonates; beginning in the Devonian, the basin underwent multiple regressive-transgressive cycles; by the end of the Permian, the entire basin was fully uplifted and subjected to erosion. (3) The basin developed four petroleum systems, with the Domanik Formation serving as the primary source rock. The transitional facies and shallow marine facies developed during the transgressive phase constitute two critical hydrocarbon reservoir units in the basin. Muhanovo-Erohovsk Sag and Kashan-Kama Depression are respectively the key area for unconventional and conventional oil and gas exploration in the future. The research findings provide a critical foundation for the evaluation of overseas oil and gas projects and the implementation of exploration and development practices.

The carbonate platforms that have been widely developed in the South China Sea during the Cenozoic Era not only contain abundant oil and gas resources, but also record important paleo-climate and paleo-environmental information, which are of great scientific significance for understanding the regional tectonic evolution and sedimentary responses of the South China Sea(SCS). Based on the drilling data and high-resolution seismic interpretation, this paper systematically analyzes the spatiotemporal distribution characteristics of the Cenozoic carbonate platforms developed in the South China Sea, and also discusses the synergistic controls of tectonic paleogeography, relative sea-level fluctuations, sediment supply, and paleoclimate on the development and distribution of the carbonate platform under compressional, extensional, and strike-slip tectonic settings, corresponding to the subduction and cessation of the Paleo-South China Sea, the progressive expansion of the Neo-South China Sea, and the strike-slip fault system along the western of the SCS. The research reveals that: (1) Based on the tectonic stress conditions, the Cenozoic carbonate platforms in the SCS can be classified into five major platform groups: the Dongsha platform group in the northern SCS, the Guangle-Xisha platform group along the western margin, the Wan′an-Zengxi slope platform group in the southwestern margin, the Luconia platform in the southern margin, and the Liyue-Palawan platform group in the southeastern margin of the SCS, exhibiting a general pattern of "the southern carbonate platforms developed earlier than the north, the eastern carbonate platforms developed earlier than the west, and most of them mainly developed during the Miocene". (2) Based on regional tectonic settings and ocean-continent position variations, the Cenozoic carbonate platforms in the SCS are classified into three types tectonic settings:compressional, extensional, and strike-slip, under each tectonic setting both shelf-margin platforms and isolated platforms are developed. The distribution of the Cenozoic carbonate platforms in the SCS was primarily controlled by regional tectonic activities and fault systems, terrestrial clastic sediment supply, and relative sea level fluctuations. The tectonic setting and fault systems determine the location and basic types of the platforms, the substantial input of terrigenous clastics from large river-delta systems significantly inhibits the development of shelf-margin carbonate platforms, while exerting limited impact on isolated platforms, and the relative sea-level fluctuations control accommodation space changes, thereby regulating the growth patterns, structural evolution, and spatial distribution of biogenic reefs. This study provides critical theoretical support for deep-water hydrocarbon exploration, global climate change research, and oceanic carbon sequestration.

Fault interpretation is one of the core tasks in oil and gas exploration and development. However, with the increase of exploration scale, traditional artificial fault interpretation and conventional fault detection methods are unable to meet practical needs. Deep learning methods provide an important approach for intelligent seismic fault recognition, among which deep network models represented by Unet have achieved many successful cases in this type of task. However, due to the particularity of convolution operations, this method loses some information in the feature extraction process, resulting in the need for further improvement in the accuracy and robustness of fault recognition. In this paper, we design a CNN-Transformer hybrid module and embed it into the Unet network framework, proposing a hybrid network model based on U-CNNformer. The hybrid network model improves the mining ability of both global features and local details in the sample set, overcomes the limitations of the conventional Unet network in weak information correlation in fault recognition, and improves the robustness of the model while ensuring the accuracy of fault recognition. Testing on the publicly available North Sea F3 data and applying with actual data in a certain area of Sichuan Basin in China demonstrate that the proposed hybrid network model not only accurately detects fault features but also provides a more detailed characterization of fault distribution, achieving high-precision intelligent fault recognition with excellent application effectiveness.

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.

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.

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 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.

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.