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.

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.

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 rocks in ultra-deep layers (burial depth > 6 000 m) of superimposed basins including the Tarim, Sichuan and Ordos basins in western China host massive hydrocarbon resources and represent the key research target of current oil and gas exploration. Carbonate sequences in superimposed basins have experienced multi-phase tectonic movements and multi-stage burial-diagenetic evolution, resulting in complicated formation mechanisms and evolutionary paths of high-quality reservoirs, which restrict the prediction of deep reservoir distribution. Taking Neoproterozoic-Paleozoic carbonate rocks of the Tarim, Sichuan and Ordos basins as the research object, this paper systematically reviews the sedimentary and tectono-thermal geological settings of the three basins. Based on the characteristics of the temperature-pressure field, fluid field, and organic matter maturation, the diagenetic process is divided into four major stages: penecontemporaneous-shallow burial, medium burial, deep to ultra-deep burial, and extra-deep burial, and the differences in diagenetic environments and diagenetic processes of each stage are clarified. Three core mechanisms governing reservoir pore preservation and secondary pore generation are identified, namely penecontemporaneous dolomitization, early hydrocarbon charging coupled with formation overpressure, and multi-phase tectono-hydrothermal activities. Combined with extensive drilling, core observation, and geochemical analysis data, five differentiated reservoir evolutionary paths are classified: non-dolomitized, non-hydrocarbon-charged, tight limestone reservoir pathway; non-dolomitized, early hydrocarbon-charged, porosity-preserved limestone reservoir pathway; penecontemporaneously dolomitized, non- hydrocarbon-charged, continuously porosity-reducing dolomite reservoir pathway; penecontemporaneously dolomitized, early hydrocarbon charged, porosity-preserved dolomite reservoir pathway; late tectono-hydrothermally modified dolomite reservoir pathway. The study reveals that high-energy mound-shoal facies constitute the material basis for reservoir development; diagenetic alterations during shallow to medium burial determine the preservation degree of primary pores; hydrothermal fluids associated with faults only locally improve reservoir properties along fault zones. Furthermore, reservoir development is constrained by stratigraphic architecture and source-reservoir matching relationships. This research improves the multi-stage reservoir-forming theory for ultra-deep carbonate rocks, and can provide theoretical support for quantitative prediction of deep high-quality carbonate reservoirs and favorable play selection for hydrocarbon exploration in superimposed basins of western China.

Targeting the deep to ultra-deep carbonate reservoirs, which are characterized by high temperature and high pressure (HTHP), multi-stage complex tectonic-fluid modifications, and complicated reservoir-formation and accumulation processes, this study has developed a diagenesis-porosity evolution reconstruction technique based on the "Fluid-Time-Temperature-Pressure" (FTtP) framework, and independently designed a visual simulation apparatus for ultra-deep reservoirs under HTHP conditions across multiple tectonic stages. Experimental investigations are conducted from both inversion (backward reconstruction) and forward simulation perspectives, aiming to reveal the genetic mechanisms and distribution patterns of porosity in deep to ultra-deep carbonate reservoirs. Specifically: (1) The FTtP-based diagenesis- porosity evolution reconstruction technique integrates over ten elemental and isotopic geochemical analytical methods, obtaining a suite of high-precision, multi-parameter, in-situ geochemical data. It addresses the critical challenges of constrainting the time, temperature, pressure, and fluid properties of diagenetic products, thereby enabling the reconstruction of the formation processes and preservation mechanisms of porosity in deep to ultra-deep carbonate reservoirs. (2) The visual simulation apparatus integrates multiple functionalities, including ultra-HTHP conditions, multi-cycle internal dissolution, real-time visualization of dissolution processes, and on-line monitoring of permeability and fluid composition. It enables forward simulation experiments of dissolution-precipitation processes across tectonic stages under near-real geological conditions, dynamically reproducing the formation and evolution of pores, and consequently revealing the genetic mechanisms, scales, and distribution patterns of reservoir porosity. The advancement and application of the above technologies have provided critical experimental support for the evaluation and prediction of deep to ultra-deep carbonate reservoirs. In the future, experimental testing techniques will continue to undergo iterative upgrades—elemental and isotopic analyses will evolve from bulk-rock analysis to in-situ micro-texture characterization, from solution-based methods to laser-based techniques, and from laser spot analysis to laser mapping/imaging. Meanwhile, the functionality of simulation apparatus will advance toward integrated modeling of hydrocarbon generation, reservoir formation, and accumulation in ultra-deep settings, continuously providing experimental support for deep petroleum exploration.

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.

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.

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 Wufeng-Longmaxi formations in the Sichuan Basin have substantial deep shale gas resource potential and represent an important frontier for increasing shale gas reserves and production in China. In recent years, continued exploration and development breakthroughs in the Weiyuan-Rongxian, Luzhou, Yongchuan, Qijiang, Baima, and other areas have advanced deep shale gas exploration and development from initial single-well exploration to breakthroughs across multiple areas and large-scale production capacity development. However, exploration results reveal substantial differences in deep shale gas enrichment and single-well productivity among structural units, with high- and low-productivity wells coexisting, indicating the complexity of the factors controlling enrichment. Based on a systematic review of progress in deep shale gas exploration and development in the Longmaxi Formation of the Sichuan Basin, together with the geological characteristics of representative high- and low-productivity wells, this study synthesizes enrichment types, major controlling factors, and approaches to exploration evaluation. The results indicate that deep shale gas in the Longmaxi Formation of the Sichuan Basin can be classified into three types: overpressure-enriched, normally pressured enriched, and tectonically modified depleted types. The overpressure-enriched type is jointly controlled by hydrocarbon-generation-induced pressurization and favorable preservation conditions and currently constitutes the dominant type for large-scale production capacity development. The normally pressured enriched type demonstrates that effective enrichment can occur even after partial pressure dissipation where high-quality shale is sufficiently thick, the proportion of adsorbed gas is high, and some capacity for gas preservation remains. The tectonically modified depleted type occurs mainly in the cores of high-steep anticlines and areas affected by multiple phases of faulting and reactivation and is characterized by low pressure coefficients, low gas content, high water saturation, low resistivity, and low productivity. Differential enrichment of deep shale gas is primarily controlled by the intensity of hydrocarbon generation and expulsion from shale and by subsequent preservation conditions. High-quality shale provides the material basis for hydrocarbon generation, and hydrocarbon-generation-induced pressurization drives enrichment, whereas the intensity of subsequent tectonic modification, fault opening behavior, uplift-related pressure dissipation, and their temporal relationships with hydrocarbon generation and expulsion ultimately determine the extent of gas preservation. The evaluation of deep and ultra-deep shale gas should shift from static indicator-based assessment to the assessment of preservation conditions based on dynamic evolution, prioritizing favorable zones with abundant residual hydrocarbons in shale, well-preserved pressure systems, limited fault-related damage, and relatively broad and gentle structures.

The source rock strata in the northern Guizhou-southern Sichuan area are widely distributed, indicating significant potential for intra-source unconventional natural gas exploration. Accelerating the exploration and development of these intra-source unconventional gas resources has become a key pathway to ensure regional energy security and optimize the energy supply structure. Controlled by multi-stage tectonic evolution, the Paleozoic marine strata in this area have complex geological conditions, necessitating the urgent development of exploration and development theories and technical systems that are tailored to local geological characteristics. Through extensive field practice in the complex structural zone of northern Guizhou-southern Sichuan, spanning from basin margin to basin interior, commercial breakthroughs in shale gas, coalbed methane, and calcareous source rock gas have been achieved successively. Based on these efforts, the concept of "intra-source unconventional exploration" targeting multiple types of source rocks, including shale, coal, and limestone, has been proposed. Furthermore, several enrichment and accumulation models have been established, including the "three-dimensional sealing system" for mountainous shallow shale gas, the "residual broad and gentle syncline" and "secondary low-amplitude anticline within a composite syncline" models for shallow coalbed methane, the "thrust fault sealing in the narrow and steep anticline limb-continuous distribution in broad and gentle syncline" model for deep shale gas, and the "predominantly source-reservoir integrated with subordinate local structural migration and enrichment" model for calcareous source rock gas. This paper systematically reviews the exploration progress, accumulation theories, and future prospects of marine shale gas, coalbed methane, and calcareous source rock gas in the northern Guizhou-southern Sichuan region, aiming to provide scientific basis and technical support for large-scale and cost-effective development of multiple types of unconventional gas resources, thereby contributing to national energy security and driving continuous innovation in petroleum geology theories and exploration and development technologies.

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.

Since 2021, 9.35 billion TOE of recoverable oil and gas reserves have been discovered worldwide, with 78.2% coming from marine sedimentary reservoirs, and there are 20 large marine oil and gas fields with recoverable reserves exceeding 5×10⁸ BOE, mainly consisting of deep-water gravity flow sandstone reservoirs, followed by carbonate rock reservoirs. Unlike the previous period when shallow marine carbonate reservoirs mainly contributed to reserves, four typical characteristics define these marine oil and gas exploration discoveries: (1) the basin types where marine oil and gas reservoirs have been discovered are primarily passive continental margins, accounting for 56.0% of reserves; (2) marine clastic rock reservoirs hold the largest controlled reserves (62.0%), with deep-water gravity flow sandstone reservoirs accounting for over 80%; (3) lithological and stratigraphic traps related to deep-water gravity flow control the largest share of reserves at 39.2%, followed by structural traps at 33.3%; and (4) marine clastic reservoirs exhibit favorable porosity and permeability, whereas carbonate reservoirs display strong heterogeneity. By analyzing the characteristics and exploration processes of four typical types of large marine oil and gas reservoirs, including deep-water gravity flow sandstones in Southwest Africa, restricted marine carbonate rocks in the Santos Basin, tight limestones in the Middle East, and biogenic reef-shoal in the Mid-Atlantic, it is emphasized that future marine oil and gas exploration should focus on three major areas: (1) deep-water gravity flow sandstone, with emphasis on eight basin groups locating offshore Southeast and Northeast South America, Northwest Africa, the Gulf of Guinea, Southwest Africa, Mozambique, Somalia, and the Bay of Bengal; (2) shallow marine reef-shoal carbonate rocks, including constructions such as those around the South China Sea rim and East Java in Southeast Asia, as well as isolated volcanic island reefs in the southern Caribbean Sea; (3) tight limestone and marine sandstone reservoirs in the Middle East, primarily within the Cretaceous and Jurassic formations of the Arabian and Zagros basins.

Deepwater regions, as strategic successors to global onshore and shallow-water oil and gas resources, have an exploration maturity of merely 16.8%, with immense remaining resource potential, positioning them as core domains for global reserve and production growth and strategic energy competition. Since the 1970s, global deepwater oil and gas exploration and development has progressed through five major stages: initial exploration, early breakthroughs, rapid development, vigorous expansion, and steady development under complex circumstances. In recent years, a series of breakthroughs have been achieved in deepwater petroleum geology and development engineering technologies, yielding theoretical innovations in deepwater submarine fan lithologic reservoirs, deepwater pre-salt lacustrine carbonate reservoirs, deepwater biogas accumulations, and ultra-deepwater ultra-shallow gas accumulations. Key technological systems have also been established, including deepwater OBN seismic exploration, fine characterization of complex reservoirs in deepwater oil and gas fields, safe and efficient deepwater drilling and completion, and all-sea mode deepwater development engineering, which have strongly supported major exploration discoveries and efficient development in deepwater basins worldwide. To address major strategic national demands in deepwater operations, domestic oil companies must take scientific and technological innovation as the core driver, continuously advancing research on global deepwater hydrocarbon enrichment theories, efficient deepwater field development technologies, and all-sea mode engineering techniques, and establishing an integrated technical system covering the entire business chain of deepwater exploration, development, engineering, and operations management. This will facilitate the transition of deepwater oil and gas operations from follower-style development to independent innovation and leading operations, providing theoretical support and technical reserves for the efficient exploration and development of China's deepwater resources and national energy security.

The classification of volcanic edifices is an important foundation for establishing the relationship between volcanic edifices and reservoirs. By systematically reviewing the definitions and connotations of various classification schemes, and integrating the influences of different volcanic edifice types on porosity-permeability characteristics, this study explores a classification scheme suitable for reservoir research. The following insights are obtained: (1) Volcanic edifice types are primarily classified based on three factors: morphology, lithology, and stratigraphic architecture. Among these, schemes based on lithology yield numerous types but show poor correspondence with reservoirs, whereas schemes based on stratigraphic architecture yield fewer types but demonstrate good correspondence with reservoirs. (2) Reservoir physical properties, in order from best to poorest, are successively layered-like, layered, massive-layered-like, and massive volcanic edifices. (3) In the early exploration stage, it is recommended to adopt the classification scheme based on stratigraphic architecture, as it facilitates the identification of favorable reservoir distribution by using seismic data. In the mid-late exploration stage or during the reservoir evaluation and development stage, classification can take both lithology and superimposed relationships into account. These findings provide a theoretical basis and practical reference for the efficient exploration of volcanic hydrocarbon reservoirs.