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 largescale 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.

Carbonate rocks in Africa are characterized by extensive distribution along continental margins and scattered occurrences in the continent. Carbonate rocks are primarily distributed in rift basins and continental margin rift basins along the Tethyan margin of North Africa. Due to widespread marine transgressions during the Cretaceous and Cenozoic, North Africa remained in a passive margin or epeiric sea environment, in favor of extensive carbonate deposition. They also occur in passive continental margin basins of West and East Africa, although with limited continuity and thickness due to narrow continental shelves and high fluvial input. Scattered carbonate deposits are found within intraplate rifts and ancient cratonic basins, which are dominated by mixed clastic-carbonate sedimentation. Carbonate rocks are concentrated in the Cretaceous and Cenozoic, with localized occurrences in the Jurassic, and extremely limited prior to the Paleozoic. The accumulation conditions in African carbonate basins can be classified into three types: (1) The Sirte Basin and Pelagian Basin have vertical stacking of mudstones, carbonates, and evaporites due to multiple cycles of rifting, inversion, and sea-level fluctuations, indicating excellent petroleum systems in the Cretaceous and Cenozoic sequences. (2) The Kwanza Basin and Lower Congo Basin of West Africa have petroleum assemblage of lacustrine source rocks, lacustrine carbonates, and overlying evaporite seals, in addition, reservoirs with underlying lacustrine source rocks, overlying marine carbonates and mudstones developed. (3) The Eratosthenes isolated platform generated biogenic reef due to the inherited paleo-uplifts and suitable sea levels. There has an appropriate hydrocarbon system of Upper Cretaceous deep-sea source rocks, reef carbonate reservoirs, and Miocene evaporite seals.of reservoirs affects pore development, distribution and reservoir quality. Relevant studies on the Middle Triassic Leikoupo Formation in central Western Sichuan Basin are still blank. In order to reveal the diagenetic evolution characteristics of dolomite reservoirs in the study area and their influence on reservoir quality, and to provide a theoretical basis for the exploration of carbonate oil and gas, the study on the dolomite diagenesis of Leikou Formation in western Sichuan Basin is systematically analyzed on the basis of data analysis such as core and thin section observations, dolomite order degree analysis, fluid inclusions and carbon-oxygen stable isotope tests. The results show that: (1) The Leikoupo Formation in central Western Sichuan mainly develops two different types of dolomite: micritic dolomite and micritic algal clast dolomite. The low degree of ordering and low formation temperature of the dolomite crystals indicate that they were formed by penecontemporaneous dolomitization. The reservoir spaces mainly consist of dissolved pores developed along algal frameworks, intergranular pores, and tectonic breccia interstices. (2) The dolomite in the study area has mainly undergone diagenetic processes such as fracturing, dolomitization, dedolomitization, dissolution, micritization, cementation, and surface-induced demineralization. Among them, structural fracture and dissolution play an improving role in the physical properties of the reservoir. Deep dissolution is the fundamental factor for the development of deep secondary pores. (3) The correlation between the development characteristics of dissolution pores and structural breccia and structural fractures is confirmed: acidic fluids were injected along the fracture space into the remaining pore development areas such as sandy shoal and the framework of the algal layer to form secondary dissolution pores in the late Indosinian stage. Vertical fissures and late structural breccia were formed in the early stage of the Himalayan Movement, and late dissolution and calcite vein filling occurred. Horizontal fractures formed in the late Himalayan period, further improving the physical properties of the reservoir. The research has for the first time clarified the diagenetic sequence and pore evolution model of the dolomite reservoir of the Leikoupo Formation in central Western Sichuan Basin, and proposes a three-stage reservoir control mechanism of "structural fracture-fluid dissolution-fracture modification", providing new geological basis for the exploration of the Leikoupo Formation

Large carbonate hydrocarbon fields have long been a global research focus. Statistical analysis of HIS 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.

Kwanza Basin, located in Angola and its adjacent offshore area along the West African coast, is a typical passive continental margin salt-bearing basin. It comprises three major structural layers: pre-salt structural layer, salt structural layer, and suprasalt structural layer. The pre-salt Cretaceous lacustrine carbonate rocks represent the primary target for hydrocarbon exploration in the basin. The pre-salt structural layer exhibits a tectonic pattern of alternating depressions and uplifts, which can be divided into the Inner Rift Zone, Central Uplift Zone, and Outer Rift Zone from east to west. The hydrocarbon accumulation mechanism in pre-salt lacustrine carbonate rocks is characterized by "riftcontrolled source rocks, uplift-controlled reservoirs, salt-controlled seals, and high-quality reservoirs controlling accumulation". The Central Uplift Zone, with well-developed basement uplifts, not only facilitates trap formation and carbonate reservoir development but also serves as the migration pathway for hydrocarbons, making it the most favorable area for pre-salt Cretaceous carbonate reservoir accumulation. The presence of high-quality reservoirs is critical for successful exploration. Based on newly acquired seismic and drilling data, this study investigates the factors influencing the differential distribution of pre-salt lacustrine carbonate reservoirs. The analysis further narrows down the prospective exploration areas for subsalt hydrocarbon plays in the Kwanza Basin to the northern part of the Central Uplift Zone, providing guidance for regional evaluation and exploration target selection.

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.

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 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 intraplatform shoals. Based on the high-frequency sequence division technology of INPEFA and wavelet transform, the highfrequency 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 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 paleouplift 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.

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 XuanhanWanzhou 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 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 paleouplifts, basin margins and slope breaks. (3) Based on comprehensive analysis of tectonic-sedimentary framework, sourcereservoir 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 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 PaleoSouth 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.

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 sourcereservoir-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 atthe range of(100-200) × 10-3μm2. 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