The oil and gas exploration has been going ahead towards deeper and older marine ultra-deep strata in China. The depth of exploration wells has exceeded 8000 m in the Sichuan Basin and the Tarim Basin, and exceeded 5000 m in the Ordos Basin despite small buried depth. However, there are no consensus in China and abroad regarding the depth limit and geological connotation of ultra-deep strata^{[1,2,3,4,5,6,7,8]}. Controlled by the multi-cycle tectonic evolution of the Chinese mainland, the superimposed basins consisting of three sets of structural layers (Precambrian-Lower Paleozoic, Upper Paleozoic, and Meso-Cenozoic) are commonly developed in the central and western regions. Specifically, the Precambrian-Lower Paleozoic lies at the bottom of the superimposed basin and is marine deposit with a large burial depth, falling in the category of ultra-deep strata. This paper holds that marine ultra-deep strata are defined comprehensively by two factors: buried depth and geological age, that is, the Precambrian-Lower Paleozoic ancient marine strata with a burial depth greater than 6000 m. In China, many large oil and gas fields have been discovered in ultra-deep strata, such as Anyue in the Sichuan Basin, and Halahatang and Shunbei in the Tarim Basin. The prospects and strategic position of marine ultra-deep strata become greatly attractive^{[2, 9-11]}. However, these old ultra-deep strata with large burial depth have experienced extremely complex process of hydrocarbon accumulation and evolution after transformation in multiple periods of structural movements. Based on the latest research results, we analyze the oil and gas geological conditions of marine ultra-deep strata in three major cratonic basins (Sichuan, Tarim and Ordos) in China, and then dissect especially the Sinian-Cambrian in the Central Sichuan Basin (abbreviated as Central Sichuan) and the Cambrian-Ordovician in the northern part of Tarim Basin (abbreviated as North Tarim), to expound the accumulation and evolution process of marine ultra-deep oil and gas and the major controlling factors for hydrocarbon enrichment, and propose the favorable direction of China’s marine ultra-deep oil and gas exploration.

China’s ultra-deep oil and gas resources differ greatly in the distribution strata, types of reservoirs, and occurrence of structural background from the deep to ultra-deep oil and gas discovered in the rest of the world.

Globally, 66% of the discovered deep to ultra-deep oil and gas reserves are distributed in the Jurassic-Neogene, and only 10% or less in the Precambrian and Lower Paleozoic, with the reservoirs dominated by clastic rocks; 94% of the reserves are concentrated in passive marginal basins and foreland basins on the margins of cratons^[5]. In China, ultra-deep oil and gas are mainly distributed in the Precambrian and Lower Paleozoic. The reservoirs are dominated by marine carbonate rocks, and hydrocarbons occur in the structural environments such as intracratonic rifts and intracratonic depressions.

The global supercontinent breakup-convergence cycles controlled the evolution of marine sedimentary basins in China, forming multi-stage cratonic rift and depression basins, which provide an important structural background for the formation of ultra-deep oil and gas geological conditions (Fig. 1). In the Early Mesoproterozoic (1.6-1.8 Ga), the North China Craton suffered a regional rifting caused by the disintegration of the Columbia supercontinent, giving rise to six major rifts, i.e. Xiong’er (Henan-Shaanxi) rift in the southern margin, Zhaertai-Bayan Obo-Huade rift in the northern margin, Shanxi- Shaanxi rift and Gansu-Shaanxi rift in the west, Yanliao rift in the center, and the rift in the eastern margin^[12]. These rifts controlled the distribution of source rocks in the Changcheng System. In the Middle-Late Mesoproterozoic (1.0-1.6 Ga), the rifts in North China Craton rift evolved into depressions, which controlled the distribution of source rocks in the Gaoyuzhuang Formation and Hongshuizhuang Formation of Jixian System and the Xiamaling Formation of Daijian System. In the Neoproterozoic, affected by the breakup of the Rodinia supercontinent, inherited rifts developed on the basis of the original Mesoproterozoic rifts on the south and north sides of the North China Craton, while the Ordos Block in the western part of the North China Craton showed a hiatus of Neoproterozoic sediments. The rifting occurred in the Yangtze Craton in the Early Neoproterozoic (820 Ma), forming three rifts, i.e. Hunan-Guangxi rift in the eastern margin, Kangding-Yunnan rift in the western margin, and the rift in the northern margin^[13], which controlled the distribution of the Nanhua-Sinian (Cryogenian-Ediacaran) source rocks. In the Late Sinian-Early Cambrian, the Deyang-Anyue rift was developed in the Central Sichuan, which controlled the distribution of high-quality source rocks in the Cambrian Qiongzhusi Formation. The Tarim Craton experienced rifting in the Neoproterozoic (740-780 Ma), and showed the development of two major rifts in the north and southwest of the Tarim, i.e. North Tarim rift and SW Tarim rift^[10]. We discovered high-quality source rocks in the Nanhua System and Sinian System through the field survey in Kuruktag, northeastern Tarim Basin, indicating that the North Tarim rift controlled the distribution of source rocks. In the Early Paleozoic, the rifting of the North China, Yangtze and Tarim Cratons basically ended, and they entered the plate drifting, agglomeration and assembly evolution cycle^[14]. During the period, the craton structural differentiation led to the intracratonic and marginal depressions, which controlled the distribution of Early Paleozoic source rocks.

Multi-stage structural cycles of the three large cratons controlled the sedimentary evolution and differences of marine strata. In the Precambrian and Paleozoic, marine intracratonic rifts and intracratonic depression basins were mainly developed. In the Mesozoic, the continental basins were mainly evolved and superimposed with foreland basin. Superimposition of different types of basins formed very thick sedimentary caprocks, making the Precambrian-Lower Paleozoic deeply buried generally. In the Sichuan Basin and the Tarim Basin, except for paleo-uplifts, the Precambrian-Lower Paleozoic strata are generally deeper than 6000 m, with marine ultra-deep strata of about 10×10⁴ km² and 21.5×10⁴ km², respectively. In the Ordos Basin, the Precambrian-Lower Paleozoic strata are generally shallow (<4000 m), except for the western margin, with marine ultra-deep strata of about 1.5×10⁴ km².

The multi-cyclic evolution of China’s marine cratonic rifts and depressions provides favorable conditions for the development of source rocks, which are distributed from the Meso-Neoproterozoic to Paleozoic, laying material foundation for ultra-deep oil and gas generation. The major source rocks control the distribution of oil and gas resources and the formation of large oil and gas fields (Fig. 2). Comparison reveals that the Sichuan Basin has the most layers of ultra-deep source rocks, followed by the Tarim Basin, while the scale of marine source rocks in the Ordos Basin needs to be confirmed.

In the Sichuan Basin, there developed multiple sets of ultra-deep source rocks: Nanhua Datangpo Formation, Sinian Doushantuo Formation and third member of the Dengying Formation (Deng 3 Member), Lower Cambrian Qiongzhusi Formation, and Lower Silurian Longmaxi Formation (Fig. 2), which are mainly organic-rich marine shales. The source rocks of the Qiongzhusi Formation, with a thickness of 100-450 m and an average TOC of 2.2%, are widely distributed in the Sichuan Basin and its periphery. With the hydrocarbon generation center in the Deyang-Anyue rift, it is the major gas source of the Anyue gas field in Central Sichuan. The source rocks of the Longmaxi Formation, 50-700 m thick, are mainly distributed in eastern Sichuan, southern Sichuan, and western Hunan-Hubei, and pinch out towards the central Sichuan paleo-uplift, with an average TOC of 2.52%. It is the primary gas source in the Carboniferous gas fields in eastern Sichuan, and also the major pay zone of marine shale gas. The black argillaceous source rocks of the Dalong Formation, about 10-30 m thick, with an average TOC of 4.5%, are distributed in the Kaijiang-Liangping Trough. The distribution of source rocks in the Nanhua System Datangpo Formation and the Sinian Doushantuo Formation and Deng 3 Member is evidently controlled by cratonic rifts, but it is still unclear inside the Sichuan Basin. The source rocks of the Datangpo Formation are found in the Hunan-Guangxi rift in the eastern margin of the Yangtze Craton, and contain black manganese-bearing carbonaceous shale, with TOC of 1.3%-6.4% and the maximum thickness of nearly 50 m. The black shale of the Doushantuo Formation is distributed under the control of the Hunan-Guangxi rift in the eastern margin and the rift in the northern margin, with TOC of 0.9%-4.7% and the maximum thickness of nearly 80 m. It may be an important set of source rocks in eastern and northern Sichuan. The black shale intercalated by thin-layered gray dolomitic mudstone in the Deng 3 Member is mainly distributed in the northern Deyang-Anyue rift, with a thickness of 5-30 m and TOC of 0.04%-4.73% (averaging 0.65%), showing certain contribution to the Anyue gas field in central Sichuan.

In the Tarim Basin, there are multiple sets of ultra-deep source rocks, such as Nanhua, Sinian, Middle-Lower Cambrian, and Middle-Lower Ordovician (Fig. 2). Specifically, the Lower Cambrian Yuertus Formation, highly recognized as the primary source rocks, is widely distributed in the northern depression and the North Tarim area. The black shale in the lower part is 6-25 m thick, with TOC of 1.9%-26.1% (averaging 8.9%). The source rocks in the Manjiaer sag in the eastern part of the basin are different from those in the North Tarim area in three aspects. First, there are more source rocks from the Cambrian to the Ordovician, mainly including three sets, namely, the Lower Cambrian Xishanbulak Formation- Xidashan Formation, the Middle Cambrian Mohershan Formation, and the Middle-Lower Ordovician Heituao Formation. Second, the source rocks are well inherited, with their distribution mainly controlled by the Manjiaer sag. Third, the abundance of organic matters is generally lower than that of the Yuertus Formation in the North Tarim area. Typically, the TOC value is 0.05%-8.4% for the Xishanbulak Formation-Xidashan Formation, 0.7%- 2.4% for the Mohershan Formation, and 0.6%-3.6% for the Heituao Formation. The distribution of Nanhua and Sinian source rocks is controlled by the Neoproterozoic cratonic rifts, and has been lowly explored. We measured the samples from the South Yardang Mountain section in Kuruktag, northeastern Tarm Basin. It is found that the Nanhua Tereeken Formation source rocks have the apparent thickness of about 320 m and TOC of 1.0%-2.6%; the Sinian Zhamoketi Formation source rocks are about 50 m thick, with TOC of 0.27%-1.93%; the Shuiquan Formation source rocks are about 60 m thick, with TOC of 0.92%-1.75%. All three sets are effective source rocks.

In the Ordos Basin, there are many sets of source rocks in the periphery, such as the Changcheng Cuizhuang Formation, the Upper Sinian Dongpo Formation, the Lower Cambrian Sandaozhuang Formation, and the Middle- Upper Ordovician Wulalike Formation (the lower Pingliang Formation). The development of these source rocks inside the basin needs to be confirmed. The black shale in the Changcheng Cuizhuang Formation is 100-500 m thick, with TOC of 0.2%-1.6% (averaging 0.62%), and its distribution is controlled by the Gansu-Shaanxi and Shanxi-Shaanxi rifts. This set of source rocks is inferred to develop inside the basin. The Upper Sinian Dongpo Formation-Lower Cambrian Sandaozhuang Formation source rocks have been discovered in the southern and western margins of the basin, being black shale with a thickness of 20-80 m. In the southern margin of the basin, the TOC values of the Dongpo Formation and the Sandaozhuang Formation are 1.5%-9.8% (averaging 1.65%) and 1.8%-9.4% (averaging 3.64%), respectively. In the western margin, only the black slate of the Sinian Dongpo Formation has been discovered, with a thickness of 2-5 m and TOC of 0.30%-1.15% (averaging 0.54%), and its distribution and hydrocarbon generation potential need to be further evaluated. The Middle-Upper Ordovician Wulalike Formation is mainly distributed along the western and southern margins of the basin, which is gray-black mudstone, with a thickness of 30-60 m and TOC of 0.21%-1.60% (averaging 0.67%).

China’s marine ultra-deep reservoirs are dominated by carbonate rocks, which have undergone the superimposition of multi-stage and multi-type geological processes^[15]. The sedimentary environment controlled the development of reservoir pores in the early stage, and coupled with dissolution and fracturing in the late stage to further improve the reservoir properties^[3]. There are mainly porous reservoirs, fractured-vuggy reservoirs, and caved reservoirs, etc., which provide favorable storage conditions for marine ultra-deep oil and gas. Carbonate reservoirs are extensively developed in the Sinian-Lower Paleozoic of both the Sichuan and Tarim basins, but only in the Lower Paleozoic of the Ordos Basin. Generally, the reservoirs are dominantly porous and vuggy dolomite reservoirs in the Sichuan Basin, and porous dolomite and fractured-vuggy limestone reservoirs in the Tarim Basin and Ordos Basin. In the Sichuan Basin, the ultra-deep large-scale carbonate reservoirs are mainly distributed in the Sinian and Cambrian. The Sinian mainly includes two sets of reservoirs: Deng 2 Member and Deng 4 Member, which are dominantly fractured-vuggy reservoirs. The reservoirs of Deng 2 Member are 20-260 m thick, with the porosity of 2.0%-7.8% (averaging 3.5%). The reservoirs of Deng 4 Member are 25-170 m thick, with the porosity of 2.0%-7.1% (averaging 3.3%). High-quality reservoirs are mainly distributed in the platform margin belts on both sides of the Deyang-Anyue rift, and are jointly controlled by platform margin mound-shoal complex and karstification. The reservoir conditions inside the platform are worse. The Cambrian mainly includes three sets of dolomite reservoirs, i.e. Canglangpu Formation, Longwangmiao Formation, and Xixiangchi Formation. Their distribution is controlled by high-energy grain shoal facies, coupling with karstification. The Longwangmiao Formation is the primary reservoir in the Anyue gas field, with the thickness of 5-60 m and the porosity of 2.0%-18.5% (averaging 4.8%). In the Western and Northern Sichuan regions, ultra-deep reservoirs also include the Middle Permian Qixia Formation and Maokou Formation, the Upper Permian Changxing Formation, and the Lower Triassic Feixianguan Formation. The Maokou Formation is represented by fractured-vuggy limestone reservoirs, while the other formations are mainly dolomite reservoirs controlled by reef-shoal facies, showing good storage conditions.

In the Tarim Basin, ultra-deep large-scale carbonate reservoirs are mainly endowed in the Sinian, Cambrian, and Ordovician, and dominantly vuggy dolomite reservoirs and karst fractured-vuggy limestone reservoirs. The Qigebulake Formation dolomite reservoirs in the upper part of the Sinian are controlled by high-energy grain shoal facies, coupling with karstification, and dominantly vuggy reservoirs, with the thickness of 15-102 m and the porosity of 3.8%-7.2% (averaging 5.2%). The Cambrian has dolomite reservoirs in the Xiaoerbulak Formation, Wusonggeer Formation, and Shayilik Formation. The Xiaoerbulak Formation reservoirs are controlled by gentle slope mound-shoal facies and high-energy grain shoal facies, and mainly vuggy reservoirs, with the thickness of 30-75 m and the porosity of 1.9%-12.5% (averaging 4.9%). The Wusonggeer Formation and the Shayilik Formation reservoirs are controlled by weakly-rimmed to rimmed carbonate platforms. They are mainly vuggy and fractured-vuggy reservoirs of platform margin reef-shoal and intra-platform shoal facies. The Wusonggeer Formation reservoirs are 12-51 m thick, with a porosity of 1.2%-4.3% (averaging 3.3%). The reservoirs of the Shayilik Formation are 10-56 m thick, with the porosity of 3.4%-5.2% (averaging 4.4%). The Ordovician shows the karst fractured-vuggy limestone reservoirs in the Yingshan Formation, Yijianfang Formation, and Lianglitage Formation. Jointly controlled by karstification and strike-slip faults, these reservoirs are widely distributed in North Tarim, Central Tarim, Gucheng and the Maigaiti Slope, serving as the primary reservoirs of such large oil and gas fields as Tahe, Shunbei, Halahatang, and Central Tarim No.1.

In the Ordos Basin, ultra-deep reservoirs are mainly distributed in the Cambrian and Ordovician, and dominantly oolitic beach dolomite and karst fractured-vuggy limestone reservoirs. The Cambrian Zhangxia Formation oolitic beach dolomite reservoirs are extensively distributed in the region, with the thickness of 20-100 m and the porosity of 2.5%-7.5% (averaging 4.3%). The Ordovician Cremori Formation is mainly distributed in the “L”-shaped platform margin on the western edge of the basin. It is a karst fractured-vuggy limestone reservoir with the thickness of 0.8-50.0 m and the porosity of 2.5%-15.0% (averaging 3.5%).

Three types of regional caprocks, gypsum salt rock, shale rock and tight carbonate rock, are developed in ultra-deep marine strata of China. The gypsum salt and tight carbonate caprocks are mainly distributed in the Lower Paleozoic Cambrian-Ordovician, and the marine shale caprocks are distributed in the Lower Paleozoic-Precambrian, which is adjacent to the underlying ultra-deep high-quality reservoirs, providing favorable conditions for ultra-deep oil and gas accumulation and preservation. In the Sichuan Basin, there are five sets of regional caprocks, i.e. the Cambrian Qiongzhusi Formation shale and Gaotai Formation gypsum salt, the Lower Silurian Longmaxi Formation shale, the Upper Permian Longtan Formation mudstone, and the Middle-Lower Triassic Jialingjiang Formation-Leikoupo Formation gypsum salt. The Qiongzhusi Formation and Gaotai Formation, with large thickness and wide distribution, are important regional caprocks for marine ultra-deep oil and gas in the Sichuan Basin. The Qiongzhusi Formation shale is 100-350 m thick and distributed throughout the basin, showing the largest thickness in the Deyang-Anyue rift. The Gaotai Formation gypsum-salt rocks are mainly distributed in eastern Sichuan (200-400 m, or up to 600 m) and central Sichuan (mainly gypsum dolomite, with a cumulative thickness of 40-50 m). The Longmaxi Formation black shale is widely developed in southern and eastern Sichuan, with the thickness of 50-700 m (averaging 120 m). The Longtan Formation is distributed throughout the basin, mainly including marine mudstone in the northeastern Sichuan region and marine-continental transitional mudstone in the central Sichuan- southern Sichuan region, with the cumulative thickness of 30-140 m. The Middle-Lower Triassic Jialingjiang Formation-Leikoupo Formation contains thick gypsum salt rocks, which are widespread in the basin, and apparently thick in the western and eastern Sichuan regions, with the cumulative thickness of 100-400 m. It is also an important regional caprock in the ultra-deep marine strata in the Sichuan Basin.

In the Tarim Basin, there are mainly four sets of ultra- deep regional caprocks, i.e. the Lower Cambrian Yuertus Formation shale, the Middle Cambrian Awatag Formation and Shayilik Formation gypsum salt rocks, the Middle- Lower Ordovician tight carbonate rocks, the Upper Ordovician Tumuxiuke Formation marlstone and Sangtamu Formation mudstone. The Yuertus Formation shale is the most widely distributed in the basin, with the area of 28×10⁴ km² and the thickness of 20-180 m; it is the primary regional caprock of the Sinian System. The Middle-Lower Cambrian gypsum-salt rocks are mainly distributed in the Maigaiti Slope, Bachu Uplift, Awati Sag and the western part of Central Tarim and North Tarim, with the thickness of 0-360 m, serving as the primary regional caprocks of the Lower Cambrian. The Middle-Lower Ordovician tight carbonate rocks, Upper Ordovician Tumuxiuke Formation marlstone and Sangtamu Formation mudstone are mainly distributed in the platform basin zones in the central and western parts of the basin, and the latter is the primary regional caprock of the Ordovician.

In the Ordos Basin, the caprocks are mainly distributed in the Cambrian and Ordovician, including tight limestone and marine shale. The Middle-Lower Cambrian Maozhuang Formation and Xuzhuang Formation develop neritic marlstone, limestone, micrite limestone and other tight carbonate rocks, with large thickness (up to 300 m) in the southwest and smaller thickness (about 37-50 m) in the northeast. The Ordovician Wulalike Formation shale is mainly distributed in the western margin of the basin and can be the direct caprock of deep gas reservoirs.

By the end of 2018, China has discovered 8 large marine ultra-deep oil and gas fields, which are mainly distributed in the Tarim Basin and the Sichuan Basin, with proven condensate oil reserves of 19.6×10⁸ t and proven natural gas reserves of 2.4×10¹² m³ (Table 1). Limited by the extent of exploration, no ultra-deep marine oil and gas fields have been discovered in the Ordos Basin. The basic characteristics of ultra-deep oil and gas fields can be summarized as follows:

(1) The hydrocarbon-bearing strata are dominantly Ordovician, Cambrian, and Sinian, and occasionally Permian and Triassic (e.g. Longgang, Puguang, and Yuanba gas fields in northern Sichuan).

(2) The reservoirs are diverse in types and dominantly lithologic-stratigraphic (typically in Tarim Basin) and structural-lithologic reservoirs (typically in the Sichuan Basin).

(3) The reservoirs contain both limestone and dolomite. In the Tarim Basin, limestone is dominant, and the storage space is composed of caves, fractures and vugs. In the Sichuan Basin, dolomite is dominant, and the storage space is composed of pores and vugs.

(4) The reservoirs show great variation of thickness and strong heterogeneity. Generally, the physical properties of dolomite are better than that of limestone.

(5) Structurally, the reservoirs are mainly distributed in the periphery of cratonic depressions and cratonic rifts (including troughs). In the Tarim Basin, marine ultra-deep oil and gas reservoirs are mainly distributed in the periphery of the Manxi intracratonic depression. In the Sichuan Basin, marine ultra-deep gas reservoirs are mainly distributed in the periphery of the Deyang-Anyue intracratonic rift and Kaijiang-Liangping trough.

The Sinian-Cambrian in the Anyue gas field in the Sichuan Basin (the periphery of Deyang-Anyue intracratonic rift) are taken as an example to discuss the oil and gas sources, hydrocarbon charging stages, and hydrocarbon accumulation and evolution process, and to identify the primary controlling factors for hydrocarbon accumulation.

The Sinian-Cambrian natural gas exploration in central Sichuan has a long history. Over years of efforts after the discovery of the Weiyuan gas field in 1964, Well Gaoshi 1 in 2011 and Well Moxi 8 in 2012 obtained daily production of more than million cubic meters from the Dengying Formation and the Longwangmiao Formation, respectively, which contributed the discovery of the Anyue super-large gas field^[16]. The Anyue gas field is located in the Gaoshiti-Moxi structure of the Central Sichuan paleo-uplift, with the Deyang-Anyue intracratonic rift to the west. The main gas layers are the Cambrian Longwangmiao Formation and Sinian Dengying Formation, with a buried depth of 4500-5400 m. The gas- bearing range is controlled by both structure and lithology, and the cumulative proven geological reserves exceed 1×10¹² m^3[17]. Recently, new exploration discoveries have been made in the northern slope of the Central Sichuan paleo-uplift and the Deng 2 Member in the rift ^[18], showing a good exploration prospect in the periphery of the Deyang-Anyue intracratonic rift.

3.2.1. Oil and gas sources

Previous studies have found that the natural gas in the Anyue gas field is crude oil cracked gas^[19], but there are differences in the understanding of the gas sources of the Dengying Formation and the Longwangmiao Formation. Some scholars indicated that the gas of both Dengying Formation and Longwangmiao Formation was derived from the source rocks of the Qiongzhusi Formation^[20]. Other scholars held that the gas of the Dengying Formation was sourced from the Qiongzhusi Formation and the Deng 3 Member, while the gas of the Longwangmiao Formation came from the Qiongzhusi Formation^[16]. Some studies also proposed that the natural gas of both Dengying Formation and Longwangmiao Formation was a mixed gas sourced from the Qiongzhusi Formation and Dengying Formation^[21].

For overmature natural gas, with relatively monotonous component, there are no geochemical indicators that can be directly compared between natural gas and source rocks, making the gas source correlation very difficult. We used the multi-parameter method for comprehensive analysis based on both geologic and geochemical data. The results suggest that the natural gas in the Anyue gas field is mainly derived from the Lower Cambrian Qiongzhusi Formation, and partially from the Deng 3 Member, which can be evidenced by three aspects:

(1) Carbon isotopic composition. The ethane carbon isotopic composition of natural gas in the Cambrian Longwangmiao Formation is -35‰ - -31‰, similar to the kerogen carbon isotopic composition of the Qiongzhusi Formation which is -36.4‰ - -30.0‰, and the bitumen carbon isotopic composition of the Longwangmiao Formation (-35.4‰ - -33.1‰) is genetically related to the kerogen carbon isotopic composition of the Qiongzhusi Formation (Fig. 3), indicating that the natural gas is mainly sourced from the mudstone of the Qiongzhusi Formation. Compared with the Longwangmiao Formation, the ethane carbon isotopic composition (-30.0‰ - -27.5‰) of the Dengying Formation is evidently heavier than the ethane carbon isotopic composition of the Longwangmiao Formation, suggesting a different gas source for the Dengying Formation. Judged from the comparison between the bitumen carbon isotopic composition (-36.8‰ - -34.5‰) of the Dengying Formation reservoirs and the kerogen carbon isotopic composition of source rocks (-36.4‰ - -30.0‰ for the Qiongzhusi Formation, and -34.5‰ - -29.0‰ for the Deng 3 Member), it is consistent with the inheritance relationship between bitumen and parent source kerogen (Fig. 3), indicating that natural gas in the Dengying Formation may come from the above two sets of source rocks.

(2) Hydrogen isotopic composition. The hydrogen isotopic composition of natural gas is not only affected by the maturity, but also by the water salinity during the deposition period. Generally, gammacerane with higher abundance is regarded as an important indicator of high salinity in sedimentary waters^[28]. The ratio of gammacerane to C₃₀ hopane of the Qiongzhusi Formation source rocks is higher than that of the Deng 3 Member source rocks^[29], indicating that the salinity of the former is higher. The methane carbon isotopic composition of the Longwangmiao Formation and Dengying Formation is mostly -34‰ - -32‰, indicating a small difference in the maturity. The methane hydrogen isotope of the Longwangmiao Formation (-138‰ - -132‰) is evidently heavier than that of the Deng 4 Member (-147‰ - -135‰), and the methane hydrogen isotopic composition of the Deng 2 Member is the lightest (-150‰ - -141‰)^[30], showing that the natural gas of the Longwangmiao Formation should come from the Qiongzhusi Formation with higher water salinity. The gas in the Dengying Formation should be a mixed source, and the source rocks of the Qiongzhusi Formation should contribute more to the natural gas of the Deng 4 Member than the source rocks of the Deng 3 Member.

(3) Hydrocarbon-generating capacity. The Lower Cambrian Qiongzhusi Formation is a set of extensively distributed high-quality source rocks, specially in the Deyang-Anyue rift, where the Qiongzhusi Formation source rocks are 300-450 m thick, with TOC of 1.8%-4.5% and the gas generation intensity of (60-160)×10⁸ m³/km². The Deng 3 Member source rocks are distributed in a relatively limited range^[19], with the thickness of 5-30 m, average TOC of 0.65%, and the gas generation intensity of (2-12)×10⁸ m³/km². According to carbon/hydrogen isotope evidence, it is concluded that the Cambrian natural gas in the Anyue gas field is originated from the Qiongzhusi Formation and the Sinian natural gas is a mixed source gas from the Qiongzhusi Formation and the Deng 3 Member source rocks. Moreover, the Qiongzhusi Formation is significantly superior to the Deng 3 Member in the development quality and gas generation capacity. Coupling with geochemical indexes and geology, it is comprehensively inferred that the Qiongzhusi Formation is the primary gas source in the Anyue gas field.

3.2.2. Hydrocarbon charging

The petrographic observation of reservoir fluid inclusions in the Anyue gas field reveals that there are mainly four types of hydrocarbon inclusions, i.e. bitumen-containing inclusions, bitumen inclusions, gas inclusions (Fig. 4a, b) and oil inclusions (Fig. 4c, d), indicating that the Anyue gas field has experienced multiple periods of hydrocarbon charging. The oil inclusions in the matrix dolomite at 5138.89-5139.10 m of the Dengying Formation in Well Gaoshi 18 show yellow-green fluorescence, with the major peak of fluorescence spectrum of (545±3) nm (Fig. 4e). The oil inclusions in the dolomite filling in caves show bright blue fluorescence, with major peak of fluorescence spectrum of (495±2) nm. The latter are significantly more than the former. According to the fluorescence spectrum of oil inclusions, the major peak wavelength of the yellow-green fluorescent oil inclusions is significantly higher than that of the bright blue fluorescent oil inclusions, reflecting the different thermal maturity of the two, which have experienced two phases of crude oil charging. The presence of bitumen inclusions and bitumen-containing inclusions and the rich content of bitumen in reservoirs suggest the occurrence of thermal cracking of paleo-oil reservoir. A large number of gas inclusions are developed in dolomite, quartz and calcite veins, indicative a process of dry gas charging.

3.2.3. Stages of hydrocarbon accumulation and evolution

Based on the analysis of oil and gas sources and hydrocarbon charging phases, together with the regional structural evolution history and the hydrocarbon generation and expulsion history of source rocks, the homogenization temperature of brine inclusions and the temperature of the reservoir burial history were compared to restore the hydrocarbon accumulation and evolution process of the Sinian-Cambrian in the Anyue gas field in Central Sichuan. The process can be divided into four stages (Fig. 5).

(1) Initiation of paleo-oil reservoir (Fig. 5a). In the Silurian, the Qiongzhusi Formation source rocks had R_o of 0.5%-0.8%, entering the early stage of oil generation. The generated crude oil migrated along the unconformity at the top and high-angle faults of the Dengying Formation to the mound-shoal reservoir rocks of the Dengying Formation and the granular shoal reservoir rocks of the Longwangmiao Formation, resulting in the formation of the first phase of paleo-oil reservoir with a small scale. Yellow-green fluorescent oil inclusions were formed in this stage.

(2) Extensive formation of paleo-oil reservoir (Fig. 5b). In the Late Permian-Triassic, the Qiongzhusi Formation source rocks in the hydrocarbon generation center reached R_o of 1.0%-1.3%, entering the peak of oil generation. A large quantity of crude oil migrated to the Central Sichuan paleo-uplift of the Dengying and Longwangmiao Formations and charged intensively in the Dengying Formation and Longwangmiao reservoirs, forming the second phase of large-scale paleo-oil reservoirs. Bright blue oil inclusions were formed in this stage.

(3) Cracking of paleo-oil reservoir (Fig. 5c). From the Middle-Late Jurassic to the Early Cretaceous, with the burial depth, the reservoir temperature of the Dengying Formation and Longwangmiao Formation in Central Sichuan exceeded 160°C. Extensive thermal cracking and in-situ accumulation of paleo-oil reservoirs occurred to form oil-cracked gas reservoirs, resulting in the formation of bitumen-containing inclusions, gas inclusions, and bitumen.

(4) Finalization of gas reservoir (Fig. 5d). In the Himalayan, the strong compression at the periphery of the Sichuan Basin was transferred to Central Sichuan. The Weiyuan area was greatly uplifted, with some natural gas transformed or destroyed. The Gaoshiti-Moxi area at the axis of the paleo-uplift was relatively stable structurally, with the gas reservoirs kept in situ and finalized. A large number of gas inclusions were formed in this stage.

The Cambrian-Ordovician in the North Tarim area of the Tarim Basin (the periphery of the Manxi intracratonic depression) are taken as an example to discuss the oil and gas sources, hydrocarbon charging stages, and hydrocarbon accumulation and evolution process, and identify the major controlling factors to hydrocarbon accumulation.

The North Tarim area has the most concentrated proven marine oil and gas reserves in the Tarim Basin. In the Late Sinian, it began to transform from intracratonic rift to the northern slope of the Manxi intracratonic depression. So far, Halahatang, Tahe, Shunbei and other oil and gas fields have been discovered. There are multiple sets of hydrocarbon-bearing strata, ranging from Ordovician, Carboniferous to Triassic and Jurassic, but hydrocarbons are mainly concentrated in Ordovician Yijianfang Formation and Yingshan Formation. The Ordovician reservoirs are dominated by karst fractured-vuggy carbonate rocks, distributing extensively in quasi-layered manner, with a buried depth of 5000-8500 m, and with oil in the west and gas in the east, and heavy oil in the north and light oil in the south. Recently, Well Luntan 1 obtained industrial oil and gas flow in the Lower Cambrian Wusonggeer Formation, revealing good prospects for exploration in the Cambrian in the periphery of the Manxi intracratonic depression.

3.3.1. Oil and gas sources

The primary marine source rocks in the North Tarim area have been controversial for a long time. Two viewpoints are common: one is the Middle-Upper Ordovician; the other is the Cambrian-Lower Ordovician^[31,32]. In this study, we systematically cleaned, selected, and tested a total of 203 core, cutting and outcrop samples from 5 wells and 1 section in North Tarim and Central Tarim, and correlated the oil and gas sources with the oil samples of Ordovician from 173 wells and of Cambrian from Well Luntan 1 in North Tarim. The results suggest that the Cambrian-Ordovician oil and gas in North Tarim are mainly derived from the source rocks in the Yuertus Formation, which can be evidenced by two aspects:

(1) Distribution of source rocks and abundance of organic matter. In the North Tarim area, high-quality source rocks of the Yuertus Formation have been drilled by wells such as Xinghuo 1, Luntan 1, and Qitan 1, with a thickness of 17-45 m and TOC of 0.90%-26.14%. For Well Xinghuo 1, the Yuertus Formation is 28 m thick, with TOC of 0.90%-7.53% (averaging 4.30%). For Well Luntan 1, the Yuertus Formation shows a cumulative thickness of 45 m with TOC >1% and the 17 m-thick black mudstone at the bottom with TOC of 6.35%-10.84% (averaging 9.01%). For Well Qitan 1, the Yuertus Formation reveals a cumulative thickness of 27 m with TOC >1% and the 6 m-thick black mudstone at the bottom with TOC of 16.03%-26.14% (averaging 20.16%) (Fig. 6). The source rocks of the Middle-Upper Ordovician Saergan Formation are only found in the Keping-Akesu area, with TOC of 0.10%-2.83% (averaging 1.32%)^[33,34], and have not been encountered in the North Tarim uplift and Northern depression so far, suggesting that this set of source rocks are distributed in an extremely limited range. The Lianglitage Formation in the Central Tarim area exhibits a TOC value of 0.05%- 0.90% (averaging 0.25%), making it impossible to become an effective source rock.

(2) Carbon isotopic composition. By comparing the carbon isotopic compositions of kerogen of the Cambrian-Ordovician source rocks and of the Ordovician crude oil in North Tarim (Fig. 7), it can be seen that the carbon isotopic composition of the Ordovician crude oil is very approximate to that of with the underlying Cambrian Yuertus Formation source rocks and generally lighter than -31‰, while the kerogen carbon isotopic compositions ​of the Ordovician Salgan Formation and Lianglitage Formation are both greater than -31‰, indicating that Ordovician crude oil was mainly derived from the Cambrian Yuertus Formation source rocks. The carbon isotopic compositions of the Ordovician crude oil and that of the Cambrian Yuertus Formation source rocks both show a law of lightening from east to west. The carbon isotopic composition of crude oils is -32.6‰ - -30.8‰ (averaging -31.7‰) in the Lungu East-Lungu block and -32.5‰ - -31.5‰ (averaging -32.2‰) in the Lungu West block in the eastern part, -33.4‰ - -32.0‰ (averaging -32.9‰) in the Halahatang block in the central part, and -33.7‰ - -32.4‰ (averaging -33.1‰) in the Yingmaili block in the western part. The kerogen carbon isotopic composition of Yuertus Formation is -32.1‰ - -30.5‰ (averaging -31.1‰) in Well Luntan 1 in the eastern part, -34.2‰ - -32.2‰ (averaging 32.9‰) in Well Xinghuo 1 in the western part, and westward -36‰ - -34‰ (averaging -34.8‰) in the Shierike section of Aksu.

3.3.2. Oil and gas charging

The Re-Os isotope age of crude oil was used to determine the age of crude oil generation, and the K-Ar isotope age of authigenic illite from oil-/bitumen-bearing sandstones was used to determine the age of crude oil charging. It is proposed that the Cambrian-Ordovician in the North Tarim area experienced three stages of oil and gas charging.

(1) Oil charging in the Late Caledonian-Early Hercynian. In the previous studies, the Re-Os isotope age of crude oil from the Tahe Ordovician heavy oil area was measured to be (443±7) Ma^[35], indicating that oil and gas began to generate in the Early Silurian and charged in the Ordovician. The K-Ar isotope ages of the authigenic illite of fine sandstone filled in the Ordovician underground rivers and the Silurian oil-leached fine sandstone and bituminous sandstone were determined to be 397-408 Ma, 378-418 Ma, and 365-391 Ma^{[35,36,37,38]}, respectively, indicating that the first phase of extensive hydrocarbon charging continued from the Early Silurian to the Late Devonian.

(2) Oil charging in the Late Hercynian-Indosinian. The Re-Os isotope age of crude oil in the Halahatang medium oil area was measured to be (285±48) Ma^[39], indicating that crude oil had begun to regenerate in the Early Permian and the second phase of extensive oil charging occurred from the Early Permian to the Late Triassic. The K-Ar isotope age of authigenic illite in the Carboniferous sandstone of the Hudson Oilfield was 224-280 Ma^[40,41,42].

(3) Oil and gas charging in the Himalayan. The K-Ar isotope ages of authigenic illite in the Triassic of Jirak Oilfield and the Triassic and Jurassic sandstones of Lunnan Oilfield were 40-49 Ma, 15-49 Ma, and 14-16 Ma, respectively^[40,41], indicating that continuous hydrocarbon charging occurred in the Cenozoic, which were mainly light oil and partially dry gas.

3.3.3. Stages of hydrocarbon accumulation and evolution

Based on the analysis of oil and gas sources and hydrocarbon charging phases, together with the regional structural evolution history and the thermal evolution history of source rocks, it is comprehensively inferred that the North Tarim area has mainly experienced three stages of hydrocarbon accumulation and evolution, forming the pattern of the coexistence of multi-stage and multi-phase hydrocarbons (Figs. 8 and 9).

(1) Oil reservoir in the Late Caledonian-Early Hercynian. In the Late Ordovician-Silurian, the source rocks of the Yuertus Formation in the Manxi intracratonic depression entered the early stage of oil generation. The generated crude oil migrated along the faults and unconformities and accumulated in the Ordovician karst fractured-vuggy reservoir rocks and the Silurian sandstones in the North Tarim area. At the end of the Silurian, the North Tarim area was uplifted to cause the first destruction of the paleo-oil reservoirs. The Silurian bituminous sandstone was distributed in large scale, and the Ordovician oil reservoir was degraded and thickened (Fig. 9a). During the Late Devonian-Early Carboniferous, the North Tarim area was further uplifted to destroy the paleo-oil reservoir for the second time. The Silurian-Devonian in the eastern part of the Lungu-Tahe area was completely denuded, making the oil reservoir completely destroyed. In the northern part of the Tahe Oilfield, due to the presence of the Silurian caprocks, the paleo-oil reservoir was preserved, but the oil was degraded into heavy oil, with the density greater than 1 g/cm³ at 20 °C (Fig. 8).

(2) Oil reservoir in the Late Hercynian-Indosinian. In the Early Permian, the burial depth of the southern slope of North Tarim continued to increase and the source rocks of the Yuertus Formation entered the peak stage of oil generation, when a large amount of medium oil was generated. Crude oil migrated along the fault to the structural highs of the northern uplift and accumulated in large scale in the Ordovician fractured-vuggy reservoirs. From the Late Permian to the Early Triassic, the Lunnan low-uplift was uplifted again, the Lungu West block suffered a strong denudation, and the Late Hercynian paleo-oil reservoir was degraded, resulting in the thickening of crude oil. The crude oil reached a density greater than 0.92 g/cm³, but it was preserved in a large scale. In the northern buried hill zone of Tahe-Halahatang, the residual Late Caledonian heavy oil was mixed with the Late Hercynian medium oil, becoming a crude oil with the density greater than 0.92 g/cm³; southward, the proportion of the Late Hercynian medium oil increased with the buried depth. In the lower slope of Tahe-central Halahatang area, the Late Hercynian oil reservoirs were not damaged, and mainly contained medium oil (Figs. 8 and 9b).

(3) Light oil-dry gas in the Late Himalayan. Since the Eocene, affected by the strong thrust of the Kuqa piedmont, the North Tarim area was rapidly and deeply buried, and the source rocks of the Yuertus Formation entered the high-mature evolution stage, when light oil and dry gas were generated. In the uplift of North Tarim, the Cambrian subsalt was charged with light oil, such as the Cambrian oil reservoir of Well Luntan 1. On the southern slope of North Tarim, gas charging occurred. In the Lungu area, the Himalayan oil and gas migrated upwardly along the fault to the Carboniferous, Triassic and Jurassic, forming medium and shallow oil and gas reservoirs such as Jiefangqu East, Jirak, and Lunnan (Figs. 8 and 9c).

The Changcheng System at the southern margin of the Ordos Basin is taken as an example to make a preliminary research on hydrocarbon accumulation in the periphery of the craton-marginal rift, which has only been less explored and discussed. Solid bitumen is found in the Changcheng quartz sandstone in the Yongji, Luonan and other field sections at the southern margin of the Ordos Basin. It has the characteristics of three aspects: (1) The Changcheng quartz sandstone is observed with opaque black materials between the grains under the single polarized light of ordinary thin section or showed orange or brown fluorescence under the excitation of ultraviolet fluorescence. (2) The SEM energy spectrum analysis indicates that the content of carbon elements of is relatively high. Typically, the Changcheng quartz sandstone in Yongji contains a carbon-to-hydrogen mass ratio of 60.10%-92.52% and an atomic ratio of 75.26%-95.02%. (3) The peak characteristics of micro-laser Raman spectra indicate the occurrence of bitumen. The micro-laser Raman spectra of the opaque black materials of the Changcheng System in Yongji show two first-order characteristic peaks of bitumen, appearing at the D peak at 1250-1450 cm^-1 and the G peak at 1500-1605 cm^-1.

The above phenomena indicate that the Changcheng System in the southern margin of the Ordos Basin has experienced the process of oil and gas migration and charging. Combined with the burial history of Well Chuntan 1, it is believed that the Changcheng System in the southern margin may have experienced three stages of hydrocarbon accumulation and evolution, i.e. paleo-oil reservoir, cracked gas reservoir, and adjustment and transformation. (1) In the Early-Middle Ordovician, the Changcheng System source rocks entered the hydrocarbon generation threshold, and the paleo-oil reservoirs were formed. (2) In the Middle-Late Permian, the southern margin was strongly buried, the formation temperature exceeded 160 °C, and the paleo-oil reservoir was cracked into gas. (3) In the Middle-Late Jurassic, the southern margin was uplifted, and the gas reservoir was destroyed and adjusted, possibly resulting in the formation of secondary gas reservoirs in the overlying strata.

As indicated by above analysis of typical oil and gas reservoirs, the marine ultra-deep layers have generally experienced complex hydrocarbon accumulation and evolution processes including multi-stage hydrocarbon generation, multi-stage hydrocarbon accumulation, and multi-stage adjustment. The formation of large ultra-deep oil and gas fields not only requires favorable petroleum geological conditions, but also dynamic evolution conditions favorable for oil and gas preservation. Comprehensive analysis suggests that the formation of ultra-deep oil and gas reservoirs is mainly affected by three factors: major hydrocarbon generation center, high-quality large- scale reservoir-caprock assemblage formed by high-energy beach facies superimposed karst-scale reservoirs and very thick gypsum salt or mudstone caprocks, and stable trap conditions.

Ultra-deep layers demonstrate complex hydrocarbon accumulation process due to multiple phases of tectonic movements. The large ultra-deep oil and gas fields discovered so far are all close to the major hydrocarbon generation centers, with the evident characteristics of “source control”. Thus, identification of major hydrocarbon generation center is the primary task to find ultra-deep large oil and gas fields, which is the material basis for the formation of ultra-deep large oil and gas fields. In the Tarim Basin, four ultra-deep oil and gas fields in the North Tarim-Central Tarim area, including Halahatang, Central Tarim No.1, Tahe, and Shunbei, are located in the Manxi intracratonic depression, and adjacent to the hydrocarbon generation center of the Lower Cambrian Yuertus Formation, thereby laying a good foundation for the formation of large oil and gas fields. In the Sichuan Basin, the Anyue gas field in Central Sichuan is adjacent to the Deyang-Anyue rift and near the hydrocarbon generation center of the Lower Cambrian Qiongzhusi Formation; the Kaijiang-Liangping trough in Northern Sichuan shows the hydrocarbon generation center in the Upper Permian, which controls the formation and distribution of large Permian and Triassic reef-shoal gas fields such as Puguang, Yuanba, and Longgang. In the Ordos Basin, where the situations are unique, the appearance of hydrocarbon generation center of marine source rocks in Precambrian and Lower Paleozoic needs to be explored.

China’s marine ultra-deep large oil and gas fields are extremely deep and old, and they could not be formed without effective and large-scale reservoir-caprock assemblages. China’s marine ultra-deep carbonate reservoirs are mainly divided into two types: vuggy dolomite reservoirs formed by high-energy shoal superimposed karst reformation, and fractured-vuggy limestone reservoirs formed by superimposed faults and karst. These two types of large-scale reservoirs and stably distributed very thick mudstone or gypsum salt rock can form a high-quality reservoir-caprock assemblage.

In the Anyue gas field of the Sichuan Basin, the Sinian Dengying Formation high-energy shoal-vug dolomite reservoir and the overlying Cambrian Qiongzhusi Formation thick mudstone constitute a high-quality large-scale reservoir-caprock assemblage. In the North Tarim area, the Sinian Qigebulak Formation vuggy dolomite and the Yuertus Formation shale constitute a favorable reservoir- caprock assemblage. In the Central Tarim-North Tarim area, the Lower Cambrian Xiaoerbulak Formation-Wusonggeer Formation vuggy dolomite and the Cambrian Shayilik Formation-Avatag Formation very thick gypsum rock constitute a reservoir-caprock assemblage. All these assemblages are the focus of recent exploration. The Middle-Lower Ordovician Yingshan Formation-Yijianfang Formation karst fractured-vuggy limestone reservoirs in the ultra-deep oil and gas fields (e.g. Halahatang, Shunbei and Tahe) in the North Tarim area and the stalely distributed Upper Ordovician Sangtamu Formation thick mudstone and Tumuxuke Formation marlstone constitute a high-quality reservoir-caprock assemblage.

Ultra-deep oil and gas have been transformed and adjusted in multiple periods due to tectonic movements. They could accumulate only under the conditions of stable trap conditions and that they were not damaged by late faults or uplift denudation.

In the Sichuan Basin, the Gaoshiti-Moxi structure is located at the core of the Central Sichuan paleo-uplift. Since it stayed inside the craton, despite of an uplift and denudation of nearly 2000 m during the Himalayan, the trap remained stable during the long-term structural evolution without an evident damage by faulting. As a result, the trap always kept in a favorable position for oil and gas migration and accumulation, which provides indispensable conditions for the formation of the Anyue gas field.

In the Tarim Basin, the Ordovician fractured-vuggy complex and the Middle-Upper Ordovician tight limestone form a lithologic-stratigraphic trap on the southern slope of the North Tarim area. During the active period of the fault, the trap communicated the source rocks with the reservoir rocks, providing favorable pathway for oil and gas migration. On the other hand, the faulting activity didn’t cut through the overburden, so the trap remained intact, forming a large-area quasi-layered fractured-vuggy reservoir.

In the Ordos Basin, the southern margin at the edge of the craton suffered a strong structural uplift in the Middle-Late Jurassic, damaging the integrity of the trap. As a result, the preservation conditions became very worse, and the gas reservoir was destroyed. So far, no industrial discovery has been made in the Mid-Neoproterozoic and ultra-deep layers.

China’s marine ultra-deep exploration has just started. The less-explored and broad marine ultra-deep strata are an important replacement option for finding large oil and gas fields. According to the petroleum geology and the process and main controlling factors of hydrocarbon accumulation and evolution, three favorable directions to explore the marine ultra-deep strata are proposed, namely, the periphery of intracratonic rift, the periphery of intracratonic depression, and the craton margin.

Intracratonic rifts control the distribution of high-quality source rocks. Platform marginal mound-shoal complexes are developed on both sides of the rift. Coupling with karstification, porous-vuggy dolomite reservoirs were formed, corresponding to the source-reservoir assemblage types of “lower generation and upper storage”, “upper generation and lower storage”, and “lateral generation and side storage”. By virtue of overlying regional mudstone of transgressive tract, the conditions for oil and gas accumulation at the periphery of the rift were favorable, making it a key area for marine ultra-deep exploration. This can be exemplified by the periphery of the Deyang-Anyue rift in the Sichuan Basin. On the east side of the rift, the Anyue gas field has been discovered. The northern slope of the Central Sichuan paleo-uplift is adjacent to the major hydrocarbon generation center and reveals multiple sets of target layers such as the Sinian Dengying Formation, Cambrian Canglangpu and Longwangmiao Formation, with diverse traps such as lithologic trap and structural-lithologic trap, so it is very prospective for the discovery of large gas fields (Fig. 10). In addition, the Sinian platform margin belts in South Sichuan and Southwest Sichuan are worthy of attention. The North Tarm and Southwest Tarm intracratonic rifts are predicted to contain the Nanhua-Sinian source rocks, making them potential exploration targets.

The intracratonic depression is believed to inherit from the early rift, but it is distributed in a larger range. High- quality source rocks of transgressive tract are widely developed in the intracratonic depression, with an area of more than tens of thousands of square kilometers. Moreover, affected by micro-paleotopography and sea level eustacy, multi-stage intraplatform granular shoals are developed; superimposed by karstification, multiple sets of large-scale carbonate reservoirs were formed. Sea level decline and occluded environments led to restricted evaporate platforms, where very thick gypsum caprocks were developed, which determined the favorable hydrocarbon accumulation conditions in the periphery of the intracratonic depression. So, the periphery of the intracratonic depression is regarded as one of the major ultra-deep exploration targets. This paper proposes the Sinian-Cambrian of the North Tarim uplift at the periphery of the Manxi intracratonic depression in the Tarim Basin, the Cambrian Xiaoerbulak Formation in the northern Central Tarim-Gucheng, the Cambrian Xiaoerbulak Formation at the periphery of the Wensu Bulge, and the Ordovician in the North Tarim-Central Tarim- Gucheng area (Fig. 11), as well as the Cambrian in the periphery of Liangping-Yibin platform-depression in the Sichuan Basin as favorable exploration targets in the near future. In the northern part of the Manxi intracratonic depression in the Tarim Basin, where the Yuertus Formation hydrocarbon generation center is developed, a large Ordovician oil and gas field has been discovered in the North Tarim-Central Tarim area by Well Luntan 1 which obtained industrial oil flow in the Lower Cambrian and gas show in the Upper Sinian, so that this area is a focus of recent exploration and has the prospect for finding large oil and gas fields. At the periphery of Liangping- Yibin platform sag in the Sichuan Basin, the Cambrian Canglangpu Formation, Longwangmiao Formation and Xixiangchi Formation granular shoal dolomite reservoirs form a good source-reservoir assemblage with the widely distributed Qiongzhusi Formation source rocks, suggesting this area an important exploration zone in the coming future (Fig. 10).

Deepwater shelf facies organic-rich shale is generally developed on the margin of craton, reflecting good source rock conditions. The platform margin belts at the craton margin control the distribution of favorable reservoirs such as mound-shoal complex and reef-shoal complex, forming multiple source-reservoir assemblages such as “lower generation and upper storage” and “side generation and lateral storage” with large buried depth, so they are important options for ultra-deep exploration. Through evaluation, the Sinian-Cambrian platform margin belt in the northern Sichuan Basin, the Permian Qixia Formation platform margin belt in western Sichuan (Fig. 10), and the Changcheng System in the southern margin of the Ordos Basin are considered as favorable exploration zones. So far, important progress has been made in the exploration of the Qixia Formation platform margin belt in western Sichuan, but other zones need to be further investigated in respect of favorable reservoirs, traps and preservation conditions.

Marine ultra-deep strata in China are defined as the Precambrian-Lower Paleozoic marine strata with a burial depth greater than 6000 m. The global supercontinent breakup-convergence cycle controlled the evolution of rifts and depressions in the cratonic basins of China, providing a favorable structural setting for the generation and accumulation of ultra-deep oil and gas.

Multiple sets of source rocks such as the Nanhua, Sinian, Cambrian, Ordovician and Silurian are developed in China’s marine ultra-deep strata. Specifically, the Lower Cambrian source rocks, which are uniformly developed in the Sichuan Basin and Tarim Basin, are major source rocks in the ultra-deep strata. The favorable reservoirs in the ultra-deep strata are mainly high-energy mound- shoal complex, reef-shoal complex, granular shoal dolomite and limestone. The development of high-quality reservoirs is jointly controlled by later dissolution reformation and faulting activities. There are three types of reservoirs: porous reservoirs, fractured-vuggy reservoirs and caved reservoirs. Thick regional shale, gypsum salt and tight carbonate rocks are excellent caprocks for ultra-deep oil and gas.

The analysis of the Sinian-Cambrian in Central Sichuan, the Cambrian-Ordovician in North Tarim, and the Changcheng System in the southern margin of the Ordos Basin shows that China’s marine ultra-deep strata have generally experienced the evaluation stages of two phases of oil reservoirs, (partial) cracking of paleo-oil reservoir, and finalization of cracked gas (or overmature oil and gas) reservoir.

Enrichment of marine ultra-deep oil and gas is jointly controlled by static and dynamic geological factors, typically including four factors, namely, major hydrocarbon generation center, high-energy shoal facies superimposed karst-scale reservoir, very thick gypsum salt rock or shale caprock, and stable trap conditions.

Based on the petroleum geology, and the process and controlling factors of hydrocarbon accumulation and evolution, combined with the latest exploration progress, three favorable directions to explore marine ultra-deep strata are proposed, namely, the periphery of intracratonic rift, the periphery of intracratonic depression, and the craton margin. The favorable exploration zones determined include the Sinian-Cambrian in the northern slope of the Central Sichuan paleo-uplift in the Sichuan Basin (the periphery of the intracratonic rift), the Sinian-Cambrian in the North Tarm uplift and the Cambrian Xiaoerbulak Formation in the northern Central Tarim- Gucheng in the Tarim Basin (the periphery of the intracratonic depression), and the Permian Qixia Formation platform margin zone in the western Sichuan Basin and the Sinian-Cambrian platform margin zone in the northern Sichuan Basin (the carton margin).