More than one hundred years of exploration and development of oil and gas have proved that “no sedimentary basins, no oil and gas”. It also proved that hydrocarbon abundance in different types of sedimentary basins differs greatly^[1]. The classification of sedimentary basins, and study about the relationships between the types of basins and hydrocarbon enrichment, have become crucial research topics in petroleum geology. Since the 1950s, a variety of classification schemes for sedimentary basins have been proposed. These schemes can be divided into three categories according to their theoretical bases: (1) Schemes based on the geosyncline-platform theory, also referred to as the classification scheme of basins during the pre-plate tectonic period, proposed by Umbgrove^[2] and Weeks^[3]; (2) Schemes based on the theory of plate tectonics, proposed by Halbouty^[4], Dickinson^[5,6], Klemme^[7], Bally^[8], Chen^[9] and Kingston^[10], et al. and (3) Schemes based on geodynamics, proposed by Liu^[11,12], Lu^[1], Allen^[13], and others. Due to the deficiencies in these classification schemes, new classification schemes emerge continuously. For example, the geosyncline-platform theory is based on the concept that basins consist of two major structural units, namely the active area and the stable (or platform) area. The classification of basins is conducted according to basin shapes and locations. This classification scheme is simple and clear, but offers no explanation about the formation mechanisms of the basins. The classification on the basis of the plate tectonics is the richest approach, primarily based on the type of plate boundary where the basin is located and the dynamic mechanisms of the underlying lithosphere. The shortcoming of this scheme is that there is no systematic explanation of the relationships between diverse types of basins. The theory of geodynamics emphasizes the stress environment in which basins form, and the controlling effect of stress on the structural framework and sedimentation of the basins. However, there is little analysis about the evolutionary processes of the basins. It is essential to find a simple and easy approach to classify sedimentary basins, which not only explains the geneses of various types of basins and the relationship between them within a unified theoretical system, but also reflects the petroleum geological conditions of each type of basins and can make a prediction on their hydrocarbon potential.

Sedimentary basins are the principal units of global tectonics, the formation and superimposition evolution of which are controlled by global plate tectonic movements. In any particular geological period, the dynamic mechanism of the plate-tectonic setting is specific and unique, resulting in the formation of particular type of basins, named as prototype basin. For different types of prototype basins, the sedimentary-tectonic systems are specific and unique, with different hydrocarbon bearing conditions. This has long been recognized and accepted by experts in the industry. As early as 1958, Weeks^[14] proposed that “to understand oil production, you must return to the original sedimentary basin". Tong et al.^[15] believed that the types of basins during the paleo-geological period are very important for the formation of source rocks, reservoirs, cap rocks and other hydrocarbon accumulation factors. However, it is insufficient to identify the type of the prototype basin in only one particular geological period. With continuous plate movement, new prototype basins were developed and superimposed continuously during the geological time, and the hydrocarbon accumulation conditions of the early prototype basins changed continuously. In this study, based on the theory of plate tectonics, with the IHS commercial database and other data, we systematically analyzed the evolution history of 483 sedimentary basins around the world since the Precambrian (Fig. 1). Combined with the tension, compression and shear stress environments, this study establishes the evolution and sedimentary models of the prototype basins at the different plate tectonic positions, and analyzes the hydrocarbon accumulation conditions and subsequent changes in each prototype basin, laying a solid foundation for scientific classification of sedimentary basins and accurate prediction of hydrocarbon prospects.

Both onshore and offshore drilling technologies have made great progress since the 1960s, and the evolution history of global plate tectonic movements since the Neoproterozoic has become more and more clear. At the end of the Precambrian, there were a number of ancient cratons on earth that were separate from each other, including the North American ancient land, Baltic land, Gondwana land (including the present-day Africa, South America, Australia, Antarctica, India and Arabia), Angara land, and several smaller land masses in China(including South China, North China, Tarim, etc.)^{[9, 16]}. During the Paleozoic, the cratons gradually drew closer together. During the Permian, the structural framework developed eventually with a single supercontinent (Pangaea), a vast ocean (the Paleo-Pacific) and a bay (Tethys)^{[9, 16]}. During the Mesozoic, the Panchia supercontinent developed, accompanied with the formation of the Neo-Tethys, the Indian Ocean, and the Atlantic Ocean. Every tectonic plate in the world was in a tensile stress environment, dominated by the disintegration of Pangaea. During the Cenozoic, the Atlantic and Indian Oceans continued to expand, the Pacific Ocean contracted, and the Neo-Tethys Ocean closed, forming a global structural framework of overall extension, with local compression and collision^[16,17].

The Canadian geologist, John Tuzo Wilson^[18,19], is one of the founders of plate tectonics theory. He studied the evolutionary history of the two opening and closing episodes of the North Atlantic and the formation of the East African Great Rift Valley, the Red Sea, and the Gulf of Aden. He drew the conclusion that oceans were created by extensional faulting and expansion of continents. When oceans shrunk and closed up, mountains and land masses developed. The entire process, from extensional faulting, expansion, to contraction and closure, represents a complete evolutionary cycle of plate movements. This complete cycle is divided into 6 stages (Fig. 2): (1) Embryonic stage. At this stage, rifts developed on the surface of the earth, such as the East African Rift. (2) Juvenile stage. At this stage, the rifts expanded laterally to form straits, such as the Red Sea and the Gulf of Aden. (3) Mature stage. At this stage, the straits expanded into vast oceans, such as the modern Atlantic Ocean. (4) Decline stage. At this stage, subduction occurred on one or both sides of the ocean, forming island arc, such as that in the Pacific. (5) The residual stage. At this stage, the plates of the ocean closed up and new mountains developed, such as those around the Mediterranean Sea. (6) Suturing stage. At this stage, due to plate collision, intense deformation occurred, collision sutures were developed, such as the Himalayas, which is a vivid example of this process. The British geologist, Kevin C.A. Burke^[20] named this ocean basin development cycle as the Wilson Cycle. Li et al.^[21] considered that this conception of extensional faulting of oceans and closure orogeny can successfully explain the relationship between global plate tectonic evolution and major geotectonic phenomena, such as oceans and orogenic belts, providing a new scientific model of global tectonic evolution.

The Wilson Cycle can be used to scientifically explain the geotectonic features, such as oceans, island arcs, and mountains. As the sedimentary basin is one of the major tectonic units in the world, its formation and development are closely related to these geological tectonic phenomena, and should be reasonably explained. Based on this principle, in this study, 483 major sedimentary basins around the world have been analyzed in detail, with an emphasis on their formation and evolution history since the Precambrian. It has been found that the basin formation mechanisms and types of basins that predominated in each stage of the Wilson Cycle show a high degree of regularity (Fig. 2), with the following general characteristics: (1) The Basin formation dynamics in the first half of a Wilson Cycle were dominated by extensional tensile stress, and the dynamics in the second half were predominated by compression and collision. Shear stress occurred throughout the process of plate tectonic evolution, and transtensional and transpressional stress systems controlled by strike-slip occurred only locally. (2) Each stage of the Wilson Cycle was characterized by a specific type of basin, which is called as the prototype basin of that stage. The types of prototype basins that always developed in a particular stage are called as primary prototype basins, and the ones that occasionally developed are called secondary prototype basins.

2.1.1. Intracontinental growth rift basins

Intracontinental growth rift basins are primary prototype basins developed during the embryonic stage, being a long, narrow subsidence zone developed by rupture of the lithosphere under extension and tension (Fig. 3a)^[22]. Different from the definitions in previous studies, the concept of intracontinental growth rift basins emphasizes that the formation and development of this type of basin are controlled continuously by boundary faults, and these basins are still active (i.e. growing) rift basins. The geographical environment of this type of basin is primarily lacustrine, with frequent seismic and volcanic activities. The main products of volcanic activities are tholeiitic basalt and alkaline basalt. This type of basin has high heat flow, with a geothermal gradient of (38-45) °C/km^{[9, 22-24].} The East African continental Albert rift basin is of this type. The dynamic mechanism is that a hot spot developed due to the upwelling of deep mantle materials. As a result, the lithosphere floated on the molten material, resulting in thinning of the crust and the formation of extensional faults. The basin basement, which was still continental crust, then subsided along the faults. The basins are composed of grabens or half grabens associated with one or more growth faults^[22,23,24].

Intracontinental growth rift basins, such as the Albert Basin and the Gulf of Suez, have been shown to have favorable geological conditions for the formation of large oil and gas fields, with current recoverable reserves of more than 6800×10⁴ t oil equivalent^[22,23,24] and a high degree of hydrocarbon enrichment. Fault depressions controlled by growth faults in an individual basin often have independent petroleum systems. The source rock is deep lacustrine shale, and the organic matter is mainly Type I and Type II₁, with TOC of 1%-5%. In steep slope zones, alluvial fan-subaqueous fan-gravity flow sedimentary systems are developed, while fan delta, braided river delta and gravity flow sedimentary systems are developed in gentle slope zones. The regional cap rock is mud shale deposited during the maximum lake transgression period. Combination of extensional faults and sand bodies provides favorable conditions for horizontal and vertical hydrocarbon migration. Structural hydrocarbon accumulation assemblages are predominant, and hydrocarbon enrichment mainly occurs in rolling anticlines, fault noses, and fault blocks^[22,23,24]. Multi-stage episodic fault activities may destroy conventional reservoirs, forming unconventional heavy oil and oil sand reservoirs. Since the present surface is dominated by lacustrine environment, it is difficult to conduct engineering operations. The development potential of these unconventional reservoirs is limited.

2.1.2. Intracontinental aborted rift basin

Intracontinental aborted rift basins are secondary prototype basins developed during the juvenile stage. This type of basin developed when the intracontinental growth rift basin developed to a certain extent, and the hot spot in the deep mantle disappeared. The lithosphere underwent thermal subsidence and entered into the depression shrinkage stage. Compared with the definition proposed in previous studies^[7], this study placed greater emphasis on differences in the activity states of the controlling boundary faults. That is, the rift basin has entered into a stagnation stage, during which the basin-controlling fault activities effectively cease. In intracontinental rifts, faulted lake basins shrunk, and disappeared after being filled by continental sediments, such as the sediments of fluvial and alluvial fans, etc. The modern earth surfaces are generally terrestrial swamp environments, like the Songliao, Sirte, and West Siberia Basins (Fig. 1)^{[25,26,27,28]}. If the basins are located in continental margin seas at the thin continental crust, and filled by fluvial-delta facies, the modern earth surfaces are neritic shelf environments, such as the North Sea Basin (Fig. 1)^[29]. This type of basin has a structure of “long rift and short depression”, dominated by rifts, with rift strata in the middle and lower parts and depression strata in the upper part (Fig. 4a). Compared with the intracontinental growth basins, the intracontinental aborted basins have lower geothermal gradients, generally (31-39) °C/km, resulting from the recession of deep mantle hot spots^{[24,25,26,27,28,29]}. However, they are still hot basins.

The exploration has proved that, before the decline stage, these basins have the same sedimentary filling characteristics as growth rift basins. They have entered a stable depression stage, which offers excellent conditions for the formation of large oil and gas fields^{[24,25,26,27,28,29,30]}. Whereas, not all rift basins are filled by lacustrine sediments. For example, the West Siberian Basin communicated with seawater during the main rifting stage, and extensive transgression occurred. In the West Siberian Basin, there are high-quality Type I and II₁ source rocks, and TOC ranges from 1% to 11%. At present, 105 large oil and gas fields have been discovered, and it is an intracontinental aborted rift basin with the greatest oil and gas accumulation^[28]. Through analogical analysis, it is believed that the rifts filled by marine sediments have greater exploration potential for unconventional oil and gas than those filled by lacustrine sediments.

2.1.3. Intercontinental rift basin

Intercontinental rift basins are primary prototype basins developed at the mature stage. This type is a primary sedimentary basin with high temperature, long and narrow oceanic crust on the basement (in contrast to intracontinental growth rift basins, which continue to expand)^[9] (Fig. 3b). William R. Dickinson defined this type as proto-oceanic rift^[5], describing it as a transitional stage between intracontinental growth lake basin/sea basin and open passive continental margin basin. The adopted description of this type of basin is consistent with that of the previous studies. A typical representative of this type of basin is the Red Sea Basin (Fig. 1), which is a basin with high heat flows, and the geothermal gradient is greater than 50 °C/km^[31]. Structurally, a stepped extensional fault system, centered on a mid-ocean ridge, is developed on the continental crust of both coasts. The early sedimentary filling was done by coarse continental debris. During the later stage, carbonate rocks and evaporites were relatively well-developed due to the intrusion of large volume of seawater and lack of fresh water supply, together with high geothermal gradient and low latitude^[31].

This type of basin is superimposed on intracontinental growth rift basins. Due to the strong volcanic activities and extremely high heat flow around the mid-ocean ridges, thermal uplifting and fault block activities occurred in the intercontinental rift basins. Oil and gas reservoirs developed during the early growth rifting stage are vulnerable to destruction, leading to the occurrence of secondary or even multiple reservoir formation and the consequent reduction in enrichment of conventional oil and gas. Unconventional deposits such as heavy oil and oil sands may also form. The low exploration degree of the Red Sea Basin does not rule out the possibility of oil and gas enrichment in reef shoals or clastic rocks on sub-salt fault horst. However, engineering operations are severely limited by the present geographical environment. Therefore, the prospects for unconventional oil and gas exploration are poor.

2.1.4. Passive margin basin

Passive margin basins are primary prototype basins developed during the mature stage, being sedimentary basins of divergent continental margin, also known as Atlantic continental margin or inactive continental margin (Fig. 3c)^{[10, 32-34]}. The typical examples are the Santos, Niger Delta, and Carnarvon Basins (Fig. 1). The formation mechanism is as follows: after a basin passed through the intracontinental rift stage (with continental crust basement) and became an intercontinental rift basin (with narrow oceanic crust), the asthenosphere continued to expand, shunting the lithosphere to both sides of the mid-ocean ridge to form a new, open ocean. The continental margin was therefore transported passively to both sides of the mid-ocean ridge (hence the name: passive margin basin). Over time, the passive continental margin experienced thermal subsidence, coupled with regional flexural subsidence caused by gravity under heavy sedimentary loading. As a result, a wide range of sedimentary prisms developed on continental crust, transitional crust, and oceanic crust on the peripheral boundary in the pelagic direction, with thicknesses of 1000 m or more. This description is consistent with previous definitions. This type of basin is a mesothermal basin with a geothermal gradient of (25-35) °C/km^{[32,33,34,35]}, and there is little volcanic activity in this kind of basin.

The sedimentary filling thickness is great in this kind of basin, with a thickness of generally 5-12 km in depocenters. Vertically, the passive margin basins consist of three sets of sedimentary strata^{[32,33,34,35]}: the lower clastic rocks developed at the intracontinental growth rift stage (a few basins form carbonate rocks at the late rifting stage), the middle clastic rocks developed at the transitional intercontinental rift stage (a few basins develop Red Sea type carbonate rocks and evaporites), and the upper passive margin marine clastic rock/carbonate platform developed during a drift depression period, with an obvious basin structure of lower rift and upper depression. Horizontally, the depression period can be divided into four tectono-sedimentary units from land to sea: continental shelf, continental slope, continental rise, and abyssal plain^[36]. The lower sedimentary series developed during the intracontinental growth rift stage generally have good hydrocarbon accumulation conditions. When the sediments in intercontinental rift and drift depression are comparatively thin, and can only serve as regional caprocks, large oil and gas fields can form at the top of the rift strata. Typical examples are the Carnarvon, Browse, Western Australia, and Bonaparte basins on the Northwest Shelf of Australia (Fig. 1). When carbonate and evaporite assemblages developed in sedimentary strata during the middle intercontinental rift stage, oil and gas in the lower growth rift migrated to sub-salt reef-shoal, forming large-scale oil and gas fields, such as the Santos Basin on the east coast of South America. If marine sedimentary series in the upper drift period are more than 4500 m thick, they can also form large oil and gas field groups, with reservoirs dominated by delta-gravity flow sedimentary systems. In such cases, three sets of source rock strata develop at most^[34]: (1) The lower intracontinental growth rift strata, in which high-quality lacustrine and marine source rocks are well developed. The organic matters are Type I and II₁, with TOC of 1%-11%. (2) Drift depression strata developed during the upper passive continental margin stage, in which high-quality marine source rocks are well developed. The organic matters are Type II and III, with TOC of 1%-6%. (3) If high-constructive deltas are developed in the depression strata after the Miocene (with a thickness at the depocenter greater than 4000 m), high-quality source rocks may also be developed in the delta strata, with Type II and III organic matter, TOC generally 1.0%- 2.2%, up to 14.4% at maximum^[34]. Heavy oil sand deposits may form on shore or in shallow water, but the exploration potential of these and other unconventional oil and gas resources is often limited due to the difficulty of engineering operations in complex geographical environments.

2.1.5. Intracratonic basins

Intracratonic basins, usually abbreviated as “craton basins” (Fig. 4b)^[37], are sedimentary basins distributed in relatively stable continental lithosphere (craton), induced by short extension during their early evolution, and entered into a slow depression stage before the end of the Late Paleozoic. Compared with previous definitions, this paper suggests two differences: (1) This type of basin is extremely old, beginning to develop before the end of the Late Paleozoic. (2) The topography of every craton basin is at least partially induced by extension, and tensile faults or rift strata develop at the bottom of the basins. Typical examples are the Williston, Parana, and Paris basins (Fig. 1). The genetic mechanisms are cooling of the lithosphere in the early stage, followed by thermal subsidence and sedimentary filling, then continuous development with the strengthening of sedimentary loading in later period. This type is a mesothermal basin with geothermal gradients of (19-30) °C/km^{[25-26, 37-40].}

Intracratonic basins are generally relatively open, with relatively uniform depressions, and the wings generally merge gently into the surrounding platforms without obvious structural boundaries. The cross section of the whole basin is basically symmetrical, with a simple structure, gentle folds and undeveloped faults. Affected by polycyclic plate movements, the Wilson Cycle of plate margins has an obvious sedimentary corollary in intraplate craton basins. In the first half of the cycle, an extensional stage, transgression generally occurred, forming broad epicontinental seas dominated by fine-grained sediments. During the second half of the cycle, a compressional collision stage, regression occurred, with an increase in coarse debris. Regional unconformities may form during the collision return stage. Only the cratonic basins in the Tarim, Yangtze, and other small, ancient cratons (plates) were able to transform into sections of foreland basin under peripheral orogeny. Therefore, Craton basins in the large, ancient cratons, such as Australia, Siberia, Baltic, South America, and North America, are still at the depression stage, despite hundreds of millions of years of development^{[1, 37-40]}. In addition to fluvial, delta, and swamp facies sediments, most of these basins have experienced marine transgression over long periods, and may contain a wide range of carbonate rocks and evaporites^{[1, 37-40]}.

Over their long geological histories, craton basins are particularly vulnerable to regional uplifts and denudation, with quite different hydrocarbon bearing conditions^{[37,38,39,40]}. Hydrocarbon enrichment is controlled by three main factors^{[37,38,39,40]}: (1) Whether thick failed rift strata formed during the early short extensional stage. Thicker failed rift strata can provide better source rock conditions. (2) Whether large-scale transgressive-regressive sedimentary cycles developed over long geological periods, with each sedimentary cycle generally corresponding to an entire Wilson Cycle^[1]. In such cases, marine, transitional, and continental sedimentary strata developed rom bottom to top, with marine and transitional facies forming two types of effective source rocks, namely mud shales and coal measure strata. The organic matter is mainly Type II and III, and TOC is 0.6%-10.0%. (3) Whether sedimentary filling is continuous. If the basins were located in large ancient cratons, far from convergent continental margin, without experiencing long-term, large-scale uplifts and denudation, the hydrocarbon accumulation conditions of source rocks, reservoirs, and cap rocks are effectively preserved. Reservoirs in this kind of basins are predominantly large-scale braided river-delta sedimentary systems, possibly with platform margins and slope facies reef shoals in low latitudes. Conventional oil and gas reservoirs can form in stratigraphic traps, such as lithologic traps, diagenetic traps, and reef beach bodies. Unconventional oil and gas, including shale oil and gas, tight oil and gas, and coal gas, might also occur^{[37,38,39,40]}.

In a compressive collision stress environment related to plate interaction, the upper crust or lithosphere generally experienced shortening deformation. However, alternating local extensions and compressive stress also occurred on both sides of the island arc at the plate margins.

2.2.1. Decline stage

Mature ocean basins passed into decline in two forms, namely unilateral and bilateral (Fig. 5). In unilateral decline, one side of the oceanic crust did not subduct, so one side of the plate only drifted to the subducted side with the oceanic crust, always in a state of passive continental margin. The West Coast Basin of the Bay of Bengal is currently at this stage. On the other side of the oceanic plate, the dense ocean plate subducted under continental plate, forming a trench-arc-basin system, like the Andaman Sea on the East Coast of the Bay of Bengal, and the South, Middle, and North Sumatra basins^{[9, 41-44]} (Fig. 5a). In bilateral decline, oceanic crust subduction occurred on both sides of the oceanic crust, like the eastern and western edges of the modern Pacific Plate, forming trench-arc-basin systems^[9,41] (Fig. 5b).

During plate decline, once the oceanic crust on the contraction side began to subduct, the continental plate margin was pulled down, forming long and deep trenches (Fig. 5a, 5b). Large sections of cold oceanic crust entered the lower part of the continental crust, and friction generated. The asthenosphere was heated up as a result, changing the thermal state of the mantle along the subduction zone at the margin of the continental crust. In shallower areas, some of the oceanic crust and continental crust melted together, forming intermediate acid magma, which rose to form volcanic island arc, forming volcanic island arc chains parallel to the trenches^{[9, 41]}. Large quantities of other molten materials continued to move to the deep interior of the continental crust. With increasing temperature and dissolution of the upper mantle, complex thermal convection occurred along the island arc near the continental margin. Affected by the distribution of heated molten materials, the primary upward convective channel was located on the inner side, behind the island arc chain, separating the island arc (including the now-welded continental crust) from the continent. This created rift valleys dominated by continental crust basements, transitional crust depressions with high heat flow and some continuing expansions which lead to the formation of oceanic crust and small ocean basins^{[9, 41]}.

Active continental margin trench-arc basin systems are always superimposed on passive continental margin basins. However, no prototype sedimentary strata, such as passive continental margin or rifting strata, have been discovered in the deep layers of the South, Central, and North Sumatra back-arc basins, or the Taraba forearm basin, despite extensive exploration. This may be because the strata were developed during the early passive continental margin stage, above the abduction plate and below the rifting strata, and dissolved as they were dragged into the deep lithosphere by the subduction plate. It is clear that prototype basins vary greatly in horizontal superposition and coincidence. The higher the degree of coincidence, the better preserved the strata in the vertical prototype stage.

2.2.1.1. Forearm system and prototype basin

Trench basins are primary prototype basins, the description of which in this study is consistent with previous studies. They are the most direct tectonic units, produced by simple contraction and collision of two plates. For example, the entire Peru-Chile trench (Fig. 1) is in a compressive stress environment. It is a typical high-pressure, low-temperature, metamorphic development zone, linearly distributed, parallel to island arcs, with a water depth of 6-11 km (Fig. 5a, 5b). It is the coldest basin in the world^{[1, 9]}, with a geothermal gradient lower than 20 °C/km. Trench basins are characterized by starvation sedimentation compensation filling, with the sediments consisting of two main components: (1) pelagic sediments, scraped by subduction plates, directly deposited on ocean crust. (2) Bathyal- abyssal turbidity clastic deposits, composed principally of silt, clay, and volcanic ash, which are unconformably distributed on pelagic sediments^[1,9] and lack effective hydrocarbon generation conditions.

Forearc basins, also known as island arc-trench gap basins, are primary prototype basins, located between trench slope breaks and magmatic arc fronts, and are the most important sedimentary basins in forearc areas^{[9, 45-46]} (Fig. 5a, 5b). The description given here is consistent with previous studies. The Myanmar offshore basin is typical of this type^[45], undergoing obvious structural and sedimentary changes during the decline stage. During the initial subduction stage, this type of basin was a simple seaward slope, dominated by bathyal facies deposition, with sediments directly entering the accretionary subduction complex belts and trenches. With the increase in subduction, the basin developed outwards and upwards. The basin water body became a shallow sea, entering into a transitional environment. In addition to clastic rock deposition, carbonate sediments formed when the temperature and purity were favorable. During the late subduction stage, subduction complexes rose above the water and marine sedimentation ceased. Forearc basins have complex basement features, and a mature forearc basin often spans over magmatic arcs and subduction complexes. Forearc basins have obvious structural characteristics. On the side closest to the magmatic arcs, overlapping contact occurred, and normal faults often developed^[45]. On the side closest to the subduction complexes, unconformable contact occurred, and compressive folds, thrust, and slump layers developed. The evolutionary process of forearc basins suggests that geothermal gradients vary widely, but they are generally in the range of (20-30) °C/km. During the decline stage, forearc basins often span over the structural slopes which are composed of magmatic arc and subduction complexes, so there is little or no space for organic sedimentation. The basins therefore do not generally provide favorable oil and gas conditions. Whereas, favorable hydrocarbon conditions can be developed in two situations: (1) If rifting on the side closest to island arc is strong, the rifts can communicate with seawater to form shallow or semi-deep marine environments, which is favorable for the formation and preservation of organic matter. Similar to rift basins, this can provide good petroleum conditions, such as the Tarala Basin on the coast of Peru^[46]. (2) A trench basin is filled with deep-water debris during the later stage and becomes part of the forearc basin, with a shallow geothermal gradient but large sedimentary thickness. Under these conditions, in addition to shallow biogenic gas source layer systems, deep layers around the sedimentary center may also produce thermogenic gas. Reservoirs are mostly deep-water gravity flow channel -submarine fan. Trap types change from compressional anticline traps in shallow water areas on continental shelf into low amplitude anticline and lithologic traps^[45] in deep water. If regional high-quality cap rocks are well developed, conventional large oil and gas fields may form. However, the geological environments have determined that the forearc basins have limited unconventional oil and gas exploration value.

2.2.1.2. Back-arc systems and prototype basins

Back-arc rift basins are primary prototype basins, produced by extension of deep lava thermal convection on back-arc surfaces^[41] (Fig. 5a, 5b). A typical example is the Malay Basin (Fig. 1). This type of basin differs from the intracontinental growth rift basins in four aspects^[47,48]: (1) The plate tectonic position is different. Back-arc rift basins are only found on continental crust on the back-arc side of the edges of oceanic-continental convergent plates, while intracontinental growth rift basins are generally located on divergent plates. (2) The former is created by magma upwelling caused by oceanic crust subduction, while the latter is generally located on fixed hot spots caused by mantle plumes. (3) The geothermal gradients of the former are higher, generally (50-60) °C/km, which may be related to thinner continental crust. (4) Inversion structures are generally developed in back-arc rift basins. Temporary obstruction of subduction caused horizontal compression, producing positive inversion structures. However, Such structures are developed only in a few basins adjacent to orogenic belts, Back-arc rift basins and intracontinental growth rift basins have similar petroleum conditions. The difference is that inversion structural belts tend to form large oil and gas fields^[47,48]. However, despite the presence of heavy oil reservoirs and oil sand deposits, the exploration potential of unconventional exploration resources in such basins is currently generally limited by their geographical environments.

Back-arc depression basins are created by continuing development and evolution of back-arc rift basins. The basal continental crust became thin, permitting frequent volcanic intrusions, forming a transitional crust with high heat flow (Fig. 5a, 5b)^[41]. Back-arc rift basins are primary prototype basins. These basins are located at the edge of thin continental crust, so they can enter the depression stage, with transitional crust, after a relatively short rifting period. Typical examples are the South, Middle, and North Sumatra basins^[43]. Back-arc depression basins have three major characteristics^{[43, 48-49]}: (1) Obvious two-stage sedimentary formation. The lower section is developed during the rifting stage, generally as a faulted lake basin, and the upper section is developed during the depression stage, with various sedimentary systems such as delta, littoral-neritic sea, bathyal-abyssal facies clastic rocks, and carbonate rocks. (2) Thinning of the crust and intrusion of large amounts of magma form a transition crust. Heat flow was extremely high. Therefore, these are thermal basins with geothermal gradients generally in the range of (40-60) °C/km, and the maximum value is as high as 110 °C/km. (3) Inversion structures are common, for similar reasons of their occurrence in back-arc rift basins. Back-arc depression basins are similar to intracontinental aborted rift basins and have favorable hydrocarbon accumulation conditions^{[43, 48-49]}. However, there are three differences: (1) Back-arc depression basins have relatively closed bay environments developed by island arcs. The combination of lacustrine facies during the lower rifting stage, middle transitional marine-continental facies and upper marine facies during the depression stage is favorable for the occurrence of organic matter. (2) The extremely high geothermal gradients are beneficial for the transformation of large amounts of organic matter into hydrocarbons. There tend to be plenty of oil-bearing strata with good vertical migration properties, which are also relatively enriched in natural gas. (3) Widespread inversion structures offer highly favorable conditions for hydrocarbon enrichment and the formation of large oil and gas fields. The unconventional hydrocarbon exploration potential of back-arc depression basins is similar to that of back-arc rift basins.

Small back-arc ocean basins are the results of continuous evolution of back-arc depression basins and the emergence of ocean crust (Fig. 5b, 5c). It should be noted that the descriptions in this paper of back-arc rift, back-arc depression, and back-arc small ocean basins are in line with the formation mechanism of back-arc series basins proposed by Karig^[41], which is based on plate tectonics theory. However, not all back-arc depression basins develop into small back-arc ocean basins before the back-arc seas close. These form a type of secondary prototype basin. An example is the Japan Sea Basin^[50] (Fig. 1). Like intercontinental rift basins, these basins are characterized by thermal uplifts and inversions, strong block faulting, volcanic rock development, and high geothermal gradients (higher than 40 °C/km)^[50]. Due to extensive development of new oceanic crust, sedimentary filling on the oceanic crust is thin, so the sedimentary strata deposited in the early back-arc rift and back-arc depression stages are seriously damaged by inversion, resulting in poor oil and gas accumulation conditions.

2.2.2. Remnant stage and terminal Stage

The remnant stage occurred during transition between the decline stage and terminal stage (Fig. 5c, 5d). Compared with the decline stage, the only change in the prototype basin during the first half of the remnant period is that the trench basin evolves into the forearc basin. The prototype basin in the second half is consistent with that of the Terminal Stage. In the unilateral declining type, when subduction is blocked after a certain degree of decline, the plates form a horizontal compression environment in island arcs and trenches^[9]. Ocean basins continue to shrink, and back-arc basins/ocean basins begin to close, forming back-arc foreland basins (Fig. 5d). A unilateral-type basin that disappeared in the Bay of Bengal is an example. The Paleocene-Miocene back-arc depression basin in the central basin of eastern Myanmar was uplifted under compression at the end of Miocene, with sea water withdrawing southward. The back-arc depression basin then evolved into a back-arc foreland basin^[51]. Intensifying compression transmitted pressure to the central forearc and the trench, so the pre-existing forearc basin gradually evolved into a compressive thrust belt. The trench became shallow and narrow, filled with large amounts of debris from the thrust belt, and eventually disappeared. The resulting huge, thick sedimentary body gradually merged with the compressive thrust belt of the forearc basin, resulting in expansion of the forearc basin, creating the present Myanmar offshore basin^[45] (Fig. 5d). With continuous compression and contraction, the oceanic crust between the western passive continental margin and the central forearc basin eventually disappeared completely, marking the terminal stage. The western passive continental margin collided with the continental island arc accretion, and the island arc (including various strata on both sides) underwent regional high-pressure metamorphism to form an orogenic belt, the west side of which evolved into a peripheral foreland basin (Fig. 5e). A similar process created the present-day Zagros and Arabian basins^[52]. Finally, with strengthening compressive uplift, the middle island arc, the associated back-arc foreland basins on both sides, and the peripheral foreland basins, were all extruded and uplifted together to create a huge orogenic belt, the Himalayas^[9], marking the end of a complete Wilson Cycle.

2.2.2.1. Peripheral foreland basins

Peripheral foreland basins are the main prototype basins. They are orogenic foredeep basins, developed by the collision of passive continental margins with island arc-type active continental margins following the disappearance of the oceanic crust of unilateral residual basins (Fig. 5e). Bally referred to this type as foredeep basins^[8]. Basins of this type often extend parallel to an orogenic belt, consistent with previous concepts. A representative example is the Arabian/Zagros Basin^[52]. This is a medium-hot basin with a geothermal gradient of (14-32) °C/km^{[9, 25-26, 52-53]}. Collision between continents is not an instantaneous process^[1]. In the case of the Arabian/Zagros Basin, subduction of the original oceanic crust caused bending of the extensional parts of the continental crust. Owing to early collision, the extensional parts of the crust experienced inversion and thrusting as they continued to advance in the continental direction. During this process, the sedimentary environment gradually transitioned from marine facies to continental facies, with neritic and marine-continental transitional fluvial-delta sediments being deposited over submarine fans in remnant ocean basins. During the late period, under the continuous action of lateral compression stress from the ongoing collision, an orogenic belt developed and rose upon the side of the abducted continental crust due to superimposed thrusting. As a result, the crust thickened and was uplifted as a whole, ending neritic sedimentation. Terrigenous debris from the young mountain system then developed a huge, thick molasse formation^[9], leading to apparent asymmetry in the structure of the basin. On the side closest to the orogenic belt, structural deformation was strong. The sedimentary cover developed thrust fold fault zones, and structural deformation gradually weakened towards the direction of the continent. The structures in peripheral foreland basins, from near the orogenic belt to the slope, are generally a succession of thrust nappe belts, thrust fold belts, and fold belts^{[9, 54-55]}.

The underlying prototype basins of peripheral foreland basins are intracontinental growth rift basins and passive continental margin basins, both rich in oil and gas. In the late period, large-scale and zonally distributed structural reservoirs form due to compression and reformation of the forelands. The Zagros/Arabian Basin, which has the highest degree of oil and gas enrichment in the world^[52,53], experienced a rifting stage in the Cambrian and a passive continental marginal environment from the Early Paleozoic to the Eocene epoch of the Paleogene, when it lay at the southern margin of the Paleo-New Tethys Ocean.

There are five major confirmed hydrocarbon-generating horizons in the basin in the Cambrian, Silurian, Jurassic, Cretaceous, and Paleogene, dominated by type II organic matter with TOC values generally of 1%-12% and up to 25%. High-quality carbonate reservoirs are extensively developed, with large thickness, favorable physical properties, and multiple sets of high-quality regional cap rocks (predominantly evaporative salt strata). Numerous large-scale anticlines developed during the foreland compression period. So far, 213 large oil and gas fields have been discovered in these traps, making the basin the most hydrocarbon-rich sedimentary basin in the world^[52,53]. It is expected that, with the current trend towards unconventional oil and gas exploration and development, more tight oil and gas and shale oil and gas strata will be discovered in the near future^[56,57].

2.2.2.2. Back-arc foreland basins

Back-arc foreland (or retroarc) basins^[5], are main prototype basins. These are sedimentary basins developed by the closure of back-arc sea basins/oceanic basins (rifts, depressions, or small ocean basins) (Fig. 5c-5f), where one side of the unilateral type of basins, or both sides of the “bilateral” type, converge after compression and collision between island arcs and the adjacent continents. This accords with previous concepts, and examples include the Volga-Ural Basin^[58], the Timan-Pechora Basin^[59], the Western Canada Basin^[53], and the Burma Central Basin^[51] (Fig. 1). Structurally, back-arc foreland basins are located at the edge of abducted plates, with the entire basins being subjected to compression stress. Back-arc foreland basins have obvious asymmetry in structural deformation and sedimentary filling. The side of the basins closest to the island arcs is subjected to strong lateral compression, forming thrust fold belts. Near the thrust zone, there is wide-ranging subsidence. Deposition thickness is great, and coarse clastics are developed. Deformation of strata on the continental side is weakened, and deposition becomes thin^{[1, 9, 50]}. The basins are moderately hot, with a geothermal gradient of (19-33) °C/km^{[25, 53-59]}.

It should be added that although the passive continental margin and intercontinental continental rift are absent in the lower part of most back-arc rifts/depressions/small ocean basins at present, these two sets of strata are developed in the lower part of most back-arc foreland basins, which are also favorable strata for the development of hydrocarbon source rocks^[53,54,55]. This also proves to some extent that there are great differences in vertical superposition and overlap degree of prototype basins

Hydrocarbon accumulation conditions in this type of basins are excellent, principally because both the underlying passive continental margins and the central back-arc series basins themselves have satisfactory hydrocarbon-bearing conditions. Large-scale traps form in the foreland stage under compression and inversion, and multiple large oil and gas fields often form^{[53,54,55,56,57,58,59]}. In the Western Canada back-arc foreland basin, for example, there are depositional strata of four prototype stages: passive continental margin, back-arc rift, back-arc depression, and back-arc foreland (from bottom to top). The first three of these stages are mainly dominated by marine deposits, with five sets of high-quality source rocks, mainly consisting of type II organic matter with TOC values of 3%-33%. In the early period of compression and inversion of the foreland structures, coal-measure strata were developed following seawater withdrawal and they were dominated by type II organic matter with TOC values up to 13%. Several types of clastic and carbonate reservoirs developed. The regional cap rocks are shales and tight carbonate rocks. Faults, sand bodies, and multi- stage unconformities provide a network of migration pathways. During later compression and inversion, a hydrocarbon accumulation model consisting of piedmont thrust fold belt-foredeep wide and gentle fold belt-slope stratigraphic trap belt (bearing heavy oil and oil sand) developed from the orogenic belt to the continent. Conventional oil and gas resources are plentiful, with a wealth of unconventional resources (heavy oil, oil sand, tight gas, shale oil and gas, and coalbed methane) also present^[53].

Strike-slip faults can be developed by sliding action along plate boundaries or by faulted blocks in shear stress environments. They are also known as wrench faults^[1]. The nomenclature varies according to the position of the faults in the plate structure. In general, strike-slip faults intersecting the lithosphere or crust at plate boundaries are called transform faults. Strike-slip faults in plates developed in the crust are called strike-shift faults. Transverse strike-slip faults connecting main basement faults in continental thrust nappe structural zones are called transfer faults, and strike-slip faults in shallow adjustment zones are called tear faults^{[1, 60]}.

There are four principal characteristics of strike-slip faults and their associated sedimentary basins^{[1, 12, 60-64]}. (1) Strike-slip faults develop in structural zones in diverse plate structural positions (intraplate and plate margin) and regional stress environments (extensional and compressive) as consequences of the different balancing and adjustment roles played by shear stress. (2) The sizes of sedimentary basins associated with strike-slip faults vary enormously, from tens of square kilometers to a maximum of 290 thousand square kilometers. Since the basins can only be developed by strike-slip faults associated with certain dip-slip components, differences in component size produce basins on quite different scales. (3) Strike-slip pull-apart basins on a scale of over ten thousand square kilometers can only form on large-scale strike-slip faults in regional extensional environments (equivalent to the first half of the Wilson Cycle). The main reason for this may be that the activity scale of strike-slip faults is constrained by the regional compressive environment. (4) Strike-slip flexural basins can be developed by directional variations in strike-slip movements produced by the reversal and compression of regional stress fields in later-stage strike-slip pull-apart basins (equivalent to the second half of the Wilson Cycle).

2.3.1. Strike-slip pull-apart basins

Strike-slip pull-apart basins are sedimentary basins developed by strike-slip faulting in local extensional environments (Fig. 6a). They are also known as transtensional basins^[1]. They are primary prototype basins developed in shear stress environments, and the description here is consistent with previous studies. Examples are the continental Bongo Basin in Africa^[61] and the Ridge Basin on the American west coast^[62]. The basins generally have geometric shapes (fusiform, rhombus, wedge, etc.), enormous variations in scale (although they are mostly small), and high depositional rates. They often contain gigantic, thick sediments with many different sedimentary types from sea to land. They are “cold” basins, with geothermal gradients in the range of (23-26) °C/km. Negative flower structures and twist-compression reversal structures (mainly positive faults) develop widely^[61,62,63].

The larger the scale of the basin, the better the hydrocarbon accumulation conditions. The Bongo strike-slip pull-apart basin in Africa is an example. The basin area is 23.6 thousand square kilometers. Development of major source rocks was controlled by intensive faulting in the depression stage, producing a set of 500-1000 m thick dark lacustrine mudstone. Organic matter type is mainly Type II₁, with average TOC of 3.5%. Numerous sets of reservoirs developed, with medium-high porosity and permeability. These reservoirs occurred in sand bodies of the offshore subaqueous fans in steep slopes and the fan deltas in gentle slopes. Shale in the transgression stage developed effective seals. Traps are mostly found in faulted anticlines and faulted blocks, in which large oil and gas fields developed in the negative flower structures in transpressional reverse fault anticlines^[63]. Due to the generally high organic matter abundance in lacustrine shale, there is still considerable shale oil potential far from fault zones.

2.3.2. Strike-slip flexural basin

Strike-slip flexural basins, also known as transpressional basins^[1], are the sedimentary basins found in strike-slip structural zones and developed in local compressive environments (Fig. 6b). Consistent with previous descriptions, they are primary prototype basins developed in shear stress environments. An example is the San Joaquin Basin in central California, United States^[64]. This basin was a forearc basin in the Mesozoic. In the Cenozoic, positive flower structures were developed by dextral strike-slip at the western margin of the San Andreas Fault due to transformation from a forearc extensional environment to a compressive environment. From the Oligocene to the Early Miocene, the basin subsided rapidly due to flexural depression caused by structural loading, and then it was filled with marine sediments. Then there was a gradual transition to continental sediments, accompanied by compression and uplifting in the periphery. The geothermal gradient is inferred to be lower than 25 °C/km.

Due to limited compressive deformation in strike-slip flexural basins, they are of small scales with limited sedimentation so hydrocarbon bearing conditions are generally poor. However, if a basin is located in a large-scale transfer fault zone, like the San Joaquin Basin, prototype basins with underlying forearc marine sediments can be reconstructed by fault activities to provide good hydrocarbon accumulation conditions^[64]. Hydrocarbon accumulation conditions for unconventional resources are poor.

Through the analysis of the formation and evolution process of the primary and secondary prototype basins, it is found that the formation and superposition evolution of the prototype basins have fixed trajectories under different plate tectonic positions and different stress environments. The plate edge is mainly stressed by tension and compression, and the superposition evolution of the prototype basin takes the Wilson cycle as the cycle and repeats in a fixed track. Specific prototype basin can be developed in each stage of the cycle. For example, the peripheral foreland basin must follow the fixed development track of intracontinental rift, intercontinental rift, passive continental margin and peripheral foreland. After experiencing brief stretch tension in the early stage, the interior of ancient plate (craton) enters into long-term, stable and slow depression evolutionary stages due to the thermal subsidence. Sedimentary cyclicity is shown within a Wilson cycle, and there are gaps between different cycles. Apart from basins on small cratons being transformed into foreland basins during the terminal stage, the basins always stay in craton kind of prototype. Strike-slip pull-apart and strike-slip flexural basins may be developed in both plates and plate margins under shear stress. The former usually occurs in the first half of the Wilson cycle, and the latter generally develops from the former due to regional stress inversion, which is equivalent to the second half of the Wilson cycle.

Based on this study and the previous classifications, 483 major sedimentary basins around the world have been classified into 14 types of prototype basins (Table 1), taking the basin prototype developed by the most recent plate tectonic activities in each basin as the current basin type. The types of basins are: intracontinental growth rift, intercontinental rift, intracontinental aborted rift, passive continental margin, interior craton, back-arc rift, back-arc depression, small back-arc oceanic basin, forearc, trench, back-arc foreland, periphery foreland, strike-slip pull-apart and strike-slip flexural basins. This classification scheme has the following two implications. (1) More than 85% of the 483 basins in this study were developed by the superimposition and evolution of more than two types of prototype basins. The application of this classification scheme guarantees the unique identification of each type of basin, making it convenient for both general reference and practical application. (2) Since the evolutionary trajectories of the prototype basins are always consistent, the superimposition process of prototype basins can be deduced by inversion based on the current basin type. Underlying hydrocarbon accumulation conditions and their possible variations in every prototype stage can be analyzed scientifically. Taking the Zagros and Arabian basins as examples, the current basin type—peripheral foreland basin—is determined using this classification principle (the basins are superimposed following the trajectory: intracontinental growth rift-intercontinental rift-passive continental margin-peripheral foreland). Their hydrocarbon accumulation conditions in various sequences can be predicted by analogy; i.e. by analysis of the hydrocarbon accumulation characteristics of comparable rift basins and passive continental margin basins with high degrees of exploration and development. The method is to identify known analogues of possible development processes of fundamental conditions—source rocks, reservoirs, capping rocks, etc.—in early-stage rift basins and passive continental margin basins, combined with the influence of foreland compression and reversal, and apply them to reconstruct the reservoir development history. This approach will be helpful in guiding future exploration deployment to further discover reservoirs.

According to the above classification principles, the distribution characteristics of 14 types of sedimentary basins in the world have been made clear. So far, except for the three types of basins including intercontinental rift, ocean trench and strike-slip flexural basin, 1123 huge oil and gas fields have been discovered, with a total recoverable reserve of 5069 × 10⁸ t. By analogy with the hydrocarbon accumulation conditions of various basins with high exploration and development degree, the favorable exploration directions in the future have basically been defined (Table 1 and Fig. 1).

There are a total of twenty intracontinental growth rift basins around the world, mostly in the continental East Africa Rift System, the basin-ridge province in western United States, and the Gulf of Suez. The proportions of the number and reserves of discovered huge oil and gas fields are 0.61% and 0.22% respectively. Risk exploration potential is the greatest in the East Africa Rift System, particularly in the western branch of the Albert Rift, the Democratic Republic of Congo (King), the Tanganyika Rift, and the Malawi Rift. Intracontinental aborted rift basins (a total of thirty) are mostly found in Eurasia and Africa, including the West Siberia, Sirte, Bohai Bay, Songliao, the North Sea, etc. The proportions of the number and reserves of discovered huge oil and gas fields are 19.68% and 16.23%, respectively. The exploration potential of the West Siberia Basin is the greatest. The South Kara Sea area holds particular promise, with excellent prospects for conventional hydrocarbon risk exploration and fine exploration in the northern part of the sea, in deep strata underlying the Jurassic, and in basement burial hills in the onshore, central, and southern areas of the sea. The most promising target for unconventional hydrocarbon exploration and development is shale oil and gas in the Jurassic Bazhenov Formation. Conventional lithological reservoirs and unconventional shale oil in the Sirte Rift also offer good prospects. At present, only two intercontinental rift basins (the Red Sea and the Gulf of Aden) can be regarded as having fair exploration potential. Passive continental margin basins are primarily found in the Atlantic Ocean, Indian Ocean, Arctic Ocean, the periphery of the Gulf of Mexico and the southeastern margin of the Caribbean, with a total of 139 basins. The proportions of the number and reserves of discovered huge oil and gas fields are 26.09% and 19.04% respectively. This type of basin is relatively unexplored, but has widespread distribution and large potential. The risk exploration potential of these basins is the greatest in the offshore areas of East Africa, Argentina, Brazil, the eastern coast of the United States, the eastern coast of the Greenland Island, and on the Arctic Shelves. Ancient cratonic basins (a total of thirty-eight) are found in the centers of every continent, in East Siberia, Paris, Williston, Parana and elsewhere. The proportions of the number and reserves of discovered huge oil and gas fields are 3.65% and 1.70%, respectively. Risk exploration potential for conventional oil and gas is the greatest in East Siberia and the Zaire Basin. Exploration prospects for shale gas are good in the Upper Amazon and Parnaiba basins.

Trench and forearc basins are found in the periphery of the Pacific Ocean and the eastern margin of the Caribbean Sea. Only limited data are currently available, but nine trench basins (Aleutian, Peru-Chile, Mariana, etc.) have been preliminarily marked for exploration and development. A total of twenty-six forearc basins (offshore basins in Myanmar, the eastern Bay of Bengal, Santino and Talara on the western coast of South America, etc.) have been identified as promising targets. Hydrocarbon bearing conditions in these forearc basins are generally only fair but a few, like Talara, contain developed rifting sequences in forearc slopes with good hydrocarbon accumulation conditions. The proportions of the number and reserves of discovered huge oil and gas fields are 0.27% and 0.04%, respectively. In trench basins, there may only be good hydrocarbon accumulation conditions in those, like the Myanmar offshore basins, which transformed into part of a forearc basin in the late stage of evolution. A number of forearc basins along the western coast of Central and South America are considered to be promising targets, including the Santino, Sechura, Arauco, and others. Back-arc rift basins (a total of sixty-three) are mostly found on the western coast of the Pacific Ocean and in the eastern Caribbean Sea. These two types of basins have excellent petroleum conditions. The former one has proportions of the number and reserves of discovered huge oil and gas fields of 0.98% and 0.25%, respectively, and the latter one has proportions of the number and reserves of discovered huge oil and gas fields of 3.29% and 1.56% respectively. Future risk exploration targets are bedrock buried hills, deep water gravity currents, and biological reefs in a series of basins in the western Pacific Ocean. A series of basins in the Caribbean are also considered to have some exploration potential. The small back-arc ocean basin mainly includes five basins in the western Pacific Ocean, namely the Sea of Okhotsk, the Sea of Japan, the Andaman Sea and the South China Sea. Large oil and gas fields were only found in the Andaman Sea basin, accounting for 0.18% and 0.04% of the total number and reserves, respectively, with good exploration prospects.

Peripheral foreland basins are chiefly distributed in the southern zone of the Tethys tectonic domain, which includes Cuba North Island, West and North Africa, Middle East, South Asia and other areas, with a total of twenty-five basins. This type of basin has excellent hydrocarbon accumulation conditions, and the proportions of the number and reserves of discovered huge oil and gas fields are 24.13% and 48.44% respectively. The largest quantities of both conventional and unconventional oil and gas resources are to be found in the huge Arabian and Zagros basins. The most promising exploration targets are deep Paleozoic plays in the Arabian foredeep depression and slope areas and in the Zagros fold belt, followed by Silurian shale oil and gas in the West and North Africa. The sea area around Cuba North Island is also worthy of investigation. Back-arc foreland basins are the sedimentary basins with the widest distribution on land, primarily in the western margin of the American Continent, the northern zone of the Tethys tectonic domain, and the western margin of the Ural orogenic belt. There are 118 basins of this type. They have been proved to have excellent geological conditions for the formation of large oil and gas field groups, and the proportions of the number and reserves of discovered huge oil and gas fields are 21.02% and 21.03%, respectively. However, generally these basins have already undergone extensive conventional oil and gas exploration. Future exploration targets are structural traps in thrust folding zones, subtle traps in deep foredeep depressions, and low-amplitude structural traps in slope zones. There are good exploration prospects for heavy oil, oil sands, and shale oil and gas.

Based on the available data, there are only 14 identified large-scale strike-slip pull-apart basins, including Bongor Muglad, and east of the Niger basin, which are a series of basins located in the west African region. They have been confirmed to have the geological conditions of forming large oil and gas fields. The proportions of the number and reserves of discovered huge oil and gas fields account for 0.09% and 0.01%, respectively, the less explored basins such as Southern Chad have better risk exploration prospects. At present, only one basin in central California, namely The SAN Joaquin Basin, can be identified as the strike-slip flexural basin, which confirms the poor hydrocarbon accumulation conditions during the strike-slip flexural stage.

Since the Precambrian, the superimposed development process of global prototype basins has been entirely controlled by plate tectonics, and has repeated in accordance with the Wilson Cycle. The superimposed evolution of prototype basins in each Wilson Cycle period has a fixed trajectory. 14 types of prototype basins can be developed in each period. Of the 483 existing sedimentary basins in the world, more than 85% are developed by superposition and evolution of more than two types of prototype basins. Every prototype basin has its own unique tectonic-sedimentary system, with distinctive source rocks, reservoirs, cap rocks, and other hydrocarbon bearing conditions. Later superimposed prototype basins altered the hydrocarbon accumulation conditions of earlier prototype basins, resulting in the formation of entirely new petroleum systems.

Based on the controlling role of global plate tectonics on prototype basins, following the principles of the Wilson Cycle, the prototype basin developed by the most recent plate tectonic activity in every basin is defined as its current type of basin. 14 types of sedimentary basin have been distinguished, including intracontinental growth rift, intracontinental aborted rift, intercontinental rift, passive continental margin, interior craton, trench, forearc rift, back-arc rift, back-arc depression, back-arc small ocean, peripheral foreland, back-arc foreland, strike-slip pull-apart, and strike-slip flexural. This classification scheme ensures identification of the unique characteristics of each type of sedimentary basin and is convenient for both general reference and for practical application in the petroleum industry. It can also be used to infer the superimposition process of basins through inversion from the current type of basin, supporting scientific analysis of the basic hydrocarbon accumulation conditions of each preceding prototype basin and possible subsequent changes, thus providing a method for evaluation of the hydrocarbon potential of any sedimentary basin.

The development degree of the prototype basin during the early stage is very important for hydrocarbon accumulation in the present basin. Take the Zagros foreland basin, which has the highest degree in global oil and gas enrichment, as an example. It has been confirmed that a total of 5 sets of main source rocks are developed in the Cambrian, the Silurian, the Jurassic, the Cretaceous and the Paleogene system. The Cambrian prototype basin was developed during the rift stage. The other four sets of source rocks were developed in the passive continental margin stage, and the main carbonate reservoir and evaporation halite cap rocks were developed in the passive continental margin stage. The greatest contribution of the foreland stage is the formation of large number of structural traps, with large size of individual units caused by intense compression. Therefore, only by making clear whether the hydrocarbon accumulation conditions such as hydrocarbon generation, reservoir and cap are well developed in the prototype basins at each early stage, can we scientifically evaluate the hydrocarbon bearing prospects of the basins at present.