An Analysis of Silurian Paleo–Tethys Hydrocarbon Source Rock Characteristics in North Africa, the Middle East, and South China

Abstract

In this study, we elucidate the genesis and distribution patterns of Silurian hot shale hydrocarbon source rocks by utilizing a comparative analysis of the evolutionary characteristics of plate tectonic activity in the Paleo–Tethys Ocean and the sedimentary filling characteristics of key basins in North Africa, the Middle East, and South China. We propose an explanation for the sedimentary genesis of world-class Silurian hydrocarbon source rocks in the Paleozoic craton basin of the ancient Tethys tectonic domain. This is achieved by scrutinizing the plate tectonic activity and evolution of the ancient Tethys Ocean and combining these findings with the paleotectonic sedimentation background of North Africa, the Middle East, and South China. Additionally, we compare Silurian hydrocarbon source rocks from these regions. The deep-water stagnant environment of the land shelf favors the preservation of organic matter, thereby forming high-quality hydrocarbon source rocks. Conversely, the shallow-water body of the land shelf is more turbulent, thus resulting in the poorer preservation of organic matter and, consequently, lower-quality hydrocarbon source rocks.

1. Introduction

In recent years, the exploration and study of marine shale gas have become a key research direction in the field of oil and gas [1,2]. The formation and distribution of hydrocarbon source rocks are central to petroleum geology research [3,4,5,6]. Against this backdrop, this study aims to explore the genesis and distribution patterns of widely distributed graptolite shale hydrocarbon source rocks in Paleozoic Silurian shelf facies in the North Africa–Middle East–South China region. The primary issues of this study revolve around clarifying the genesis and distribution characteristics of Silurian hot shale hydrocarbon source rocks [7,8]. Based on the data of the North African basins, the achievements of the “Twelfth Five-Year Plan”, and previous research findings, analyses are conducted using core, well-logging, seismic, and laboratory analytical data. Through a comprehensive analysis of the characteristics of the Silurian hydrocarbon source rocks in the “North Africa–Middle East–South China Plate” region, this research focuses on key geological issues, such as the tectonic–sedimentary infill evolution of significant basins in the Paleo–Tethys Ocean and the formation and evolution patterns of hydrocarbon source rocks. These regions, located at the northern part of the continent Gondwana and the southern margin of the Paleo–Tethys Ocean during the Silurian period, provide a unique geological background for studying the formation and distribution of hydrocarbon source rocks [9,10,11]. Under nearly identical tectonic movements, these regions have positively impacted the mobility of hydrocarbon source rocks [12,13]. Through a systematic analysis of these key geological processes, this study reveals their impact on the development and characteristics of oil and gas reservoirs, providing a theoretical basis and geological model for oil and gas exploration.

Through the analysis of the tectonic positions of North Africa, the Middle East, and South China, and in conjunction with a comparative analysis of global sea level changes and Silurian characteristics [14], this study aims to both reveal how these regions, under a similar ancient plate tectonic backdrop, experienced comparable sea level changes and explore how these changes influenced the sedimentary infill characteristics of the basins [15,16]. Furthermore, we will also conduct a detailed analysis of the organic matter type, gamma-ray characteristics, and total organic carbon (TOC) content of the Silurian hydrocarbon source rocks in North Africa, the Middle East, and South China to assess the similarity of their depositional origins [17].

The black shale of the shelf facies, which is rich in fossils, such as graptolites, and formed in a deep-water shelf-anoxic environment [18], is widely distributed in the Paleozoic “Pan-craton basin” in North Africa and the Middle East. In North Africa, apart from the coastal–delta facies that developed in the peripheral areas north of the Eglab–Hoggar Shield, the shallow marine shelf facies are widespread across vast regions of the Tindouf, Timimoun, Triassic/Ghadames, Murzuq, and Sirt Basins located in the central and western parts of the Sahara Platform [19,20].

In the Middle East’s Arabian Platform [21], aside from coastal–delta facies that developed on the eastern periphery of the Arabian Shield, shallow marine shelf facies are prevalent across vast areas of the Western Arabian, Central Arabian, and Rub’ al Khali basins. In the western part of the Yangtze Platform in South China, delta–coastal facies have developed around the Sichuan Uplift and the Guizhou Uplift [22]. However, in the eastern regions of Sichuan, Hubei, Hunan, and Jiangxi, a vast area exhibits the development of shallow marine shelf facies. Moreover, the developed deep-water shelf environments often manifest as shelf depressions (or basins) with stagnant water conditions [23]. The weak hydrodynamic energy and anoxic conditions in these stagnant waters ensure the excellent preservation of deposited organic matter [24].

The results of this study not only deepen our understanding of the characteristics of hydrocarbon source rocks in the Paleo–Tethys Ocean region but also hold significant reference value for global research on Silurian hydrocarbon source rocks [25]. Through the analysis of the characteristics of Silurian hydrocarbon source rocks in the Middle East, North Africa, and South China, this study further confirms the existence of world-class hydrocarbon source rocks of shallow marine shelf origin in the “Pan-Cratonic Basin” of this region during the Silurian period. This provides a new perspective on the distribution and genesis of Silurian hydrocarbon source rocks on a global scale [26,27].

2. Geological Setting

During the late Ordovician to early Silurian period, South China, Qiangtang, and Lhasa were connected with Gondwana, marking the closure of the Proto-Tethys Ocean [14]. The Paleo–Tethys Ocean formed between Gondwana and the Laurasia and Siberian Plates. Subsequently, it entered a period of cracking and continuous expansion, with the expansion of the ocean ridge being significant [11]. During this time, the “Pan-Cratonic Basin” of the Sahara Platform in North Africa, the Arabian Platform, and the South China Block in China were all located in the northern part of Gondwana and near the southern edge of the Paleo–Tethys Ocean (Figure 1).

Due to the consistent geotectonic background and the rise in global sea levels during the Early Silurian, a large-scale marine transgression occurred following the decline in glacial sea levels in the Late Ordovician [28]. Sea water invaded a large portion of the shelf in the northern part of Gondwana, causing the Sahara in North Africa, Arabia in the Middle East, and the Yangtze Plate in South China to enter the largest marine transgression period in the Early Silurian [29]. The vast shallow sea and warm and humid climate were conducive to the massive reproduction of marine organisms. At the same time, abundant organic matter and nutrients caused via upwelling resulted in the widespread deposition of black shale hydrocarbon source rocks in the area where upwelling occurred [30]. The lithology of the hydrocarbon source rocks in the Ludan stage of the Lower Silurian is mainly dark-gray to black mud shale and/or calcareous mud shale [31]. The content of biological fossils, especially graptolites, is rich. The dark graptolite shale is all “hot shale” [32], with high radioactivity and a natural gamma well logging response generally greater than 150API, exhibiting high gamma characteristics. The types of organic matter are mainly types I and II kerogen [33]. More than 9% of the world’s recoverable oil and gas reserves come from this set of hydrocarbon source rocks in the Silurian system, thus being considered “world-class” hydrocarbon source rocks [34].

3. The Plate Tectonic Activity and Evolution of the Paleo–Tethys Ocean

Plate tectonic activity and its evolution control the type, distribution, and structural sedimentary filling evolution of global sedimentary basins, thereby determining the characteristics and abundance of mineral resources and fossil energy in the basin [35,36]. Using plate tectonic activity as the entry point for this research, the structural evolution and sedimentary filling characteristics of the Paleozoic cratonic basin are clarified in the Paleo–Tethys structural domain of the North Africa–Middle East–South China region through analyzing the evolution of the Paleo–Tethys Ocean and its plate convergence and divergence. This is conducted to determine the characteristics, development distribution [37], and oil and gas occurrence patterns of the world-class hydrocarbon source rocks in the basin of the Silurian System [38]. Global plate activity is believed to have generally experienced the following evolutionary stages (Figure 2).

3.1. Proto-Tethys Ocean Stage

After the breakup of Rodinia at the end of the Neoproterozoic Era, the Pannotia (Greater Gondwana) formed [10], which essentially encompassed the major global plates. During the mid–late Neoproterozoic Era, Rodinia began to split. The ancient craton’s split was centered around Laurentia [9], with dispersion occurring between Laurentia and South China–Australia–Antarctica–Siberia, between Siberia and North China, and around areas between East and Northwest Africa, thus forming multiple expansion ridges. Around 760–700 Ma, the Baltica Plate and the Siberian Plate successively broke away from Pannotia, forming the Apites Ocean and the Ural Ocean. By the end of the Neoproterozoic Era, the Pan-African orogeny led to the final formation of Gondwana [39], which primarily included plates like South America, Africa, Madagascar, India, Arabia, East Antarctica, and Australia. The major landmasses of China were located on the northeastern edge of Gondwana. Gondwana and the northern landmasses mainly formed passive continental margin basins, with intracratonic and foreland basins forming within Gondwana [40]. By this time, the initial forms of the craton basins in the Middle Eastern Arabian Platform and the North African Sahara Platform had already taken shape. From the end of the Precambrian to the early Cambrian (around 560–510 Ma), after the southern landmasses formed Gondwana with Africa at its core through the Pan-African orogeny, ancient continents like Gondwana, Old Europe, and Old China were separated by oceans [41]. Laurentia broke away from Pannotia. At this time, the ancient Asian Ocean separated Gondwana from Siberia, and around the periphery of Siberia and the Baltica Plate, the narrow Kipchak–Tuva–Mongolia island arc appeared during the Cambrian.

3.2. Development and Evolutionary Stage of the Tethys Ocean

During the early to middle Early Paleozoic, plate activity was distinct, with passive continental margins and prototype intracratonic basins forming around drifting landmasses [42]. By the Middle Cambrian to Early Ordovician, the crust of the ancient Asian Ocean began to subduct beneath eastern Gondwana [43]. During the transition between the Cambrian and Ordovician periods, continents experienced their maximum dispersion, with the formation of Gondwana and the Laurentian, Baltica, and Siberian Plates. However, the North African and Arabian Plates remained attached to Gondwana, and vast passive continental margins and cratonic platforms developed globally [44]. Against the backdrop of the global ridge expansion, global sea levels continuously rose during the Cambrian, with the expansion of the Rheic Ocean along the northern edge of Gondwana (around 500 Ma). By the Early Ordovician, the Apites, Ural, Rheic, and Proto-Tethys Oceans formed between major continental and Chinese blocks, such as the South China, Tarim, and Qiangtang Blocks. Some scholars believe that, accompanying the breakup of Rodinia in the late Precambrian, the Proto-Tethys Ocean formed between the Siberian and Baltica Blocks and the Kazakhstan and Gondwana continents, persisting until the Devonian [45]. During this stage, the Proto-Tethys or Rheic Ocean between the Baltica and Siberian Blocks connected with the ancient Asian Ocean, situated between the Kazakhstan Block and the Siberian Block, and between the Tarim, North China, and South China Blocks, also referred to as the Ancient Asian–Proto-Tethys Ocean. During the Early to Middle Ordovician, landmasses drifted northward, approaching the equatorial region [46]. With the warming climate, the first extensive marine transgression occurred globally. The clockwise rotation of the Ordovician Plate caused the southern end of Gondwana to enter the ancient Antarctic region, resulting in the appearance of the Late Ordovician ice age [47]. The aforementioned plate tectonic evolution determined the “Pan-Cratonic Basin” development around the Proto-Tethys Ocean on the Middle Eastern Arabian Platform and the North African Sahara Platform.

3.3. Plate Convergence and Development and Evolution Stage of the Paleo–Tethys Ocean

In the Early to Middle Ordovician, the Avalonia landmass broke away from Gondwana and continued to drift northward, subducting obliquely toward the Baltica Plate, while the Iapetus Ocean Basin began to contract [10] (Figure 2). By the Late Ordovician to Early Silurian, the Rhine Ocean Basin continued to expand, and Avalonia collided with the Baltica Plate in a strike–slip manner, closing the Tornquist Ocean Basin between them [48]. The expansion of the Rhine Ocean and the reduction in the size of the Iapetus Ocean simultaneously occurred, and after the collision of the Baltica Plate and Avalonia, they collectively subducted toward the Laurentian Plate. Around the Ordovician period (approximately 460 Ma), Gondwana began to rotate clockwise. The adjustment of the rotation direction was accompanied by the retreat of the magmatic arc on the eastern edge of East Gondwana (Australia–East Antarctica), leading to the opening of the Pacific Ocean margin. The clockwise rotation of Gondwana also caused a series of landmasses (such as Tarim) to break away from the western side of East Gondwana [49]. Moreover, South China, Qiangtang, and Lhasa were sutured to Gondwana, and the former Tethys Ocean was closed.

In the Silurian, other land masses except Gondwana began to converge, in which the Paleo-Atlantic Ocean closed and formed a foreland basin around the present-day Caledonian Mountains in Europe and the Appalachian Mountains in North America [50]. The presence of a spreading ridge is obvious on Gondwana, the Rauwolf Plate, and the Siberian Plate during the formation of the Paleo–Tethys Ocean. In the Middle and Late Silurian, the Apethyan Ocean closed (the western section closed at about 480–440 Ma, and the eastern section closed at about 440–400 Ma). The collision of the Laurentian Plate, the Baltic Plate, and Avalonia in the Silurian led to the formation of the continent of Rauhou [51]. During the Silurian–Permian (ca. 443–250 Ma), the Laurentian, Siberian, Kazakhstan, and Tarim Plates, with their peripheral island arcs and landmasses, continued to move and converge toward the mid-latitudes of the Northern Hemisphere. By the Middle Devonian, Rauhou was surrounded by a subduction zone, and the north-dipping subduction zone formed the Rhine–Hercynian back-arc basin in southern Europe. The Siberian Plate, on the other hand, after rifting from Rodinia, was characterized by a continuous northward drift (by ca. 250 Ma, it had reached ca. 65° N) until the Late Carboniferous addition of Pangaea. During the Silurian–Late Paleozoic, the Siberian Plate underwent continuous clockwise rotation, and the formation of Carboniferous Central Asian horseshoe tectonics was closely related to the clockwise rotation of the Siberian Plate [52]. Eventually, the northern plate group collapsed in the Late Paleozoic to form Laosia, with the successive closure of the Ural Ocean, the Rhineland Ocean (closed during the Carboniferous), and the western section of the Paleo-Asian Ocean. During the period of approximately 320–310 Ma, the clockwise rotation of Gondwana caused a collision orogeny between the South American–North African Plate at its northern margin and the Laoya continent in the north, forming the Hercynian orogenic belt [53]. Paleomagnetic studies have shown that during the northward drift of the Arabian Plate in the Carboniferous–Permian, a large clockwise rotation occurred, and during the period of 350–250 Ma [54], the Arabian Plate rotated clockwise at an angle of about 40°, and it has been hypothesized that at about 300 Ma [22], a mantle super subduction flow or cold mantle column appeared in the Central Asian region, with the cold mantle column causing the multidirectional subduction of the Paleo-Asian Ocean Basin and the Paleo–Tethys Ocean Basin, which was then closed [55].

The paleoplate tectonic background has an important influence on the formation and evolution of the basin [56]. Through the study of the Paleo–Tethys tectonic domain, it is found that the Silurian North Africa–Middle East–South China Plate is located in the northern part of Gondwana and along the southern edge of the Paleo–Tethys, exhibiting similar paleoplate tectonic backgrounds and, thus, developmental characteristics among the hydrocarbon source rocks. This lays an important foundation for studying the Silurian hydrocarbon source rock formation, distribution, and preservation [57].

4. Tectonic Evolution and Sedimentary Filling of the Basin

Based on an in-depth analysis of the database of the North Africa–Middle East–South China Basin and the data from the 12th Five-Year Plan, this study comprehensively investigates the paleogeographic distribution, superposition structural pattern, tectonic evolution, and sedimentary filling process of this basin group [58]. In particular, it is emphasized that the tectonic evolution and sedimentary filling process of the basin have a significant controlling effect on the formation, distribution, and enrichment of hydrocarbon resources in the basin.

4.1. Basin Tectonic Evolution

The Pan-African Movement (PAM) was a Precambrian–Cambrian tectonic movement across the African continent and Gondwana. This crustal movement was primarily characterized by tectonic–thermal events [59]. It resulted from the collision of a series of micro-plates, forming the stable Precambrian crystalline basement of the large “Pan-Cratonic Basin” in the Middle East–North Africa, which is clearly exposed in the Arabian Shield in the Middle East and the Hoggar Shield in southern Algeria in North Africa (Figure 3).

The North African Craton Basin has a roughly similar tectonic evolution history. Overall, the tectonic evolution of the North African Craton Basin development area can be divided into three major tectonic evolution stages, namely, the Paleozoic Pan-Craton, the Mesozoic Depression, and the Cenozoic passive terrestrial basin [60] (Figure 4). The tectonic evolution process of the basin is discussed using the Triassic Basin, where the key research area (HBR block) is located, as an example. In the Triassic Basin, the tectonic evolution, which is similar to that of the Saharan Plateau Sedimentary Basin, mainly went through five tectonic stages, namely, Pan-African, Taconic, Caledonian, Hercynian, and Late Alpine, and the tectonic movements of the different folds in each tectonic stage exerted different degrees of influence and modification on the basin, resulting in the basin’s current tectonic appearance.

Influenced by multiple tectonic cycles, the sedimentary basins in North Africa exhibit a three-layered superimposed geological structure [61]. During the Paleozoic Era, the Pan-craton basin had a wide sedimentary fill range. During the Mesozoic and Cenozoic Eras, the sedimentary range of the intracontinental depression basin continuously narrowed, and the sedimentary center’s position kept shifting, resulting in the basin showing a vertical migration and superposition characteristic (Figure 5). The typical characteristics of the basin include the following:

During the Cambrian–Carboniferous cratonic intracontinental depression basin phase, equivalent to the first structural layer, the sedimentary strata’s thickness is relatively uniform. Two sets of hydrocarbon source rocks, the Silurian and Devonian, are developed. In the Triassic/Gueddames and Illizi Basins, a complete source–reservoir–seal combination is developed.

After the Carboniferous, the Hercynian orogeny caused differential uplift and subsidence, leading to significant erosion in uplifted areas such as the ancient Hassi Messaoud Uplift and Dirhemout Uplift. The earlier sedimentary strata are either incompletely preserved or have a limited distribution range.

Above the Hercynian unconformity, the Triassic–Jurassic intracontinental sandstone and evaporite mudstone are deposited, belonging to the second structural layer of this region. Its distribution range is significantly smaller than the Paleozoic, mainly located in the central–western Triassic Basin.

During the Cretaceous–Cenozoic period, the North African intracontinental depression basin deposited the third structural layer with the smallest distribution range, and the sedimentary center shifted.

The central and upper Yangtze regions in South China are delineated by the Huaying Mountain, Qiyue Mountain, and Baojing–Cili Fault Zones. This demarcation gives rise to the Sichuan Basin, the Chongqing Eastern Barrier-style Fold Belt, and the Hunan–Hubei Western Trough-style Fold Belt.

The central and upper Yangtze regions have a unified crystalline basement, and there must be a specific connection between their sedimentary and tectonic evolution characteristics and their shale gas reservoir conditions and enrichment patterns. After a comprehensive comparison of the geological features in the central Sichuan, eastern Chongqing, and western Hunan–Hubei regions, the stratigraphic characteristics are as follows:

In the central Sichuan area, strata from the Archean to the Quaternary periods are developed.

In the eastern Chongqing area, strata from the Archean to the Jurassic periods are present.

In most of the western Hunan–Hubei area, strata from the Archean to the Lower Triassic are developed, while in some parts, strata range from the Upper Triassic to the Cretaceous periods, as seen in the Yuanma Basin [62].

The vertical geological characteristics are as follows: from the Paleozoic to the Lower Triassic, marine carbonate rocks developed, and from the Middle Triassic to the Cenozoic, continental clastic rocks were present.

From a regional perspective, the geological history of the Lower Paleozoic shows significant variations. Moving from east to west, the Cambrian and Ordovician strata gradually decrease in thickness. The Silurian strata are thickest in the Yudong area, moderately thick in the Xiang-E-West area, and absent in the central Sichuan area. In the central Sichuan area, the Mesozoic and Cenozoic strata are the most developed, the most recent being the Quaternary. In the Yudong area, the most recent strata are from the Upper Jurassic, while in most of the Xiang-E-West area, the most recent strata are from the Lower Triassic, with only some areas exhibiting the most recent strata from the Cretaceous (Yuanma Basin). This indicates that during the Cambrian and Ordovician periods, the sedimentary center was located west of the Xiang-E-West area, while the central Sichuan area was far from this center. By the Silurian period, the sedimentary center had shifted to the Yudong area, and the ancient uplifted regions in central Sichuan experienced erosion. From the Mesozoic to the Cenozoic, moving from east to west, the strata became increasingly recent, with the sedimentary center located in the Sichuan Basin.

From the analysis above, the similarities and differences in the structural styles of the North Africa–Huanan Basins are due to the differences in their superimposition patterns. These patterns control and influence the preservation and distribution of hydrocarbon source rocks in oil and gas combinations, the relationship between generation, storage, and cap rock combinations, and the differences in the patterns of hydrocarbon accumulation in oil and gas reservoir combinations.

4.2. Basin Sedimentary Filling

The sedimentary filling and evolutionary processes of basins are shaped by a blend of diversity and uniformity in their depositional history, alongside the influence of basin tectonic activities, structural evolution, and sea-level changes. These factors collectively dictate the sedimentary filling and evolutionary patterns within basins, highlighting the intricate interplay between geological processes and environmental conditions in shaping basin development [63].

The sedimentary basin in the North African Craton, such as the Triassic Basin, underwent Pan-Cratonic sedimentary filling during the Paleozoic Era, depositing strata from the Cambrian, Ordovician, Silurian, Devonian, and Carboniferous periods. Similar to the entire Sahara Platform, the basin was profoundly influenced by the Caledonian orogeny, resulting in an uneven uplift [64]. Earlier sedimentary layers experienced varying degrees of erosion, leading to a widespread absence of Permian strata in the basin (Figure 5). During this sedimentary period, the primary developments were marine facies and transitional marine–continental facies, which collectively exhibited six transgressive–regressive sedimentary cycles.

During the Cambrian to Early Ordovician period, the basin was primarily characterized by tensile rupture rifts. During the Cambrian, extensive fluvial siliceous sandstone deposits were formed in the basin. During the Early Ordovician, a marine transgression from Morocco to the east led to the deposition of a set of marine anoxic mudstone strata (Gassi mudstone). By the late Early Ordovician, a marine regression occurred, resulting in the deposition of shallow marine quartz sandstone, marking the first transgressive–regressive cycle from continental to marine in the Paleozoic Era.

In the Middle Ordovician, the basin experienced another marine transgression, resulting in semi-deep marine Azzel mudstone deposition. During the Middle–Late Ordovician, a second marine regression occurred, leading to shallow marine clastic sandstone deposition in the early Late Ordovician, forming the basin’s second marine transgression–regression sedimentary cycle in the Paleozoic Era. In the Late Ordovician, as the climate cooled, glaciers became widespread, causing sea levels to drop and leading to the deposition of low sea level glacial clastic rocks in the Paleozoic. Accompanied by an early Silurian marine transgression, reaching its maximum transgression, extensive shelf mudstone was deposited over the glacial sediments—Silurian marine radiolarian shale was widely deposited, which became an important (world-class) hydrocarbon source rock for the North African basin.

In the late Silurian, influenced by the Caledonian orogeny, there was a marine regression, leading to the deposition of siliceous clastic sandstone, marking the Paleozoic’s third marine transgression–regression sedimentary cycle. During the Early to Middle Devonian, the basin experienced its fourth sedimentary cycle in the Paleozoic Era, forming the primary hydrocarbon source rocks in the Gudmis and Iliz Basins. The Upper Devonian to Lower Carboniferous saw the development of the fifth sedimentary cycle composed of marine transgression–regression clastic rock deposition. In the Middle to Late Carboniferous, the basin formed its sixth sedimentary sequence of clastic rock deposition due to marine transgression–regression (Figure 6). During the Mesozoic depression stage, the basin primarily developed terrestrial facies sedimentation interspersed with marine facies sediments.

During the early Sinian period, the continental crustal basement along the southeastern edge of the central and upper Yangtze regions underwent extension. By the middle of the Sinian period, the central and upper Yangtze regions transitioned into a stable passive continental margin. Entering the Early Cambrian, continental rifting intensified. The Niutitang Formation developed with thick layers of black carbonaceous shales throughout the region, marking the first set of hydrocarbon source rocks in southern China.

From the Late Ordovician to the Silurian, the Caledonian orogeny intensified, leading to the emergence of several uplifts in the central and upper Yangtze regions, such as the Jiangnan, Qianzhong, and Chuanzhong Uplifts. Surrounded by these uplifts, the central Yangtze area formed a foreland basin (Figure 7).

During the Early Silurian period, the Sichuan Basin in South China extensively developed deep-to-shallow shelf sedimentary environments. Controlled by sedimentary facies, the region deposited thick, dark, organic-rich mud shales [65]. The lithology of the deep water shelf subfacies mainly consists of radiolarian-rich carbonaceous graptolite shales, while the shallow-water shelf subfacies primarily comprise carbonaceous siltstone mudstones, graptolite shales, and silty mudstones.

Following the Middle Silurian, the Caledonian orogeny intensified, causing uplift and erosion in the central and upper Yangtze regions, leading to sedimentary discontinuity [66]. From the Devonian to the Early Carboniferous, most of the central Yangtze area was uplifted due to tectonic movements. From the Late Carboniferous to the Early Triassic, the central and upper Yangtze regions were under the extensional background of the expansion of the Paleo–Tethys Ocean. By the end of the Middle Triassic, the Yangtze Plate and the North China Plate converged and sutured, completing the north–south amalgamation of the Chinese mainland. After the Late Triassic, the central and upper Yangtze regions entered a phase dominated by foreland basins. By the end of the Middle Jurassic, the Xuefeng Uplift further squeezed and uplifted, causing significant subsidence to its northwest side. The sedimentary center shifted westward to the central Sichuan area, solidifying the Sichuan Basin’s basic structure and stably depositing continental molasse. Moreover, uplift and erosion occurred in the eastern Chongqing and western Hunan–Hubei regions, with only lacustrine clastic rocks deposited in the Yuanma Basin.

From the perspective of sedimentary infilling, the Silurian period in the North Africa–Middle East–South China region exhibited similar sea level changes. Overall, they manifested a single primary cycle of sea level change. Accompanied by the rise and fall in sea levels during the Silurian sedimentary infilling process in the basin, extensive marine and deep-to-shallow shelf sedimentary environments developed within it. In the deep water shelf environment, planktonic organisms, primarily bacterioplankton and algae, thrived. The oxygen-rich photic zone in shallow waters was conducive to the proliferation of planktonic algae, ensuring high paleoproductivity. This environment guaranteed the development of high-quality hydrocarbon source rocks for oil and gas combinations.

4.3. Hydrocarbon Source Rock Conditions

The Triassic Basin is primarily characterized by two dominant hydrocarbon source rocks: Upper Devonian dark mudstone and Lower Silurian graptolite shale [67]. Additionally, there is a secondary hydrocarbon source rock from Ordovician dark mudstone. These three hydrocarbon source rocks are widely and consistently distributed throughout the basin (Figure 8).

The Ordovician dark mudstone in the basin primarily consists of types I–II organic matter with a relatively low total organic carbon (TOC) content, categorizing it as a medium-grade hydrocarbon source rock. In contrast, the Upper Devonian hot shale and the Lower Silurian Tanezzuft graptolitic hot shale exhibit a more consistent distribution. The Tanezzuft hot shale from the Lower Silurian is a principal hydrocarbon source rock in Algeria. Remarkably, 80–90% of the hydrocarbons in the North African Paleozoic Era originate from this formation [70]. This hot shale, deposited after the Late Ordovician ice age, is black shale, resulting from the most extensive marine transgression. It represents a deep shelf anoxic sedimentation characterized by dark, highly radioactive graptolitic mudstone, globally recognized as a premium hydrocarbon source rock (

Table 1. Characterization of hydrocarbon source rocks in the Triassic Basin.

Hydrocarbon Source Rock	Hydrocarbon Source Rock Distribution	Lithology	Organic Matter Type	Organic Carbon Content	Hydrogen Index (HI)
Devonian hydrocarbon source rock	Ghadames Sub-Basin	Dark argillaceous shale	Types I and II kerogen	8~14%
Silurian hydrocarbon source rock	Oued Mya Sub-Basin	Black graptolite shale	Type I kerogen	3~20%	60 mg/g
	Ghadames Sub-Basin	Black graptolite shale	Types I and II kerogen	1~17%	600 mg/g
Ordovician hydrocarbon source rock	Oued Mya Sub-Basin	Dark mudstone	Types I and II kerogen	0.37~0.53%	305.7~378.4 mg/g

). This hydrocarbon source rock can reach a thickness of up to 100 m, with an average thickness of 50 m, spanning an area exceeding 20,000 km². The organic matter in this rock is primarily of types I–II 1 kerogen, with a TOC ranging from 1% to 17%, peaking at 26.2%. Different structural units exhibit variations in organic richness. For instance, the TOC in the Oued Mya Basin ranges from 3% to 10%, while in the Hassi Messaoud uplift, it varies between 1% and 17%, with the highest concentration in the Tidikelt dome reaching 20%. The Lower Silurian formation is rich in organic content, highly evolved, and has a significant hydrocarbon generation potential, typically exceeding 60 kg/t, making it an excellent-to-superior hydrocarbon source rock. Influenced by tectonic movements, the maturity of the hydrocarbon source rock, and hydrocarbon expulsion efficiency, the TOC content gradually increases from the southern to the northern parts of the basin. However, some of the Lower Silurian hydrocarbon source rocks might have been eroded in uplifted areas. Previous studies have indicated that the effective hydrocarbon generation and expulsion from the Lower Silurian hydrocarbon source rocks in the Hassi Messaoud Uplift began in the Late Jurassic, peaking in the Late Cretaceous to Neogene. In terms of regional organic maturity, the vitrinite reflectance (Ro) in the Timimoun Basin ranges from 1.0% to 4.0%. In the Oued Mya Basin, the Ro varies between 0.5% and 1.3%, with the basin’s center reaching up to 1.5%. The Hassi Messaoud Uplift has an Ro of 0.8% to 1.1%. These parameters collectively indicate that the organic matter in the Lower Silurian hydrocarbon source rock has matured and is in a phase of extensive hydrocarbon generation.

During the Early Silurian period, the lithological profile of the Longmaxi Formation in the Sichuan Basin of South China is characterized by deep-water shelf deposits in the lower part, with a higher content of graptolites, predominantly dominated by Climacograptus [71]. Pyrite is locally enriched in thin layers and bands. The upper part is characterized by shallow-water shelf deposits with fewer graptolites, mainly consisting of single graptolites. Pyrite is often enriched in nodules and concretions. In the deep water shelf deposition zone, the thickness of organic-rich mud shale generally ranges from 40 to 120 m. For instance, the thickness reaches 80–120 m in the area of Shizhu Qiliao–Jiaoshiba–Dingshan–Changning Shuanghe–Leibo Bajiaotan. The high-quality mud shale (with a TOC greater than 2.0%) typically has a 20 to 50 m thickness. Four high-quality mud shale development zones are distributed around the edge of the Sichuan Basin, namely, Zhenba South, Shizhu Qiliao, Fuling Jiaoshiba, Xishui Dingshan, and Changning Shuanghe to Leibo Bajiaotan, with thicknesses reaching 40 to 60 m.

Based on core analysis results, the shale of the Longmaxi Formation in the study area exhibits characteristics of high residual organic carbon content, favorable type, and advanced thermal evolution. In well HN3C, the gray–black carbonaceous shale, gray–black mud shale, and gray–black silty mudstone have a minimum organic carbon content of 0.55%, a maximum of 5.89%, and an average of 2.54%. The lower high-quality shale section has a residual organic carbon content ranging from 1.06% to 6.28%, with an average of 3.50%. The organic matter type is type I, favorable for hydrocarbon generation. The vitrinite reflectance (Ro) ranges from 2.20% to 3.13%, with an average of 2.56%. The thermal evolution is in the over-mature stage, and the natural gas is predominantly dry.

5. Comparative Analysis of Hydrocarbon Source Rock Indicators

In North Africa, the Middle East, and South China, the Lower Silurian hydrocarbon source rocks are predominantly mudstone shales, characterized by high TOC and natural gamma features, indicating their high quality [72]. These regions exhibit significant regional differences in organic richness and thermal maturation, reflecting their unique geological histories and tectonic settings. The characteristics of hydrocarbon source rocks in North Africa, the Middle East, and South China reveal the complexity and diversity of different basins in their sedimentary and thermal maturation processes [73].

5.1. Hydrocarbon Source Rock Type

The Silurian hydrocarbon source rocks of North Africa, the Middle East’s “Pan-Cratonic Basin”, and the Yangtze Platform in South China are primarily characterized by mud shale hydrocarbon source rocks (Figure 9). These regions share remarkably consistent hydrocarbon source rock features [74]. Specifically, the rock formations in North Africa’s Triassic/Ghadames and Illizi Basins, as well as the Middle East’s Central Arabian and Rub’ al Khali Basins, are characterized by dark-gray to black graptolitic shales (Figure 10a) [75]. Moreover, the Sichuan Basin on the Yangtze Platform boasts hydrocarbon source rocks, including rich, black carbonaceous–siliceous shales abundant in graptolite fossils (Figure 10b).

The analytical data of this study are based on the “13th Five-Year Plan”: Study on Hydrocarbon Accumulation Regularity and Favorable Exploration Direction in Key Basins of North Africa. These Silurian hydrocarbon source rocks across the North Africa–Middle East–South China nexus are distinguished by their high natural gamma radiation and elevated TOC levels, typically exceeding 2.0% [76]. This makes them highly comparable, as illustrated in Figure 9. However, the thickness of these hydrocarbon source rocks can vary significantly between regions, generally falling within the 30–100 m range.

Figure 9. Comparison of Silurian hydrocarbon source rock characteristics between North Africa and South China (Modified from [77]).

Figure 9. Comparison of Silurian hydrocarbon source rock characteristics between North Africa and South China (Modified from [77]).

Figure 10. Photos of the characteristics of the Lower Silurian dark graptolite hydrocarbon source rock in North Africa, the Middle East, and South China. (a) Outcrop and core photos of the Lower Silurian black graptolite shale in the Yangtze Platform of South China. (b) Outcrop and core photos of the Lower Silurian black graptolite hydrocarbon source rock in North Africa.

Figure 10. Photos of the characteristics of the Lower Silurian dark graptolite hydrocarbon source rock in North Africa, the Middle East, and South China. (a) Outcrop and core photos of the Lower Silurian black graptolite shale in the Yangtze Platform of South China. (b) Outcrop and core photos of the Lower Silurian black graptolite hydrocarbon source rock in North Africa.

5.2. Hydrocarbon Source Rock Quality

The Lower Silurian hydrocarbon source rocks of North Africa, the Middle East, and South China vary in quality and organic matter abundance, but overall, they are considered high-quality hydrocarbon source rocks with distinct characteristics in different regions (

Table 2. Comparison of Silurian hydrocarbon source rock characteristics in North Africa–Middle East–South China.

Distribution Area	Basin	Organic Matter Type	Organic Carbon Content	Hydrogen Index (HI)
North Africa Sahara Platform	Oued Mya Basin	Type I kerogen	3~20%	60 mg/g
	Ghadames Basin	Types I and II kerogen	1~17%	600 mg/g
Middle Eastern Arabian Platform	Central Arabian Basin	Types I and II kerogen	1~20%	Max, 670 mg/g Average, 339 mg/g
	Rub’ al Khali Basin	Types I and II kerogen	2.0~8.65%	50~200 mg/g
South China Yangzi Platform	Sichuan Basin	Types I/I-II kerogen	1.29~11.94%

).

The Lower Silurian hydrocarbon source rocks are well preserved in the Oued Mya Sub-Basin of the Triassic Basin in North Africa. The organic matter is predominantly type I, with a total organic carbon (TOC) content ranging from 3 to 20%, averaging 6%, and a hydrocarbon generation potential exceeding 60 kg/t. In the Ghadames Basin, the organic matter is types I and II, with a TOC ranging from 1 to 17%, derived mainly from lower aquatic algae and bacteria.

In the Middle East, the Silurian hot shales exhibit types I–II organic matter. The amorphous components in the kerogen microscopic components exceed 60%, primarily derived from graptolites, chitinozoans, marine algae, and organisms with uncertain origins. The TOC generally ranges from 1 to 20%, with an average of 3–5%, and the hydrocarbon generation potential is between 8.0 and 13.5 mg/kg. Specifically, the TOC ranges from 2.0% to 8.65% in the Rub’ al Khali Basin. In the Central Arabian Basin, the TOC ranges from 1 to 11%, reaching up to 20%; in the Western Arabian Basin, the average TOC is 5%, reaching up to 16%.

In the Sichuan Basin of the Yangtze Platform in South China, the Silurian Longmaxi Formation hydrocarbon source rocks are dominated by type I sapropelic organic matter and types I–II organic matter [78]. The TOC ranges from 1.29 to 11.94%, and the organic matter maturation conversion rate can reach approximately 66.7%. In the northeastern Chongqing area, the TOC of the Silurian Longmaxi Formation shale ranges from 0.57 to 4.96%, averaging 2.86%. In southeastern Sichuan, the TOC ranges from 0.7 to 2.29%, averaging 1.50%, and in the northern Guizhou area, the high abundance hydrocarbon source rock of the Longmaxi Formation has a TOC as high as 5.44%.

5.3. Thermal Evolution Characteristics

In North Africa, the Middle East, and South China, basins within different tectonic plates are influenced by tectonic movements and the evolutionary processes of sedimentary filling, leading to significant regional variations in the thermal maturation characteristics of organic matter in hydrocarbon source rocks [77]. These variations are evident not only between basins across different plates but also within different basins of the same plate. This phenomenon reflects the direct impact of tectonic activities and sedimentary evolution on the thermal maturity of organic matter, subsequently affecting the quality of hydrocarbon source rocks and their potential for hydrocarbon generation [79].

In the Silurian of the Wedderburn Basin in North Africa, Ro ranges from 0.5% to 1.3%, and the thermal evolution of hydrocarbon source rocks is mainly oil-generating. The Illizi and Ghadames Basins exhibit Ro values of 0.9% to 2.0% and 1.1% to 2.0%, respectively, indicating the co-generation of oil and gas. In contrast, the Timimoun Basin exhibits a Ro of 1.0% to 4.0%, with the thermal evolution mainly generating gas, especially dry gas.

The thermal maturation of Silurian thermal shales in the Middle East also varies, with Ro ranging from 0.7% to 2.5%. On average, it is greater than 2%, generally falling within the mature to over-mature stages. Moving westward, closer to the Arabian Shield, the thermal maturation gradually decreases, being in the oil-generating phase. Overall, the North African Craton Basin is characterized by a high degree of thermal evolution of homogeneous organic matter.

In the Longmaxi shale of the middle and upper Yangtze regions, the thermal maturity of Ro ranges between 2.5% and 4.0%. In the southern Sichuan area, the thermal maturity of the Longmaxi shale is generally between 1.8% and 3.8%. In the Chongqing East–Hubei West area, the maturity ranges from 2.0% to 4.5%. The maturity shows a trend of increasing from northwest to southeast, reaching an overall over-mature stage. Comparatively, the degree of organic matter thermal evolution in the Sichuan Basin of the Yangtze region is higher than the former.

6. Comprehensive Analysis of Hydrocarbon Source Rock Development Factors

Silurian hydrocarbon source rocks’ development and distribution characteristics are primarily governed and influenced by the comprehensive effects of global tectonic evolution, climatic changes, sea level fluctuations, and sedimentary filling processes. Specifically, the tectonic position of the basin, historical climatic conditions, and the paleogeomorphological environment of sedimentation collectively impact the sedimentary filling process. Moreover, the paleogeographic features of sedimentary facies and lithofacies significantly determine hydrocarbon source rocks’ development and distribution patterns. These varying development patterns, in turn, affect the spatial distribution of hydrocarbon source rocks [80].

6.1. Hydrocarbon Source Rock Development Model

In North Africa and the Middle East, current research on the genesis of Silurian hydrocarbon source rocks primarily revolves around two theoretical perspectives. The first viewpoint attributes the genesis to glacial valley erosion, supported by the evidence of the discontinuous planar distribution of the hydrocarbon source rocks. This discontinuity is interpreted as geological evidence of glacial activity, where glacial valleys were formed on the earth’s surface due to ice erosion. The second viewpoint suggests that these hydrocarbon source rocks were formed in shallow marine shelf environments. The evidence supporting this theory lies in the variability and discontinuity of the source rock distribution, which is closely associated with changes in sedimentary facies. This interpretation emphasizes the significant role of the sedimentary environment in the formation of hydrocarbon source rocks, particularly how changes in sedimentary facies influence the distribution patterns of these rocks.

During the Silurian period, both the Yangtze Platform in South China and North Africa and the Middle East regions were situated on the northern edge of Gondwana [81]. They shared a fundamentally similar tectonic and sedimentary background. The characteristic feature of the Silurian hydrocarbon source rocks in these regions is black graptolitic shale. The research indicates that the Silurian hydrocarbon source rocks on the Yangtze Platform in South China have a broad distribution and are typical of shallow marine shelf deposits.

Given their similar tectonic settings and concurrent stages of tectonic evolution, coupled with largely consistent stratigraphic and lithological traits, as well as similar paleobiological types and assemblages, it is believed that the Silurian hydrocarbon source rocks in North Africa and the Middle East follow a shallow marine shelf depositional model [33].

The glacial valley genesis model for hydrocarbon source rocks suggests that Silurian hydrocarbon source rocks were deposited in erosion valleys formed by glacial erosion during the late Ordovician period [82]. With the warming climate of the early Silurian, widespread marine transgressions flooded these erosion valleys, leading to the deposition of dark graptolitic thermal shales within the valleys. In contrast, the elevated regions outside these valleys lacked hydrocarbon source rock deposition. A developmental model of hydrocarbon source rocks is shown in Figure 11.

During the late Ordovician regression, the rapid marine transgression in the Early Silurian led to the inundation of the northern shelves of the Gondwana continent, resulting in the widespread shelf sedimentation characteristic of the maximum flooding period. In this context, the paleogeomorphology of the shelf exhibited significant undulations, particularly in the low-lying areas. Due to the stagnant, low-energy hydrodynamic conditions in these deeper waters, an anoxic environment was prevalent, favoring the preservation of dead accumulations of graptolites, chitinozoans, marine algae, and problematica, thereby facilitating the formation of high-quality hydrocarbon source rocks. The dark graptolitic shales in these regions are relatively pure in mud content, exhibiting high amplitudes in natural gamma ray log profiles. In contrast, the shallower shelf areas with stronger hydrodynamic energy had relatively poorer organic matter preservation, resulting in hydrocarbon source rocks of average quality with lower mud purity and correspondingly lower natural gamma ray readings. The thermal maturity characteristics of these rocks were less pronounced compared to those in deeper water settings. The depositional model of hydrocarbon source rocks in shallow marine shelves is illustrated in (Figure 12).

6.2. Distribution Characteristics of Hydrocarbon Source Rocks

Through a comparative analysis of the Silurian hydrocarbon source rock characteristics in North Africa, the Middle East, and South China, and in conjunction with the background of plate tectonic activities, ancient climate, and paleogeography, it is believed that the developmental pattern of hydrocarbon source rocks predominantly exhibits characteristics of shallow marine shelf facies. Based on the thicknesses of hydrocarbon source rocks revealed by drilling in different regions, a comprehensive distribution map of hydrocarbon source rocks (Figure 13) was compiled. This map shows that the original distribution of hydrocarbon source rocks in North Africa, the Middle East, and South China was extensive. However, due to the influence of ancient sedimentary geomorphology, there are variations in the characteristics of hydrocarbon source rocks in different regions. In the low-lying areas of the shelf terrain, specifically the “deep shelf stagnant basins”, the kinetic energy of the water is low, creating an anoxic environment conducive to the preservation of organic matter. These conditions result in high-quality hydrocarbon source rocks. In contrast, elevated areas of the shelf terrain, namely, “elevations within or between deep shelf stagnant basins”, represent shallow marine shelves where water is more active. This leads to slightly poorer preservation of organic matter, resulting in an inferior quality to the former. The Hercynian orogeny caused the original “Pan-Cratonic Basin” to uplift unevenly, leading to topographic differentiation [83]. Hydrocarbon source rocks in tectonically uplifted areas were eroded, reducing their distribution range. This resulted in the absence of Silurian hydrocarbon source rocks in regions such as the Ougarta Uplift in western North Africa, the Hasa-Mesopotamia uplift in the Triassic Basin, the peripheral areas of the Arabian Shield in the western Middle East [84], and the central Sichuan and Qianzhong Uplifts in the Yangtze Platform of South China’s Sichuan Basin.

7. Conclusions

• Based on an analysis of plate tectonic activities and the evolution of the Paleo–Tethys Ocean, combined with the geotectonic position of North Africa, the Middle East, and South China in the Paleo–Tethys tectonic domain, as well as the global sea level change characteristics and Silurian feature comparisons, it is believed that during the Silurian period, the North Africa–Middle East–South China Plate was located in the northern part of Gondwana and near the southern margin of the Paleo–Tethys. These regions shared the same ancient plate tectonic background and experienced similar sea level changes, resulting in consistent sedimentary filling characteristics in the basins;
• The Silurian hydrocarbon source rock characteristics of North Africa, the Middle East, and South China are similar. They predominantly consist of types I–II organic matter and exhibit high gamma and TOC content. This suggests that the sedimentary origins of these regions are broadly consistent. The Silurian hydrocarbon source rocks in the Yangtze Platform of South China are typical of shallow marine shelf deposits. This confirms that world-class hydrocarbon source rocks with a shallow marine shelf origin developed during the Silurian in the “Pan-Cratonic Basin” of the Middle East and North Africa. Depressions in the shelf (shelf basins) with deep stagnant water conditions favor the preservation of organic matter, thereby resulting in high-quality hydrocarbon source rocks. Conversely, the turbulent waters of the shallow marine shelf result in poorer organic matter preservation, thus resulting in hydrocarbon source rock of an inferior quality. The distribution range of sedimentary hydrocarbon source rocks in the shallow marine shelf is extensive.