Global deep Earth exploration and ultra-deep oil and gas exploration (below 6 000 m) have attracted increasing attention, with a growing number of major oil and gas discoveries. This article systematically reviews the discovery history of ultra-deep oil and gas exploration since 1937, dividing it into four major stages: onshore ultra-deep exploration and local breakthrough (1937–1982), shallow- water-dominated ultra-deep exploration and sporadic discoveries (1983–1997), onshore and offshore large-scale ultra-deep discoveries (1998–2018), and onshore over-8 000-m exploration and new breakthrough (since 2019). By the end of 2025, a total of 1 348 exploratory wells with a depth of more than 6 000 m have been drilled worldwide. A total of 305 ultra-deep oil and gas fields have been discovered in 29 basins across 20 countries, with recoverable reserves equivalent to 63.21×108 t, accounting for only 0.9% of the global total reserves and indicating enormous exploration potential. The discovered reserves are highly concentrated in the Tethyan and South Gondwana petroleum realms, dominated by passive continental margin basins with a proportion of 71.25%. Reservoirs are mainly composed of Meso-Cenozoic carbonate rocks and clastic rocks. Studies show that three types of advantageous basins, including cratonic basins, passive continental margin basins and foreland basins, have their own characteristics in terms of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation. The global ultra-deep oil and gas exploration degree is extremely low, and there may exist another “golden zone” for hydrocarbon accumulation with huge resource potential. In the future, it is necessary to strengthen research on the mechanisms of hydrocarbon generation and accumulation as well as resource assessment in ultra-deep strata, and carry out integrated evaluation combining geology, engineering and intelligent technology. Internationally, efforts should be focused on new ultra-deep project evaluation and oil and gas cooperation in hydrocarbon-rich regions such as the both sides of the Atlantic, the Middle East, Central Asia-Russia and Australia. With the accelerated exploration of over-8 000-m oil and gas in China, a new peak of reserve growth is forthcoming.

The century-long history of the oil and gas industry in the world has witnessed rapid advancements in petroleum exploration and an ever-expanding scope of research. The dynamic evaluation of oil and gas resources has played a crucial role in guiding and facilitating this process. Specifically, theoretical breakthroughs and initial exploration help identify new potential plays, while resource evaluation and exploration practices together drive both theoretical and technological progress. These contribute to a great leap forward in new areas of petroleum exploration. Over the past two decades, driven by technological advancements and the goals of achieving carbon neutrality and peak carbon dioxide emissions, global petroleum exploration efforts have been extended into deep-water environments, deep plays, and unconventional resources dominated by shale oil and gas, continuously opening new frontiers. According to the independent evaluation of the China National Petroleum Corporation (CNPC) 2024, the technically recoverable oil and gas resources worldwide amount to 1868.4 billion tons of oil equivalent, with conventional recoverable resources accounting for 61.2% and unconventional recoverable resources representing 38.8%. Therefore, conventional hydrocarbon resources remain the primary source of utilization, while unconventional hydrocarbon resources serve as an effective supplement. In the next 30 years, oil and gas will continue to play a vital role in global primary energy consumption. In this context, Chinese oil companies should sustain production and ensure sustainable development by securing numerous new overseas petroleum exploration and exploitation projects. Focusing on the high-quality petroleum exploration and exploitation overseas and in combination with petroleum geological conditions, resource potential, and cooperation environments, top ten major regions should be given priority for conventional petroleum exploration in the next decade, such as the Russian Arctic, the Central South Atlantic, and offshore East Africa. For shale oil exploration, seven major regions should be highlighted, including the Arabian Basin in the Middle East, the Volga-Urals Basin and West Siberian Basin in Russia, and the Bongor Basin and the southern Chad Basin of the West and Central African rift system. With the profound transformation of the global energy landscape and increasing difficulties in resource development, petroleum exploration is confronted with unprecedented complex challenges. Moving forward, the deep integration of theory, technology, exploration models, and intelligence will be a critical approach to successful petroleum exploration in the future.

The Termit Basin, a well-explored hydrocarbon-rich basin in West Africa, provides an excellent case study for investigating oil families, palaeoenvironments and organic matter (OM) inputs in the Trans-Saharan epicontinental basins. This study examines 19 newly discovered southeastern oils using gas chromatography, gas chromatography-mass spectrometry and stable carbon isotopic analysis. While three oil families (I, II and III) were previously identified in the basin based on discoveries made prior to 2020, this study identified, for the first time, family I oils in the far east of the basin, and first recognized two new families (IV and V) by chemometric analysis and correlations of 14 biomarkers and carbon isotope compositions. Families I and IV show more terrigenous inputs than family V. Our results do not support previous work suggesting that family I was derived from algal-dominated OM. Compared with family I, a contribution of marine sources was defined for family IV, although terrigenous inputs remained significant. Family V originated from source rocks with more inputs of marine OM. Family V is divided into subfamilies V1 and V2, of which subfamily V2 is distinguished by greater algal inputs under more reducing conditions. The identification of family V proved the presence of a new petroleum system related to marine algal-rich source rocks in the Termit Basin. Our results suggest significant terrigenous OM influx and extensive marine algae blooms in the Trans-Saharan epicontinental seas during the Late Cretaceous, coinciding with sea-level changes.

Investigating the deformation evolution of rifting, strike-slip faulting, and positive inversion within the Central African Shear Zone (CASZ) is crucial for understanding regional tectonic evolution, dynamic processes, and improving the exploration of hydrocarbon-rich basins. To better understand the deformation evolution of the CASZ, three brittle/ductile analog models with different block angles were tested. The results indicate that under NE-SW extensional stress: (1) rifting intensity in the CASZ decreases progressively from west to east, with the Doba Basin experiencing the strongest rifting, followed by the Doseo Basin, and the weakest rifting occurring in the Salamat Basin; (2) significant strike-slip deformation is concentrated primarily in the Doseo Basin, followed by the Salamat Basin, with minimal strike-slip deformation in the Doba Basin; and (3) strong positive inversion occurs near boundary regions of the CASZ-predominantly along the basin boundaries in the Doba Basin, whereas in the Doseo and Salamat Basins, it is more pronounced in the central depression areas.

The Bongor Basin is an important petroliferous basin in the Western and Central African rift system. The basin's evolution history is featured with a strong tectonic inversion during the Late Cretaceous, which resulted in its unique basin structure and hydrocarbon accumulation pattern. However, due to the complex process of repeated cooling and heating, single sample bedrock thermochronology can hardly provide accurate constraints to its thermal evolution history. In this paper, nine granitic core samples from the crystalline basement in five wells on the northern slope of the Bongor Basin were analyzed using multiple thermochronological methods (apatite UTh/He, apatite fission tracks and length distribution, apatite U-Pb dating) as well as vertical profiles to obtain a more accurate thermal history. The results show that the samples from all five wells underwent four stages of thermal history: from similar to 600 Ma to 135 Ma, the samples cooled continuously from 600 degrees C to near-surface temperatures; from similar to 135 Ma to 100 Ma, the samples were heated rapidly; from 100 Ma to 60-80 Ma, the samples cooled rapidly; and after that, the samples experienced slow differential heating and cooling. The thermal history results show that the key time for the strong inversion of the Bongor Basin was between 80 and 90 Ma when the basin was uplifted and exhumed as a whole, while samples in different fault blocks underwent differential uplift and subsidence since the Paleogene.

Faced with the continuous increase in oil and gas dependence on foreign sources,intensifying international oil and gas exploration and development is an inevitable choice.In response to the call of the Central Committee of the Communist Party of China,Chinese state-owned oil companies have embarked on the"go global"strategy since 1993,earnestly implementing the"Belt and Road"initiative and the new energy security strategy of"four revolutions and one cooperation."Over the past 30 years,Chinese state-owned oil companies have made significant contributions in sharing global oil and gas resources,adapting to energy transitions,and ensuring national energy security.

Based on two-dimensional/three-dimensional seismic and logging data, combined with the analysis of low-temperature thermochronology data, the unconformity surface characteristics and the patterns and dynamic mechanisms of inverted structures in the Doseo Basin in the Central and West African rift systems are systematically analyzed. Seismic profiles reveal two key inversion unconformable surfaces in the basin, i.e. the T5 interface within the Upper Cretaceous and the T4 interface at the top of the Cretaceous, which control the development of inverted structures in the basin. Four types of inverted structures, i.e. fault-associated, thrust, fold, and back-shaped negative flower, are identified. Spatially, they form six inverted structural belts trending in NE-NEE direction. The thermal history simulation of apatite fission track reveals two rapid cooling events in the late Late Cretaceous (85-80 Ma, cooling by 15 degrees C) and the Eocene-Oligocene (30-40 Ma, cooling by 35 degrees C), corresponding respectively to the formation periods of the T5 and T4 interface. The dynamics analysis of structural inversion indicates that the structural inversion in the Late Cretaceous was controlled by the subduction and long-range compression within the Tethys Ocean in the north of African Plate, while the structural inversion in the Eocene-Oligocene was drived by the stress transmission from the African-Eurasian collision. The two events were all controlled by the continuous tectonic regulation of the intracratonic basin by the evolution of the Tethys tectonic domain. The two periods of structural inversion enhanced the efficiency of oil and gas migration by controlling the types of traps (anticline and fault-related traps) and fault activation, precisely matching the hydrocarbon generation peaks of the Lower Cretaceous source rocks in the Late Cretaceous and Eocene, thereby controlling the formation of large-scale oil and gas reservoirs in the Doseo Basin. This geological insight provides a critical basis for the theoretical research on the evolution and hydrocarbon accumulation of inverted structures in discrete strike-slip rift systems.

近两年我国南方川北-鄂西地区上二叠统吴家坪组-大隆组取得了页岩气重大勘探突破，并在中二叠统孤峰组发现了勘探新苗头，但其富有机质层段的分布规律及其页岩气资源潜力仍不清楚.通过对川北-鄂西地区中二叠统地层开展沉积相识别与层序地层对比划分，分析不同层序的岩相古地理演化特征，进而探讨该区孤峰组富有机质层段的分布规律与页岩气资源潜力.研究结果表明：川北-鄂西地区中二叠统可划分为3个三级层序SQ1、SQ2和SQ3，其中层序SQ3对应于孤峰组，沉积于卡匹敦晚期；层序SQ3沉积时期，该区在碳酸盐岩台地（对应层序SQ1和SQ2）基础上发育了3个北西向展布的深水盆地，即鄂西盆地、开江-梁平台盆（海槽）和广旺台盆（海槽）；孤峰组硅质岩与硅质页岩层段的有机碳TOC含量较高（平均TOC含量为3%～10%），且展布相对连续稳定；峨眉山地幔柱事件驱动了该区中二叠世晚期深水斜坡-盆地环境的形成，从而控制着孤峰组富有机质硅质岩与硅质页岩的大规模区域性沉积.基于上述分析，综合硅质岩及硅质页岩有效厚度、TOC含量、构造保存条件等页岩气地质评价要素，在川东北至湘鄂西地区优选出5个有利区，面积约为1.2×10~4 km~2，估算总资源量约1.75×10 12 m~3，展示了良好的页岩气勘探开发潜力.

It is essential to intensify research on the strike-slip tectonic system in West and Central Africa to better understand regional tectonic evolution and achieve future breakthroughs in oil and gas exploration. Based on the structural interpretation of extensive seismic data and stratigraphic paleontological analysis of more than 50 wells, this study investigated the tectonic history, sedimentary filling, and evolution of the rift basins in the West and Central Africa, and identified a novel type of intraplate strike-slip tectonic system. It exhibits the following characteristics: (i) the strike-slip tectonic system in the West and Central Africa consists of the Central African Shear Zone (CASZ) and two rift branches, manifesting as an N-shape; (ii) most of basins and rifts are characterized by rapid subsidence at one end and substantial sedimentary thickness; (iii) two types of strike-slip basins are developed, namely the transform-normal extensional basin (TEB) along CASZ and the strike-slip-induced extensional basin (SEB) at each end of CASZ; (iv) two types of basins display their own temporal and spatial evolution history. TEBs underwent two rifting stages during the Early and Late Cretaceous, with a strong inversion at the end of the Late Cretaceous. SEBs experienced three rifting stages, i.e., the Early Cretaceous, Late Cretaceous, and Paleogene, with a weak inversion; and (v) this strike-slip tectonic system was formed under intraplate divergent field, indicating a new type of system. This discovery enhances understanding of the breakup of Gondwana and provides valuable guidance for future oil and gas exploration.

In the Neoproterozoic era, the breakup of the Rodinia supercontinent had a profound impact on different aspects of Earth; yet, the precise driving mechanism behind this event has been a source of ongoing controversy. The Tarim block, as a crucial component, presents an opportunity to gain valuable insights into the breakup process through its tectonic-sedimentary evolution history and dynamic background. However, the comprehension of basin evolution is limited due to the presence of an ambiguous prototype basin during the late Neoproterozoic and its intricate interconnections with surrounding blocks. In this contribution, we integrate detailed field observations, U-Pb dating of detrital zircon and rutile, and trace element analysis of detrital rutile to elucidate the source-to-sink relationships and the tectonic setting of Ediacaran sedimentary strata in the Aksu area (northern Tarim block, China). Detrital zircon age spectra exhibit consistent distributions with ages between - 850 and 600 Ma and between - 2100 and - 1800 Ma. Rutile age groups however exhibit an abrupt transition between the lower member of the Sugatbrak Formation and the succeeding upper member to the Qigebrak Formation in the basin, with ages between - 1800 and - 900 Ma and nearly identical to those between - 2100 and - 1800 Ma. Calculated Zr-in-rutile temperatures and Cr-Nb compositions imply that the majority of the detrital rutiles were sourced from amphibolite facies metapelites, with an abrupt transition from amphibolitic schist to amphibolite-granulite facies for the - 1800 Ma group grains. Provenance tracing shows that the detrital sediments of the lower Sugatbrak Formation are sourced from both the Central Tianshan and the Tarim blocks, and that the overlying strata have a single source in the Tarim block. A corresponding change from syn-rift detrital facies to a shallow-marine environment in on a passive continental margin is suggested in terms of depositional setting. In light of prior published evidence from petrology, geochronology and paleomagnetism, we propose that the Neoproterozoic northern Tarim margin was affected by a protracted subduction zone retreat. Associated back-arc spreading eventually was responsible for the opening of the southern Tianshan Ocean and rifting of the Central Tianshan block from the Tarim block in the late Ediacaran. This development ultimately prevented detrital material from the Central Tianshan block from reaching the northern Tarim depocenters as the latter evolved into a passive continental margin.

Based on seismic, drilling, and source rock analysis data, the petroleum geological characteristics and future exploration direction of the oil-rich sags in the Central and West African Rift System (CWARS) are discussed. The study shows that the Central African Rift System mainly develops high-quality lacustrine source rocks in the Lower Cretaceous, and the West African Rift System mainly develops high-quality lacustrine organic matter-rich marine source rocks in the Upper Cretaceous, and the two types of source rocks provide a material basis for the enrichment of oil and gas in the CWARS. Multiple sets of reservoir rocks including fractured basement and three sets of regional cap rocks in the Lower Cretaceous, the Upper Cretaceous, and the Paleogene are developed in the CWARS. Since the Late Mesozoic, due to the geodynamic factors including the dextral strike-slip movement of the Central African Shear Zone, the basins in different directions of the CWARS differ in terms of rifting stages, intervals of regional cap rocks, trap types and accumulation models. The NE–SW trending basins have mainly preserved one stage of rifting in the Early Cretaceous, with regional cap rocks developed in the Lower Cretaceous strata, forming traps of reverse anticlines, flower-shaped structures and basement buried hill, and two types of hydrocarbon accumulation models of “source and reservoir in the same formation, and accumulation inside source rocks” and “up-source and down-reservoir, and accumulation below source rocks”. The NW–SE basins are characterized by multiple rifting stages superimposition, with the development of regional cap rocks in the Upper Cretaceous and Paleogene, forming traps of draping anticlines, faulted anticlines, antithetic fault blocks and the accumulation model of “down-source and up-reservoir, and accumulation above source rocks”. The combination of reservoir and cap rocks inside source rocks of basins with multiple superimposed rifting stages, as well as the lithologic reservoirs and the shale oil inside source rocks of strong inversion basins are important fields for future exploration in basins of the CWARS.

The discovery of Palogue oilfield in Melut Basin has opened a new exploration direction of the Central African Rift Paleogene and confirmed that the northern sag of Melut Basin is rich in oil and gas resources.The Lower Cretaceous source rock is the major source rock of Melut basin,the Palaeogene is its main seal-reservoir assemblage.The formation mechanism and model of oil and gas accumulated were proposed based on the specific tectonic-stratigraphic assemblages and evolution history of the Melut Basin.Oil and gas accumulations were influenced of mantle CO2.Relationship between CO2 and hydrocarbon accumulation was investigated using a suite of hydrocarbon generation and expulsion history,tectonic evolution history,fluid inclusions,CO2 and crude by taking Palogue oil reservoir as an example.The results show that the Late Paleogene-Neogene,the occurrence of the mantle source CO2 migration tectonic thermal event have an important influence on oil and gas accumulation in Palogue oilfield.Under the action of tectonic-thermal events,the thermal evolution of source rocks rapidly enters the mature stage,and intense hydrocarbon generation and expulsion occurs,CO2 in supercritical state quickly blends into crude oil.The crude oil saturated with supercritical CO2 quickly migrated through the reservoir and developed a large number of high-temperature mixed hydrocarbon inclusions,which showed the rapid accumulation event under the abnormal high heat event.After the crude oil full of supercritical CO2 entered the Palogue trap,CO2 gas began to separate out from the crude oil layer by layer due to the change of formation temperature and pressure conditions,CO2 gas carries light components into the upper reservoir for mixing.This results in a series of changes in vertical physical properties.

The Cenomanian Mishrif Formation is one of the most important carbonate reservoirs in the Mesopotamian Basin. Detailed petrographic analysis, aided by geochemistry and burial history establishment on Mishrif carbonates from the AD oilfield, located at the margins of the Central Mesopotamian Basin of Iraq, presents a distinctive differential diagenetic mechanism that significantly impacts reservoir quality and exhibits a pronounced relationship with tectonic evolution and hydrocarbon accumulation. Analyses of petrographic features, carbon-oxygen isotopes, and minor and rare-earth elements reveal that echinoderm shells and rim calcites are results of marine waters; sparry calcites, matrix, and vein calcites from host rock primarily precipitate from meteoric fluid; microspars and vein calcites in the concretionary limestone are derived from brine water. The development of concretionary limestone mainly involves a complex process that comprises extensive bioturbation in marine waters, substantial fabric-selective dissolution in the meteoric zone, and significant sparry calcites occluded dissolved spaces in shallow burial environments. Winding and skew seams of argillaceous sediment around concretionary limestones, as well as the excellent preservation of skeletal remains inside the concretionary zone, manifest that the development of the concretionary limestone accomplished during the early diagenesis stage and pre-compaction. These centimeter-to-decimeter scaled concretionary limestones intermixed with host rock holding abundant open porosities shape the Mishrif reservoir and result in an inconspicuous, dual permeability system. The burial history, integrated with the diagenetic sequence and tectonic evolution, elucidates four stages that clarify interactions of diagenesis, porosity preservation, and hydrocarbon accumulation. The Cenomanian to Turonian period was a critical stage for the development of effective reservoir capacity. The end of the Cretaceous, marked by the contraction of the Neo-Tethys and the complete closure of the South Neo-Tethys, witnessed an early hydrocarbon accumulation event that enhanced reservoir porosity preservation. During the Paleocene to the Early Miocene epoch, the Neo-Tethys tended to be closing. As a result, the Mishrif Formation experienced shallow burial and generated typical concretionary limestone, which provided a rigid framework against compaction. From the Early Miocene to the present, the total closure of the Neo-Tethys and the Zagros Orogeny initiated a significant late oil-filling event that acted as the main accumulation moment, coinciding with efficient trap development and other optimal petroleum conditions. This study contributes to (1) comprehending the genesis of the differential diagenesis and its effect on pore structures and reservoir heterogeneity, and (2) linking diagenetic sequence to tectonic evolution and hydrocarbon accumulation of foreland basins evolved from Neo-Tethys tectonics. (c) 2024 Elsevier B.V. All rights are reserved, including those for text and data mining, AI training, and similar technologies.

Sediment composition and microfacies (MF) types in the Cretaceous Mishrif Formation of the A oilfield in Iraq were quantitatively analyzed to identify changes in facies belts. Nine major constitutes were recognized via point-count group analysis and thin sections. The hierarchical cluster analysis of point-count groups indicated that the Mishrif Formation contained 12 MF types that were clustered into seven facies belts: protected-, open inner ramp, and shallow shoal, proximal and distal middle ramp, agitated outer ramp, and distal outer ramp. The quantitative analysis of MF enabled the interpretation of the water energy and continuity of the subenvironments. A low-energy homoclinal ramp was established by integrating the significant volumes of finegrained carbonates that were present in almost all MF and low-relief green algal build-ups. Diagenetic discrepancy along Cenomanian-Turonian (C-T) unconformity is presented by extensive fabric-selective dissolution, classical karstification of dissolution-collapse breccia and paleosol deposits, and incisions and channels. Finally, a comprehensive comparison of the carbonate developments and diagenetic processes along unconformities in the Mishrif and its time-equivalent platform implied that the configuration of platforms associated intrabasins, and related diagenesis along unconformities were affected by the far-field effect of the tectonic activities that occurred in the northeast margin of the Arabian Plate. This study demonstrated that the quantitative analysis of carbonate MF is a powerful tool that can improve the reconstruction of a model of a low-energy carbonate ramp and provided important implications for the study of the paleogeography of the northeastern margin of the Arabian Plate during the Cenomanian-Middle Turonian.

The results of a multiproxy study on Mishrif carbonates from the margins of the Central Mesopotamian Basin of Iraq display a wide range of rock fabrics and diagenetic features, all affecting reservoir heterogeneity and flow properties in a complex manner. Based on petrographic and facies analyses of the Mishrif Formation in the AD oilfield, twelve characteristic microfacies types are proposed and are set in six sedimentary facies belts: (i) restricted inner ramp, (ii) back-shoal, (iii) shallow shoal, (iv) fore-shoal, (v) storm-agitated bioclastic shell layer, and (vi) outer ramp. There is a good correlation between microfacies types, depositional components and reservoir quality. Twelve microfacies types are classified into five classes (i.e., Type I – V) with distinct reservoir quality. Besides, the content of typical components comprising green alga, planktonic foraminifera, micrite, and cement plays important roles in reservoir quality. The Mishrif reservoir properties are shaped by distinctive patchy cementation occluded by multiple-stages calcitic cements. These patchy carbonates are mainly developed in the Reservoir Type I lithology and result in distinctive cm-to dm-scale heterogeneity. The contrast between small, poorly-connected pore systems in nodules and medium-sized, well-connected pore systems in the host rock is best described as an inconspicuous, dual permeability system. Four types of reservoir heterogeneity (i.e., Type I – IV) are established by four coefficients and show a good logging response from NPHI and GR logs. Sedimentation and diagenesis are two main reasons for the heterogeneity generation: i) Sedimentology is a foundation for reservoir heterogeneity development. The spatial distribution of microfacies controls the meter-scaled inter- and intra-stratigraphic reservoir heterogeneity. ii) Subsequently, diagenesis further enhances the decimeter to centimeter scaled intra-stratigraphic reservoir heterogeneity in two aspects: diagenetic overprints below the 4th sequence boundary and intensity of patchy cementation. Data shown here and evidence from other studies dealing with the Mishrif in the Central Mesopotamian Basin are important to understand and predict reservoir properties in other carbonate fields with similar properties.

In the first comprehensive study of the Termit Basin petroleum system, an integrated organic geochemistry and basin modeling study of potential source rocks and related oils was conducted to evaluate source rock potential, classify oil families, establish oil -source correlation, and explain the distribution of petroleum systems. Six hundred forty-three cutting samples from the Paleogene Sokor1 Formation, Upper Cretaceous Yogou and Donga Formations, and Lower Cretaceous K1 Formation were analyzed using total organic carbon, Rock-Eval pyrolysis, vitrinite re flectance, and kerogen element analysis. The results suggest that the Sokor1, Yogou, and Donga Formations are poor to excellent source rocks with type I, II, II -III, and III kerogen, and most of the samples are thermally mature and within the oil window. Samples from the K1 Formation have poor organic richness and are thermally mature to postmature. In vertical, samples from the upper member of the Yogou Formation have greater organic matter richness and contain more oil-prone type I and oil-prone type II organic matter than those from the lower member. In horizontal, samples from the Donga Formation on the east side of the basin are dominated by very oil-prone type I and oil-prone type II organic matter and have higher hydrocarbon generation potential than those on the west side, which mainly contain oil- and gas-prone type II -III and gas-prone type III organic matter. One-dimensional basin modeling results demonstrate that the Sokor1 source rocks are mature in the northwestern part of the basin, are immature on the eastern side at present-day, and oil generation began in the early Oligocene. The Yogou source rocks are in the early oil to wet gas stage at present-day, and oil generation began at the end of the Late Cretaceous. The Donga source rocks are in the late oil to dry gas stage at present-day, and oil generation commenced in the middle Late Cretaceous. The maturation of these source rocks increased rapidly during the Oligocene due to active rifting. Three families (I, II, and III) were identi fied by hierarchical cluster analysis, principal component analysis, and stable carbon isotope compositions for 97 oil samples and eight rock extracts. Most of the oils (family I) were derived from Yogou source rocks, and their extensive distribution and wide range of thermal maturities are closely related to the large area of mature Yogou source rocks in the basin. Family II oils occur in the northwestern part of the basin and are genetically related to Sokor1 source rocks. The family III oil occurs on the east side of the basin and originated from the Donga Formation. This study con firms the existence of three petroleum systems between the Paleogene and Upper Cretaceous and helps to identify exploration prospects and guide petroleum resource assessment in the Termit Basin.