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.

The Late Cretaceous global transgression is one of the best documented episodes of continental submergence events. The extent of transgression of the Neotethys Ocean into the African continent is generally thought to be limited to north Africa. Here, we describe transgression traces in the Muglad Basin in central Africa that indicate a greater spatial extend of the Neotethys during the late Cretaceous. A series of molecular markers detected in the Upper Cretaceous Santonian-Maastrichtian sediments of the Muglad Basin are typical for marine depositional conditions and differ from those in the typical lacustrine sediments of the Lower Cretaceous Barremian-Aptian. Combining the geological-geochemical implications of these markers with the paleogeographic, paleontological and lithological records, we propose that the Muglad Basin received intermittent marine inundations during the SantonianMaastrichtian stages(86.3-66.0 Ma) and these special molecular markers are therefore the products of seawater incursion. Consequently, this study proposes that the transgression extent of the Neotethys Ocean into the African continent southern extended to the central Africa during the Late Cretaceous.

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.

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.

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.

M Basin in South Sudan is a complex Meso-Cenozoic intracontinental superimposed rift basin formed under the action of oblique rifting in the Central African Shear Zone. The oil and gas resources discovered in M Basin are concentrated in the upper Paleogene reservoir of the North Sub-basin, and few discoveries have been made in other sub-basins. In order to analyze the rules of hydrocarbon accumulation in the basin and reveal the exploration potential of various sub-basins, using the petroleum system theory as a guide and based on the analysis of reservoir elements, this paper carries out the analysis of the geochemical characteristics of crude oils, oil-source rock correlation, and the evaluation of petroleum systems and points out the exploration direction for different petroleum systems. (1) Two sets of source rocks have been formed in the basin, and the lacustrine mudstone in the upper part of the Lower Cretaceous succession is the primary source rock. (2) The petroleum systems in the basin are classified into three known petroleum systems and three predicted petroleum systems. For the Northern Petroleum System in the North Sub-basin, there are two critical periods, namely, the end of the Paleogene and the beginning of the Neogene. The end of the Paleogene is a period of large-scale hydrocarbon charging, and the beginning of the Neogene is a period of continuous oil charging. The near-source lithologic-stratigraphic trap in the lower part is an important zone with great potential for future exploration. (3) To a certain extent, the crude oil of the Southern Petroleum System in the North Sub-basin is genetically related to the two sets of source rocks mentioned above. For this petroleum system, there is only one critical period, namely, the end of the Paleogene. The upper Paleogene structural trap is a favorable zone with great exploration potential. (4) Except for the M Petroleum System in the South Sub-basin, which is speculated to be similar to the Northern Petroleum System in the North Sub-basin, the Cretaceous successions of the petroleum systems in other sub-basins are shallowly buried and only have limited exploration potential. This study not only provides an effective means for the study of petroleum systems, but it also further enriches and develops the connotation of petroleum systems in rift basins.

The sensitivity of biodegradation on diamondoids was investigated using a series of biodegraded oil samples from the Ronier tectonic unit of Bongor Basin, Chad. The results suggest that diamondoids, including adamantanes (As) and diamantanes (Ds), are relatively resistant to biodegradation and obvious biodegradation was observed in oils with a Peters-Moldowan (PM) biodegradation rank of 6 or more. Overall, the sensibility of biodegradation on diamondoids is generally similar to hopanes and regular steranes. As biodegradation evolves, the changes in concentration and components of diamondoids show that the biodegradation process is selective and stepwise. The significant increase of MD/MA and DMD/DMA for oils with a PM ranking 6+ indicates that diamantanes are generally more resistant to biodegradation than adamantanes. The similar trends of DMA/MA, EA/MA, MD/D, DMD/MD and other relevant indexes, show that higher alkylation homologs are more resistant to biodegradation. The commonly used diamondoid ratios, such as MAI, EAI, MDI and DMID-1, are obviously affected by biodegradation at the stage of high-level biodegradation, which may indicate that these ratios should be used with caution in case of severely degraded oils.

The Lower Cretaceous Manville Group of Upper Mc Murray Formation is one of the main bitumen reservoirs in Athabasca. In this study, the relationship between reservoirs heterogeneity and bitumen geochemical characteristics were analyzed through core and microscopic observation, lab analysis, petrophysics and logging data. Based on the sedimentology framework, the formation environment of high-quality oil sand reservoirs and their significance for development were discussed. The results indicate that four types lithofacies were recognized in the Upper Mc Murray Formation based on their depositional characteristics. Each lithofacies reservoirs has unique physical properties, and is subject to varying degrees of degradation, resulting in diversity of bitumen content and geochemical composition. The tidal bar(TB) or tidal channel(TC) facies reservoir have excellent physical properties, which are evaluated as gas or water intervals due to strong degradation. The reservoir of sand bar(SB) facies was evaluated as oil intervals, due to its poor physical properties and weak degradation. The reservoir of mixed flat(MF) facies is composed of sand intercalated with laminated shale, which is evaluated as poor oil intervals due to its poor connectivity. The shale content in oil sand reservoir is very important for the reservoir physical properties and bitumen degradation degree. In the context of regional biodegradation, oil sand reservoirs with good physical properties will suffer from strong degradation, while oil sand reservoirs with relatively poor physical properties are more conducive to the bitumen preservation.

The Termit Basin is a typical rift basin of the Mesozoic-Cenozoic era and is considered the most promising area for hydrocarbon exploration in the West African Rift System. This region's Paleozoic and Upper Cretaceous Formations have relatively complete source-reservoir-cap assemblages. This study aims to provide an in-depth understanding of the excellent environmental conditions and background that are conducive to the preservation of hydrocarbons in the Paleocene and Upper Cretaceous Formations. The study aims to explore various aspects of the sedimentary age, depositional environment, source direction, and hydrodynamic conditions in the area.In this study, zircon dating, geochemical characterization, and particle size analysis were performed on samples collected from two high-quality exploration areas, the Paleocene and Upper Cretaceous Formations. The Sokor-2 Formation of the Paleocene and the Madama and Yogou Formations of the Upper Cretaceous were the principal strata under investigation. The zircon dating results show that the primary rocks of detrital zircons experienced the Garidonian movement, with primary peaks in the Cambrian period. Geochemical characterization reveals that the sedimentary environment in the area was oxygen-rich, low-salinity, and warm. Particle size analysis helps identify the direction of material sources and hydrodynamic conditions in the palaeoenvironment.The experimental results indicate that the Paleogene and Upper Cretaceous Formations are high-quality exploration layers for oil and gas. These findings provide valuable data support for future hydrocarbon discoveries in the region.

There is a growing recognition that the post-rifting phase of basin evolution is far from being tectonically quiescent, as it can involve episodic uplift. However, the dynamic mechanisms responsible for this phenomenon remain a subject of controversy, particularly for intra-plate basins situated distant from active plate boundaries. Accurately determining the timing and magnitude of uplift is essential for elucidating the driving model behind these processes. In this study, we document the thermal history of the Doseo basin within the West and Central Africa Rift System (WCARS) using a combination of apatite fission track analysis and vitrinite reflectance data. Our findings reveal a period of accelerated exhumation during the late Eocene to Miocene epoch (similar to 45-20 Ma), characterized by kilometer-scale uplift, which corresponds to the formation of angular unconformities, folds, and fault-related anticlines. This specific time interval appears to be critical for the Cenozoic petroleum system, coinciding with the peak maturation of source rocks and the simultaneous formation of compressional traps. When integrated with the seismic data and previously published thermochronological data, our research reveals two significant cooling and uplift events in WCARS: a Santonian extrusion event and a late Eocene exhumation event. Both of these events have the potential to impact the entire tectonic plate, and Tethys realm. Furthermore, this two-stage exhumation event aligns closely with the timing of the Africa-Europe convergence collision. Consequently, we come to conclude that far-field lateral compression emerges as the dominant driving mechanism for intra-plate uplift, outweighing the influence of the mantle model.

In order to clarify the source, depositional environment and genetic relationship of crude oils in different areas in the northern Melut basin, the geochemical characteristics of crude oils in different areas were analyzed and correlated by means of saturated hydrocarbon chromatography and chromatography-mass spectrometry. The results showed that the n-alkanes of crude oils in the northern Melut basin have no obvious odd-even predominance, the Ts/Tm values range from 1.36 to 3.47, the C 31 hopane 22 S/（22 S+22 R） ratios are from 0. 54 to 0. 60, and the ratios of αααC 29 20 S/（20 S+20 R） and C 29 αββ/（ααα+αββ） are more than 0.4, all of which indicated that the crude oils in the northern Melut basin are mature oils. The gammacerane index is generally less than 0.1, the C 21 tricyclic terpanes have obvious predominance, and the values of Pr/Ph range from 0.97 to 2.31, with an average value of 1.61, all of which indicated that the source rocks of these crude oils were formed in the environment of weak reduction-oxidization freshwater lacustrine and developed type II-III organic matter. The source and maturity of crude oils in different areas in the northern Melut basin are different. The crude oils in the eastern slope of the Moleeta sub-sag have a unimodal and post-peak distribution of n-alkane, with a predominance of high carbon number n-alkane and an average value of C 24 TeT/C 23 TT being more than 1, which showed that the source rocks of these oils are dominated by terrestrial higher plants. The maturity of crude oil is low, and the heavy-medium oils are generally developed in the eastern slope of the Moleeta sub-sag. The crude oils in the deep area of the Jamous sub-sag have a bimodal distribution of n-alkane, with a pre-peak predominance, and the value of C 24 TeT/C 23 TT is less than 1. In addition to the contribution of terrestrial higher plants, the aquatic organisms also have an important contribution to the source rocks. The maturity of crude oil is relatively high, and the medium-light oils are generally developed in the deep area of the Jamous sub-sag. The Palogue oilfield is located between the two hydrocarbon-generating sub-sags and has the characteristics of mixed sources. The crude oils of the AYT oilfield mainly comes from the deep area of the Jamous sub-sag, and also has the contribution of local source rocks. The tilting fault zone in the middle part of the eastern slope of the Jamous sub-sag divided the sub-sag into two secondary faulted depressions, which provided the structural conditions for the deposition of local source rocks in the AYT（Abyat） area. Meanwhile, the tilting fault zone uplifted and shallowed the middle part of the Jamous sub-sag slope, where the shallow-water sandstone-mudstone interbeds locally developed in a weak oxidization environment.

Based on the seismic and drilling data, casting thin sections, geochemical analysis of oil and rock samples, and hydrocarbon generation history simulation, the hydrocarbon accumulation characteristics and exploration direction of Termit superimposed marine—continental rift basin are discussed. The Termit basin is superimposed with two-phase rifts (Early Cretaceous and Paleogene). The subsidence curves from two wells on the Trakes slope in the east of the basin show high subsidence rate in the Late Cretaceous, which is believed to be high deposition rate influenced by transgression. However, a weak rift may also be developed. The depositional sequences in the Termit basin were controlled by the Late Cretaceous marine transgression cycle and the Paleogene lacustrine transgression cycle, giving rise to two types of superimposed marine—continental “source-sink” deposits. The marine and continental mixed source rocks developed universally in the whole basinduring the marine transgression period, and are overlaid by the Paleogene Sokor 1 reservoir rocks and Sokor 2 caprocks developed during the lacustrine transgression period, forming the unique superimposed marine—continental basin in WCARS. The early low geothermal gradient in the Termit basin resulted in the late hydrocarbon generated by the source rock of Upper Cretaceous Yogou in Paleogene. Mature source rock of Upper Cretaceous Donga developed in the Trakes slope, so that the double-source-supply hydrocarbon and accumulation models are proposed for the Trakes slope in which formed the oil fields. Due to virtue of the newly proposed hydrocarbon accumulation model and the exploration activities in recent years in the Termit superimposed marine—continental rift basin, an additional effective exploration area of about 2500 km2 has been confirmed in the east of the basin. It is believed that potential domains such as Sokor 1, Donga and Upper Cretaceous lithologic traps in the southeast of the basin are key expected targets for exploration and frontier evaluation in future.

Based on systematic study on stratigraphic division, fault characteristics and reservoir forming mode, the fault development characteristics of Sharaf-AG low uplift and its control on reservoir formation is clarified. Considering the regional structure evolution, stratigraphy sequence, seismic reflection pattern and stratigraphic contact, the study area is divided into early strongly deformed Basement structural layer, AG-Bentiu rift depression structural layer, Darfur-Amal rift depression structural layer and Tendi-adok rift depression structural layer from the bottom to the top. By analyzing the trend, density and extension distance of faults in different periods, the author believes that there are three-level fault systems in the study area. The differences of fault growth rate curves show that the activity intensity of faults at different structural locations are obviously different, and the development of stratigraphic strata are also different. The analysis of the reservoir forming model in the structural belt shows that the faults play an important role in the process of oil and gas accumulation. They are not only an effective channel for oil and gas upward migration, but also an effective lateral sealing of the reservoirs. These understandings directly guide the oil and gas discoveries in the area in recent years.

Heavy oil is one of the most significant unconventional petroleum resources and one of its formation mechanisms is biodegradation. The characterization of the molecular compositions of petroleum is crucial for determining the various degrees of biodegradation. In this work, detailed investigations of acids and polar NSO compounds in different levels of biodegraded oils from the Bongor Basin (Chad) were carried out by negative ion electrospray ionization (-ESI) Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS). The present findings show that the heteroatomic compounds of biodegraded crude oils are predominantly composed of N-1, N1O1, O-1, O-2, O-3 and O-4 species. The relative content of N-1, N1O1 and O-1 species tend to decrease and those of O-2, O-3 and O-4 species appear to increase with the increasing of biodegradation. The ratio of acyclic and cyclic acids (A/C ratio) of the O-2 species increase with an increase of biodegradation, indicating the increasing of O-2 class during microbial alteration. A new parameter, i.e. the ratio of (O-2 + O-3 + O-4)/(N-1 + O-1) species, is presented to quantificationally define biodegradation levels. This parameter is inversely proportional to API gravity and has a favorable positive correlation with total acid number (TAN), suggesting acidic compounds are formed by the microbial alteration of N-1 and O-1 class and are more presented in advanced biodegradation. A modified ternary diagram including N-1, O-1 and O-2 + O-3 + O-4 species describe the detailed changes of nitrogen-and oxygen-containing compounds. Data points with a high level of biodegradation tend to shift to O-2 + O-3 + O-4 species end-member and retreat from N-1 species end-member, showing the relative content of O-2 + O-3 + O-4 species increase and those of N-1 species decrease with increasing biodegradation which may due to the formation of organic acids in degradation oil. The ratio of (O-2 + O-3 + O-4)/(N-1 + O-1) species and the modified ternary diagram provide new parameters to estimate the biodegradation degree and TAN in crude oil.

The Bongor Basin is a typical lacustrine passive-rifted basin situated in the West and Central African Rift System (WCARS). It has experienced two phases of tectonic inversion and features a complex process of petroleum generation and accumulation. A total of 41 crude oil samples from the basin were geochemically analyzed to investigate their compositions of molecular markers. The results show that the oils have similar origins and are likely to belong to the same oil population. However, there are significant differences in geochemical characteristics and physical properties, caused by the secondary alteration. The relative contents and distribution patterns of normal alkanes and acyclic isoprenoids indicate that some of the oils have suffered biodegradation to varying degrees. The samples can be divided into three categories according to their relative degrees of degradation: normal oil, slightly biodegraded oil (PM 1–3), and severely biodegraded oil (PM 5–7). The burial depth of oil reservoirs in this area is the predominant factor impacting on the level of biodegradation. Crude oils in reservoirs with burial depths of less than 800 m are all severely biodegraded, while oils in reservoirs with burial depths greater than 1300 m have experienced no evident biodegradation. In reservoirs with burial depths between 800 m and 1300 m, the biodegradation degrees vary from normal to severely biodegraded. Oil reservoirs with burial depths less than 1300 m and adjacent to major faults are readily subject to biodegradation, while reservoirs with similar burial depths, but a certain distance away from major faults, have suffered no evident biodegradation. Moreover, if primary reservoirs have been modified by tectonic activity after accumulation, the crude oils are more likely to be biodegraded. Faulted anticline traps may create more favorable geological conditions for preservation of crude oil than reverse extrusion anticline reservoirs. This study may provide practical guidance for the assessment and prediction of oil quality in future oil exploration.

Palogue油田的发现打开了Melut盆地古近系勘探新方向,证实了北部凹陷为富油气凹陷.Palogue油田具有以下白垩统为主力烃源岩,古近系为主力成藏组合的跨时代运聚风格,幔源CO2气体对油气的聚集和改造具有不可忽略的作用.通过对CO2气体、原油特征、生标特征、包裹体特征进行研究,结合地层埋藏史,分析油气特征及成藏期次.结果表明:Palogue油田具有两期成藏的特征,古近纪中期发生第1期油气成藏事件,随后原油被降解;古近纪晚期-新近纪以来,伴随幔源CO2气体油气发生第2次运移充注事件,且CO2气体对油藏进行了强烈的气洗作用.

Several international oil companies had conducted petroleum exploration, but failed to make any commercially viable discoveries in the Doseo Basin for over 30 years. In this article, an integrated analysis, based on the latest seismic and drilling data combined with exploration practice and tectonic, sedimentary as well as petroleum-geological characteristics of the basin, has been conducted with the aim to disclose the key factors of hydrocarbon accumulation and enrichment and then to find the potential petroleum plays. The Doseo Basin in Chad is a Meso-Cenozoic lacustrine rift basin developed on the Precambrian crystalline basement in the Central African Shear Zone. It is a half graben rift controlled by the strike-slip fault at the northern boundary, and can be divided into two sub-basins, an uplift and a slope. The basin experienced two rifting periods in the Cretaceous and was strongly inverted with the erosion thickness of 800–1000 m during the Eocene, and then entered the depression and extinction period. Structurally, a large number of normal faults and strike-slip faults are identified in the basin, and the boundary faults are inverted faults with normal at first. The main structural styles include inverted anticlines, fault noses, complex fault-blocks and flower structures. The Lower Cretaceous is the main sedimentary strata, which are divided into the Mangara Group, Kedeni, Doba and Koumra Formations from bottom to up. Two transgressive-regressive cycles developed in the Lower Cretaceous indicates with mainly lacustrine, fluvial, delta, braided-delta, fan-delta sandstone and mudstone. The effective source rock in the basin is the deep-lacustrine mudstone of the Lower Cretaceous containing the type I and type II1 organic matters. Furthermore, Inverted anticlines and fault-complicated blocks comprise the main trap types and the Kedeni Uplift is the most favorable play, followed by the Northern Steep Slope and Southern Gentle Slope. Lateral sealing capacity of faults controls the hydrocarbon abundance.

KN area is located in the East of KN depression in Muglad Basin. It has lower exploratory level, only two-dimensional survey lines are distributed in most areas before, and the quality of seismic data is poor. Three wells have been drilled in this area, only one well has low oil production in Bentiu formation, and the other two wells have failed. However, oil was discovered in multiple targets in H area, which is in the SouthEast of KN area. In order to evaluate the oil and gas potential of KN area, combined with the new seismic data of KN 3D area, it is carried out of comprehensive geological and geophysical research work in KN area. By means of well correlation, precise seismic interpretation, tectonic evolution analysis and drilled wells analysis, and comparing with the reservoir forming conditions of adjacent H area, it is concluded that the oil source fault and forming time of traps are the important factors to form the oil and gas reservoir. On this basis, the residual potential of KN area is reevaluated, and it is concluded that the Eastern fault step zone is a favorable area for further exploration.

Esso等多家国际油公司在尼日尔Termit盆地勘探36年,未获商业开发储量规模而退出.中国石油通过技术评价和商务一体化结合,于2003年进入Termit盆地,制定"分步走"勘探策略,一方面在盆地已有发现的西部进行滚动勘探落实储量,另一方面通过攻关核心地质问题,明确主力含油气层系和勘探方向.研究认为:(1)Termit盆地为发育两期裂谷和两期坳陷的叠合裂谷盆地,且在晚白垩世遭受海侵,与中西非地区其他陆相裂谷盆地有所差异;(2)古近系下部砂泥岩互层与上部区域性泥岩构成主力储盖组合;(3)建立了海陆叠合裂谷油气成藏模式,指导发现了4个亿吨级油田群,勘探获得巨大成功,成为海外自主勘探的又一典型成功案例.形成3个启示:(1)技术评价和商务一体化运作是尼日尔区块获取的重要原因;(2)陆相裂谷石油地质理论和技术的成功应用是Termit盆地勘探成功的前提;(3)建立Termit盆地成藏模式是勘探获得重大突破的主因.

The Palogue Oilfield is the largest oilfield in the Melut Basin, an important petroliferous rift basin in Africa. Geochemical analyses, including gas chromatography and gas-mass chromatography were adopted to analyze the biomarker composition and geochemical characteristics of oils from the Palogue Oilfield and the neighboring Moleeta and Jamous lows. Oil-oil correlations were performed for the Palogue Oilfield and the Moleeta/Jamous lows, and the hydrocarbon accumulations of the Palogue Oilfield were studied based on the oil maturities, thermal evolution modelling of the Moleeta/Jamous lows and the petroleum system analysis of the Melut Basin. Geochemical analysis indicates that the oils of the Moleeta/Jamous lows are derived from terrestrial higher plants, with the low ratios (<1) of light n-alkanes to heavy n-alkanes (∑nC21-/∑nC22+) and the predominance of C29 regular sterane, but there still are some geochemical differences in distribution shape of n-alkanes, paleoenvironments and maturities in these two lows. The oils of the Palogue Oilfield have mixed-source features and their geochemical characteristics are more like those of the Jamous low, and a few oils are like the oils in the Moleeta low. The Jamous low has a larger area and higher thermal maturity than the Moleeta low, and the abundant oils generated by the Al Renk source rocks (upper part of early Cretaceous) in the Jamous low are the primary contributors to the formation of the giant Palogue Oilfield. The vitrinite reflectance equivalent (Rc) converted by the methyl phenanthrene ratio indicates that the oil maturities of the Palogue Oilfield range from 0.65% to 1.07%. Thermal evolution modelling of the Moleeta/Jamous lows indicates that the Jamous low generated and expelled hydrocarbons earlier than the Moleeta low. The maturity of Al Renk source rocks reached 0.65% at 70Ma (Late Cretaceous) and 1.07% at 38Ma (Eocene) in the Jamous low, and reached 0.65% at 59Ma (Paleocene) and 1.07% at present in the Moleeta low. Thus, the high-maturity oils (Ro> 1.07%) generated by the source rocks in the Jamous low since 38 Ma have not been discovered in the primary production layers of the Paleogene Samma and Yabus Formations in the higher part of the Palogue structure, a drape-anticline developing on a paleo-high between the Jamous and Moleeta lows. The maturity parameter of Ts/(Ts + Tm) shows that the oil maturities from late Cretaceous Formation in the well PS-7 and PS-8 are close to the oils in the Jamous Low and are significantly higher than the oils from the Paleogene Formation in the higher part of the Palogue structure. So, the Cretaceous Formation under the Paleogene pay zones and the Paleogene Formation in the lower part of the Palogue structure likely accumulated high-maturity oils from the Jamous low, which will enhance the exploration potential of the Palogue Oilfield. The petroleum system study indicates that the end of Oligocene (late Paleogene) is the critical moment for the Paleogene hydrocarbon accumulations in the Melut Basin. Whereas, the high-maturity oil accumulations (Ro> 1.07%) in Cretaceous formations in the Palogue Oilfield occurred after 38Ma (late Eocene), when the Al Renk source rocks in the Jamous low started to enter the high thermal evolution stage with the Ro> 1.07%.