As an important unconventional oil and gas resource, oil sands have been paid more and more attention all over the world. However, oil sands usually have some disadvantages such as strong heterogeneity and large differences in oil content, which leads to limited development efficiency. Based on the results of core, casting thin section and SEM observations, logging data, reservoir rock pyrolysis and soluble organic matter gas chromatography-mass spectrometry analysis, the mechanism of the oil content difference in the Cretaceous Upper McMurray Formation oil sands in the Mackay River area, Athabasca, Canada was studied. The diagenesis of the Mackay River oil sands is weak and there is no cement. The rock characteristics are mainly determined by three parameters: grain size, sorting and matrix content. The rock types are divided into extremely fine sandstone, fine sandstone, greywacke and siltstone. According to logging and core water saturation data, the oil sands reservoir can be evaluated as the gas, water, oil and poor oil interval, which are mainly composed of extremely fine sandstone, fine sandstone, greywacke and siltstone, respectively. The biomarker characteristics show that bitumen derives from the same source kitchen and there is no difference in maturity. Therefore, the main reason for the difference in oil content may be the difference in degradation degree and the amount of oil charged due to the diversity in reservoir petrological. Fine sandstone has good connectivity and is easy to be affected by degradation such as washing and oxidation, and usually forms the water interval. The siltstone is dense, and the early oil charging has difficulty reaching completion and this usually forms the poor interval. The properties of greywacke lie somewhere in between, the degree of degradation is relatively low and without affecting the early charging of oil, so it usually forms the oil interval.

Light oil and gas reservoirs are abundant in the Ordovician marine carbonate reservoir in Shunbei Oilfield, Tarim Basin. This presents a compelling geological puzzle, as ultra-deep reservoirs undergo intense alteration and complex petroleum accumulation processes. A comprehensive suite of geochemical analyses, including molecular components, carbon isotope composition, homogenization temperature of saline inclusions, and burial-thermal history of single wells, was conducted to elucidate the genesis of these ancient reservoirs. Three petroleum filling events have been identified in the study area: Late Caledonian, Hercynian-Indosinian, and Himalayan, through analysis of homogenization temperatures of brine inclusions and burial-thermal histories. Additionally, the oil in the study area has undergone significant alteration processes such as biodegradation, thermal alteration, mixing, evaporative fractionation, and gas invasion. This study particularly emphasizes the influential role of Himalayan gas filling-induced evaporation fractionation and gas invasion in shaping the present petroleum phase distribution. Furthermore, analysis of light hydrocarbon and diamondoid parameters indicates the oil within the study area is at a high maturity stage, with equivalent vitrinite reflectance values ranging from 1.48% to 1.99%. Additionally, the analysis of light hydrocarbons, aromatics, and thiadiamondoids indicates that TSR should occur in reservoirs near the gypsum-salt layers in the Cambrian. The existence of the Cambrian petroleum system in the study area is strongly confirmed when considering the analysis results of natural gas type (oil cracking gas), evaporative fractionation, and gas invasion. Permian local thermal anomalies notably emerge as a significant factor contributing to the destruction of biomarkers in oil. For oil not subject to transient, abnormal thermal events, biomarker reliability extends to at least 190 °C. In conclusion, examining the special formation mechanisms and conditions of various secondary processes can offer valuable insights for reconstructing the history of petroleum accumulation in ultra-deep reservoirs. This research provides a scientific foundation for advancing our knowledge of petroleum systems and underscores the importance of hydrocarbon geochemistry in unraveling ultra-deep, complex geological phenomena.

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 Santonian-Maastrichtian 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.

The Fushan Depression is one of the petroliferous depressions in the Beibuwan Basin, South China Sea. Previous studies have preliminarily explored the origin and source of crude oils in some areas of this depression. Nevertheless, no systematic investigations on the classification and origin of oils and hydrocarbon migration processes have been made for the entire petroleum system in this depression, which has significantly hindered the hydrocarbon exploration in the region. A total of 32 mudstone and 58 oil samples from the Fushan Depression were analyzed to definite the detailed oil-source correlation within the sequence and sedimentary framework. The organic matter of third member of Paleogene Liushagang Formation (Els₃) source rocks, both deltaic and lacustrine mudstone, are algal-dominated with high abundance of C₂₃ tricyclic terpane and C₃₀ 4-methylsteranes. The deltaic source rocks occurring in the first member (Els₁) and second member (Els₂) of the Paleogene Liushagang Formation are characterized by high abundance of C₁₉₊₂₀ tricyclic terpane and oleanane, reflecting a more terrestrial plants contribution. While lacustrine source rocks of Els₁ and Els₂ display the reduced input of terrigenous organic matter with relatively low abundance of C₁₉₊₂₀ tricyclic terpane and oleanane. Three types of oils were identified by their biomarker compositions in this study. Most of the oils discovered in the Huachang and Bailian Els₁ reservoir belong to group A and were derived from lacustrine source rocks of Els₁ and Els₂. Group B oils are found within the Els₁ and Els₂ reservoirs, showing a close relation to the deltaic source rocks of Els₁ and Els₂, respectively. Group C oils, occurring in the Els₃ reservoirs, have a good affinity with the Els₃ source rocks. The spatial distribution and accumulation of different groups of oils are mainly controlled by the sedimentary facies and specific structural conditions. The Els₂ reservoir in the Yong'an area belonging to Group B oil, are adjacent to the source kitchen and could be considered as the favorable exploration area in the future.

Due to limited data on the geochemical properties of natural gas, estimations are needed for the effective gas source rock in evaluating gas potential. However, the pronounced heterogeneity of mudstones in lacustrine successions complicates the prediction of the presence and geochemical characteristics of gas source rocks. In this paper, the Liaohe Subbasin of Northeast China is used as an example to construct a practical methodology for locating effective gas source rocks in typical lacustrine basins. Three types of gas source rocks, microbial, oil-type, and coal-type, were distinguished according to the different genetic types of their natural gas. A practical three-dimensional geological model was developed, refined, and applied to determine the spatial distribution of the mudstones in the Western Depression of the Liaohe Subbasin and to describe the geochemical characteristics (the abundance, type, and maturation levels of the organic matter). Application of the model in the subbasin indicates that the sedimentary facies have led to heterogeneity in the mudstones, particularly with respect to organic matter types. The effective gas source rock model constructed for the Western Depression shows that the upper sequence (SQ2) of the Fourth member (Mbr 4) of the Eocene Shahejie Formation (Fm) and the lower and middle sequences (SQ3 and SQ4) of the Third member (Mbr 3) form the principal gas-generating interval. The total volume of effective gas source rocks is estimated to be 586 km³. The effective microbial, oil-type, and coal-type gas source rocks are primarily found in the shallow western slope, the central sags, and the eastern slope of the Western Depression, respectively. This study provides a practical approach for more accurately identifying the occurrence and geochemical characteristics of effective natural gas source rocks, enabling a precise quantitative estimation of natural gas reserves.

Recently, significant oil discoveries have been made in the shallower pay zones of the Jurassic Badaowan Formation (J₁b) in the Mahu Sag, Junggar Basin, Northwest China. However, little work has been done on the geochemical characteristics and origins of the oil in the J₁b reservoir. This study analyzes 44 oil and 14 source rock samples from the area in order to reveal their organic geochemical characteristics and the origins of the oils. The J₁b oils are characterized by a low Pr/Ph ratio and high β-carotene and gammacerane indices, which indicate that they were mainly generated from source rocks deposited in a hypersaline environment. The oils are also extremely enhanced in C₂₉ regular steranes, possibly derived from halophilic algae. Oil-source correlation shows that the oils were derived from the Lower Permian Fengcheng Formation (P₁f) source rocks, which were deposited in a strongly stratified and highly saline water column with a predominance of algal/bacterial input in the organic matter. The source rocks of the Middle Permian lower-Wuerhe Formation (P₂w), which were deposited in fresh to slightly saline water conditions with a greater input of terrigenous organic matter, make only a minor contribution to the J₁b oils. The reconstruction of the oil accumulation process shows that the J₁b oil reservoir may have been twice charged during Late Jurassic–Early Cretaceous and the Paleogene–Neogene, respectively. A large amount volume of hydrocarbons generated in the P₁f source rock and leaked from T₁b oil reservoirs migrated along faults connecting source beds and shallow-buried secondary faults into Jurassic traps, resulting in large-scale accumulations in J₁b. These results are crucial for understanding the petroleum system of the Mahu Sag and will provide valuable guidance for petroleum exploration in the shallower formations in the slope area of the sag.