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The eastern Kuqa Depression in the northern Tarim Basin, NW China, is rich in oil and gas. However, recent exploration has been hindered by a lack of knowledge on the evolution of the petroleum system. To address this, we conducted hydrocarbon generation and accumulation modeling using both the 2Dmove and PetroMod2017 software for a complex tectonic extrusion section in the Kuqa Depression. The results show that the source rocks in the northern slope zone became mature quite early at around 170 Ma, but the thermal maturity evolution stagnated subsequently because of tectonic extrusion and uplift. The source rocks in the central anticline zone, the southern slope zone, and the deep sag zone were of overall low maturity during the Jurassic to Paleogene but rapidly became mature to highly mature with the deposition of the Neogene Jidike and Kangcun formations. The main hydrocarbon generation periods are in the late Neogene and Quaternary, and the main hydrocarbon generation stratum is the lower Jurassic Yangxia formation. The amount of cumulative hydrocarbon generation gradually increases for carbonaceous mudstone, mudstone, and coal source rocks. Sourced from source rocks mainly in the northern slope zone, oil and gas migrated to anticlinal traps along sandstone transport layers and faults. Recent discoveries, such as the Tudong-2 gas field in the central anticline zone, underscore the richness of this region in petroleum resources. Some gas fields were also predicted in lithologic traps in the southern slope zone and the deep sag zone, as well as in fault-related traps in the northern part of the northern slope zone. [ABSTRACT FROM AUTHOR]

Recent decades have witnessed an increasing number of studies investigating petroleum systems with the application of rhenium-osmium (Re-Os) isotopic geochemistry. Here, we review the use of the 187Re-187Os geochronometer with respect to the geochemical behaviour of rhenium and osmium in hydrocarbon-related geological processes. The Re-Os budget in hydrocarbon source rock predominantly originates from natural water columns during its deposition. Open seawater tends to have a homogeneous Os isotopic composition because its residence time in seawater is longer than the time taken for ocean mixing. On the contrary, restricted water bodies (e.g., lakes) may have heterogeneous Os isotopic compositions due to the greater amount of terrigenous input. Hydrogenous Re and Os atoms are sequestered from the water body into sedimentary organic matter and transferred into crude oil through thermal maturation of organic matter. Thermal maturation likely does not significantly alter the Re-Os isotopic systematics of the source rock as a Re-Os isochron age of 442±21 Ma (2σ) is yielded in this study for over matured source rocks within the Silurian Longmaxi Formation from the Sichuan Basin. Re-Os atoms are mainly hosted by the highly polar/aggregating/aromatic asphaltenes in hydrocarbons, possibly chelating with organic complexes or occurring as metalloporphyrins. Resin and aromatic hydrocarbons also contribute to the Re-Os budget, but are 2 to 3 orders of magnitude lower than that of asphaltenes, whereas saturates do not contain appreciable Re-Os contents. The distribution of Re-Os atoms in hydrocarbons is heterogeneous because the duplicate analysis of pure single bitumen samples yields similar 187Os/188Os ratios whereas variable 187Re/188Os ratios. The Re-Os system in crude oils can be reset during transport away from the source rocks, with Os-rich organic fractions more readily expelled than Re-rich fractions. Contact with metal-rich fluids (e.g., hydrothermal fluid) or compositional changes related to asphaltene contents (e.g., deasphalting, biodegradation, thermal cracking and thermochemical sulphate reduction) are also likely to alter the Re-Os systematics in hydrocarbons. These geochemical features enable the 187Re-187Os isotopic system to have robust applicability for petroleum system investigations, which may use the Re-Os radiometric tool for: (1) stratigraphic correlation of source rocks, (2) dating geological events altering the asphaltene content in hydrocarbon such as hydrocarbon generation, thermochemical sulphate reduction, etc., and, (3) fingerprinting hydrocarbons. Regardless of the robustness of the 187Re-187Os geochronometer for petroleum system investigations, there are several pending questions such as partitioning between solid organic species or between organic matter and sulphide, chelating sites in hydrocarbons and Os isotopic equilibration between hydrocarbon subfractions. To improve the understanding of the Re-Os behaviour in petroleum systems, we underscore multi-proxies-based geochemistry (e.g., inorganic-organic geochemistry) and experimental studies (e.g., hydrous pyrolysis). [ABSTRACT FROM AUTHOR]

The Kelasu Thrust Belt is a favorable hydrocarbon accumulation zone in the Kuqa Sub-basin with several known giant gas fields including the Dabei and Kela-2 gas fields as well as the Dawanqi oil field. The origin and accumulation process of the hydrocarbons were investigated through an integrated petroleum geochemistry and fluid inclusion analysis, and basin modeling. Geochemical parameters indicate that the light oils from the Dawanqi oil field and Dabei gas field were generated from different sources as compared with light oils from the Kela-2 gas field. Light oils from the Dawanqi oil field and Dabei gas field are primarily derived from the terrestrial mudstones in the Jurassic Qiakemake ( J 2 q ) Formation with a maturity level of 1.4–1.6 %Ro, whereas light oils from the Kela-2 gas field are mainly derived from the terrestrial mudstones in the Triassic Huangshanjie ( T 3 h ) with a maturity level of 1.6–1.8 %Ro. Gases in the Kelasu Thrust Belt are dominated by coal-type gas and are primarily generated from the Jurassic coal measures. Carbon isotope ratios suggest that gases in the Dawanqi oil field and Dabei gas field were generated at a thermal maturity level of 1.6–2.3 %Ro , while gas in the Kela-2 gas field was generated at a thermal maturity level of 2.1–2.5 %Ro. Two episodes of oil and one episode of gas charge were delineated in the Dabei gas field. The second episode of oil charge occurred around 5–4 Ma, while gas charge occurred around 3–2 Ma. Three episodes of oil and one episode of gas charge were identified in the Kela-2 gas field. The latter two episodes of oil charge occurred around 5.5–4.5 Ma and the gas charge occurred around 3–2 Ma. The timing of the petroleum charge was also confirmed by the correlation between the maturity of the source rocks during the times of charge and the maturity levels of the light oil and gas in the reservoirs. The later oil and gas charge occurred at the same period in both the Dabei and Kela-2 gas fields, possibly relating to structural reactivation caused by regional tectonic compression, because intense tectonic compression and rapid uplift of the Tianshan Mountains occurred during the same period, which may have caused thrust fault activation and opening. Hydrocarbon expulsion from the source rocks during the period was possibly also related to the regional tectonic movement, providing hydrocarbon sources for the reservoirs. [ABSTRACT FROM AUTHOR]

Sedimentary heterogeneities are ubiquitous in nature and occur over a range of scales from core, reservoir to basin scales. They may thus exert significant influences on hydrocarbon generation, migration and accumulation. The sedimentary heterogeneities of the Permian Shanxi Formation in the Ordos Basin, China were modelled using Sedsim, a stratigraphic forward modelling program. The simulation results were then used to construct a 3D petroleum system model using PetroMod. The effects of sedimentary heterogeneities on hydrocarbon accumulations were evaluated by comparing the integrated Sedsim-PetroMod model with the classic 3D basin model. The Sedsim simulation shows that considerable sedimentary heterogeneities are present within the Shanxi Formation, as a result of the interplay of the initial topography, tectonic subsidence, base level change and sediment inputs. A variety of lithologies were developed both laterally and vertically within the Shanxi Formation at kilometre and metre scales, respectively, with mudstones mainly developed in the depositional centre, while sandstones developed in the southern and northern margin areas. A typical source-ward retrogradation is well developed within the Lower Shanxi Formation. A base-case classic 3D basin model was constructed to quantify the Permian petroleum system in the Ordos Basin. The geological and thermal models were calibrated using Vr and borehole temperature data. The source rocks of the Upper Paleozoic became mature (R o > 0.5%) and high mature (R o > 1.2%) in the late Triassic and late Jurassic, respectively, in the central and southern areas. During the Early Cretaceous, a tectonically induced geothermal event occurred in the southern Ordos Basin. This caused the source rocks to reach over maturity (R o > 2.0%) quite rapidly in the early Late Cretaceous in the central and southern areas. All the source rock transformation ratios (TR) at present are greater than 70% in the P 1 coal and P 1 mudstone layers with TR values approaching 100% in the central and southern areas. The transformation ratios of the P 1 limestone are close to 100% over the entire interval. In the base-case model, a large amount of hydrocarbons appear to have been expelled and migrated into the Shanxi Formation, but only a minor amount was accumulated to form reservoirs. In the model, the Shanxi Formation sandstone layer was set to be homogeneous vertically and there was no regional seal rocks present at the top of the Shanxi Formation. Therefore hydrocarbons could not be trapped effectively with only minor accumulations in some local structural highs where hydrocarbons are trapped both at the top and in the up-dip direction by the adjacent mudstone facies. In contrast, the integrated Sedsim-PetroMod model takes into account of the internal lithological and sedimentary facies heterogeneities within the Shanxi Formation, forming complex contiguous sandstone-mudstone stacking patterns. Hydrocarbons were found to have accumulated in multiple intervals of lithological traps within the Shanxi Formation. The results indicate that lithological distinctions, controlled by sedimentary heterogeneities in three dimensions can provide effective sealing in both the top and up-dip directions for hydrocarbon accumulations, with gas being mainly accumulated near the depocentre where lithological traps usually formed due to frequent oscillations of the lake level. [ABSTRACT FROM AUTHOR]

Highlights: [•] QGF+ directly measures dry, disaggregated reservoir grains after robust cleaning. [•] iTSF measures crushed inclusion solvent extracts from the QGF+ cleaned grains. [•] Fluorescence intensities correlate moderately well to total n-alkanes in inclusions. [•] Spectral peaks and ratios broadly reflect thermal maturity and/or API gravity. [•] Fluorescence spectrophotometry of oil inclusions is a useful screening technique. [Copyright &y& Elsevier]

Abstract: The petroleum generation and charge history of the northern Dongying Depression, Bohai Bay Basin was investigated using an integrated fluid inclusion analysis workflow and geohistory modelling. One and two-dimensional basin modelling was performed to unravel the oil generation history of the Eocene Shahejie Formation (Es3 and Es4) source rocks based on the reconstruction of the burial, thermal and maturity history. Calibration of the model with thermal maturity and borehole temperature data using a rift basin heat flow model indicates that the upper interval of the Es4 source rocks began to generate oil at around 35 Ma, reached a maturity level of 0.7% R o at 31–30 Ma and a peak hydrocarbon generation at 24–23 Ma. The lower interval of the Es3 source rocks began to generate oil at around 33–32 Ma and reached a maturity of 0.7% R o at about 27–26 Ma. Oil generation from the lower Es3 and upper Es4 source rocks occurred in three phases with the first phase from approximately 30–20 Ma; the second phase from approximately 20–5 Ma; and the third phase from 5 Ma to the present day. The first and third phases were the two predominant phases of intense oil generation. Samples from the Es3 and Es4 reservoir intervals in 12 wells at depth intervals between 2677.7 m and 4323.0 m were investigated using an integrated fluid inclusion workflow including petrography, fluorescence spectroscopy and microthermometry to determine the petroleum charge history in the northern Dongying Depression. Abundant oil inclusions with a range of fluorescence colours from near yellow to near blue were observed and were interpreted to represent two episodes of hydrocarbon charge based on the fluid inclusion petrography, fluorescence spectroscopy and microthermometry data. Two episodes of oil charge were determined at 24–20 Ma and 4–3 Ma, respectively with the second episode being the predominant period for the oil accumulation in the northern Dongying Depression. The oil charge occurred during or immediately after the modelled intense oil generation and coincided with a regional uplift and a rapid subsidence, suggesting that the hydrocarbon migration from the already overpressured source rocks may have been triggered by the regional uplift and rapid subsidence. The expelled oil was then charged to the already established traps in the northern Dongying Depression. The proximal locations of the reservoirs to the generative kitchens and the short oil migration distance facilitate the intimate relationship between oil generation, migration and accumulation. [Copyright &y& Elsevier]

Borno (Chad) Basin is an intra-cratonic rift basin located at the southwestern terminal of the West Africa Rift System. Despite its reported low petroleum potential, oil seepages have recently been found in the basin from its oldest and lowest stratigraphic unit, the Bima Sandstone. The lack of source beds below this reservoir sandstone makes it challenging to classify the basin petroleum system elements (PSEs) in their normal order and to predict the origin of the oil seepages in the region. Coupled structural analysis (2D Move) and petroleum system modeling (PetroMod) were employed to investigate the structural and hydrocarbon evolution of the basin to reassess its PSEs, hydrocarbon potential and migration trends. The structural model shows that the basin has extended up to 2900 km since the Late Cretaceous. The extension controlled by regional tectonic activities has affected the West and Central Africa Rift System and caused some localized tectonic disturbance in the form of igneous underplating and magmatic intrusion, leading to regional uplift. The magmatic sill intruded into the Late Cretaceous source rock formations increased the heat flow for the study area to a peak value of 128 mW/m2. This anomalous high heat flow value is 38 mW/m2 above the regional average and 18 mW/m2 above the average value for a non-volcanic rift margin. Essential petroleum system elements for trapping and accumulation of hydrocarbons were missing as a result of the uplift during the Late Cretaceous, creating hiatus and diverting sediments to other parts of the basin. The PetroMod model result indicates three zones of oil generation: Early Oil, Main Oil, and Late Oil in the Fika Shale and the Gongila source formations. Source rocks became mature at a relatively shallow burial depth of 900 m due to transient heating from the magmatic sill intrusion in the Late Cretaceous. Oil migrated updip to the surface through fault breakouts. The modeling results show no significant entrapment of conventional hydrocarbons in the study area. The findings improve our understanding of the Borno Basin petroleum system setting and offer new insight on the petroleum exploration potential in the region. • Extensional tectonic in the north-eastern Borno (Chad) Basin reached 2900 km length. • Paleo-section reconstruction shows the basin experienced uplift during the Late Cretaceous. • Late Cretaceous magmatic sill intrusion raised the geothermal gradients in the Kasade-1 well above the regional average. • PSM indicates oil migration along fault/fracture planes to the surface as seepages in the Borno (Chad) Basin. [ABSTRACT FROM AUTHOR]

Abstract: Two fluorescence techniques namely Quantitative Grain Fluorescence (QGF) and QGF on Extract (QGF-E) were employed to investigate hydrocarbon charge history in 17 wells from seven sedimentary basins in Australia and Papua New Guinea including the Exmouth, Barrow, Vulcan, Timor Sea (joint petroleum development area), Cooper, Gippsland, and Papuan basins. The investigation has delineated a widespread occurrence of residual and palaeo oils in all seven basins including (1) residual oil columns below current oil–water contacts (OWCs) and in currently water-bearing “dry” wells; (2) palaeo oil accumulation within current gas zone; (3) palaeo oil columns below current OWCs, and (4) palaeo oil in currently water-bearing “dry” wells. The QGF and QGF-E methods, which provide information on both current and palaeo oil saturation, have been shown to be very effective in unravelling hydrocarbon charge history in the wells investigated. [Copyright &y& Elsevier]

Highlights from the article: At the turn of the 21st century, petroleum exploration began to shift from conventional petroleum resources to unconventional petroleum resources largely due to the success of shale oil and gas development in the United States. The successful development of terrestrial tight oil in China has become a global highlight in the unconventional petroleum development in addition to the North America shale oil of marine origin.

The Kebai Fault zone of the West Junggar Basin in northwestern China is a unique region to gain insights on the formation of large-scale petroleum reservoirs in volcanic rocks of the western Central Asian Orogenic Belt. Carboniferous volcanic rocks are widespread in the Kebai Fault zone and consist of basalt, basaltic andesite, andesite, tuff, volcanic breccia, sandy conglomerate and metamorphic rocks. The volcanic oil reservoirs are characterized by multiple sources and multi-stage charge and filling history, characteristic of a complex petroleum system. Geochemical analysis of the reservoir oil, hydrocarbon inclusions and source rocks associated with these volcanic rocks was conducted to better constrain the oil source, the petroleum filling history, and the dominant mechanisms controlling the petroleum accumulation. Reservoir oil geochemistry indicates that the oil contained in the Carboniferous volcanic rocks of the Kebai Fault zone is a mixture. The oil is primarily derived from the source rock of the Permian Fengcheng Formation (P 1 f ), and secondarily from the Permian Lower Wuerhe Formation (P 2 w ). Compared with the P 2 w source rock, P 1 f exhibits lower values of C 19 TT/C 23 TT, C 19+20 TT/ΣTT, Ts/(Ts + Tm) and ααα-20R sterane C 27 /C 28 ratios but higher values of TT C 23 /C 21 , HHI, gammacerane/αβ C 30 hopane, hopane (20S) C 34 /C 33 , C 29 ββ/(ββ + αα), and C 29 20S/(20S + 20R) ratios. Three major stages of oil charge occurred in the Carboniferous, in the Middle Triassic, Late Triassic to Early Jurassic, and in the Middle Jurassic to Late Jurassic periods, respectively. Most of the oil charged during the first stage was lost, while moderately and highly mature oils were generated and accumulated during the second and third stages. Oil migration and accumulation in the large-scale stratigraphic reservoir was primarily controlled by the top Carboniferous unconformity with better porosity and high oil enrichment developed near the unconformity. Secondary dissolution pores and fractures are the two major reservoir storage-space types in the reservoirs. Structural highs and reservoirs near the unconformity are two favorable oil accumulation places. The recognition of the large-scale Carboniferous volcanic reservoirs in the Kebai Fault zone and understanding of the associated petroleum accumulation mechanisms provide new insights for exploring various types of volcanic reservoir plays in old volcanic provinces, and will undoubtedly encourage future oil and gas exploration of deeper strata in the region and basins elsewhere with similar settings. [ABSTRACT FROM AUTHOR]

Abstract: Oil generation can be the dominant overpressure mechanism in low permeability source rocks because of the volume increase upon conversion of organic matter to less dense oil during the petroleum generation process. To quantitatively express the relationship between oil generation and overpressure in source rocks, an equation for the pressure change due to oil generation was derived to quantitatively estimate the overpressure generated in the source rock by considering of the episodic fluid expulsion and parameters, such as the residual oil coefficient, source rock porosity, transformation ratio, TOC (total organic carbon), hydrogen index, the compressibility of Type I kerogen, oil and pore water. The equation was then calibrated with the results from physical simulation experiments in a closed pyrolysis system. Sensitivity analyses on the residual oil coefficient, TOC and hydrogen index were performed to investigate the dominant parameters controlling overpressure due to oil generation. A good correlation was achieved between measured overpressure from the physical simulation experiments and the calculated data using the derived equations for the pressure change due to oil generation, suggesting that the equation can be used to quantitatively estimate overpressure caused by oil generation in source rocks. Many parameters can affect overpressure caused by oil generation, including residual oil coefficient, source rock porosity, TOC, hydrogen index, and transformation ratio. Sensitivity analyses indicate that the most effective parameter on the pressure change due to oil generation in the source rocks is the residual oil coefficient, implying that the internal pressure seal for the source rock is the most important parameter for overpressure development caused by oil generation. Overpressure cannot be generated from oil generation if the residual oil coefficient is less than 0.75. Source rock TOC and hydrogen index have moderate effects on the pressure change caused by oil generation. Overpressure can be generated when the TOC content is as low as 0.5% provided the source rocks have a good internal pressure seal. [Copyright &y& Elsevier]

During secondary migration, there is an opportunity for oil to be trapped as fluid inclusions (FIs) within framework grains such as quartz and within diagenetic cements that have a crystalline structure. Oil saturation on migration pathways remains relatively low, so typically fewer oil inclusions get trapped compared with samples from an oil column. Geochemical analysis of the much smaller amounts of inclusion oil present in samples from interpreted oil migration pathways has been attempted for two samples from the Champagny-1 and Delamere-1 wells in the Vulcan Sub-Basin, northern offshore Australia. A combination of petrographic analysis, bulk geochemical inclusion analysis and log evaluation confirmed that both samples were from oil migration pathways. Despite the small number of oil inclusions, reliable geochemical data were acquired from both samples that were significantly above the levels detected for the system and outside-rinse blanks. The FI oil trapped on the interpreted oil migration pathway in Champagny-1 was generated from clay-rich marine source rock with little terrigenous organic matter input. It was generated at peak oil window maturity and correlates best with oils derived from the Late Jurassic Lower Vulcan Formation. In contrast, the Delamere-1 FI oil contains evidence of greater input of terrigenous organic matter and was generated at early oil window maturity. This FI oil also contains a signature of a biodegraded component, which could have been generated either from the Middle Jurassic Plover Formation, or from an older source rock. These data indicate that it is feasible to geochemically map migration pathways across prospects or basins, and to analyse palaeo-oil compositions in oil zones where the few inclusions get trapped. This also suggests that the few oil inclusions that sometimes occur in Proterozoic or Archaean rocks may be analysable in the future, which would provide relatively pristine and robust data on the composition and diversity of Earth’s early biosphere. [Copyright &y& Elsevier]

The tight reservoir property and oil accumulation are greatly affected by the complexity and heterogeneity of pore structure. Fine-grained, mixed sedimentary formation samples from the Permian Lucaogou Formation in the Jimsar Sag were systematically studied focusing on their fractal characteristics and effects on the storage space, minerals and diagenesis, and its implication for tight oil accumulation. Fractal dimensions were calculated by the MICP model equation. The lacustrine fine-grained, mixed sedimentary samples are characterized by single and multi-fractal structures. Compared with the multi-fractal reservoir, the pore-throat structure of single fractal reservoir is more uniform and the pore throat size is relatively smaller. Minerals and diagenesis have apparent influences on fractal characteristics of the lacustrine MSR tight oil reservoir. The enrichment of terrestrial minerals can increase the heterogeneity of storage space and might be the reason for the multi-fractal pore structures. The enrichment of tuff in mixed sedimentary rock (MSR) can greatly improve the property and reduce the fractal dimension of tight reservoirs through dissolution. Large-pore filling calcite has dual effects on destroying reservoir space and reducing heterogeneity, which makes the weak correlation between calcite and fractal dimension. Fractal characteristics implicate that pore structures play a very significant role in controlling the accumulation of tight oil. MSRs with D or D e more than 2.586 and porosity (average pore-throat radius) less than 6.3% (0.05 μm) are mostly incapable of effectively accumulating oil. • Pore structures of lacustrine fine-grained MSRs are characterized by single and multi-fractal structures. • Terrestrial minerals might be the reason for the multi-fractal pore structures. • Tuff reduce the fractal dimension of tight reservoirs through dissolution. • Fractal characteristics of pore structures play a very significant role in controlling the accumulation of tight oil. [ABSTRACT FROM AUTHOR]

Thermal stability of liquid petroleum in the subsurface is closely linked to reservoir temperature. Most oil accumulations occur at temperatures <120 °C. Oil cracks into gas at temperatures >150–160 °C leading to the dominance of gas condensate and free gas accumulations in ultra-deep high-temperature reservoirs. The recently drilled Fuyuan-1 exploration well (northern Tarim basin) produced high-quality non-cracked single-phase (black) oil from a carbonate reservoir located at maximum depth 7711 m and temperature 172 °C. This is the deepest oil discovery in China to date and among the deepest in the world. The oil density (0.825 g/cm 3 at 20 °C or API gravity 40°), relatively low gas/oil ratio (135 m 3 /m 3 or 758 scf/bbl), low variety and abundance of adamantanes as well as lack of thiaadamantanes and dibenzothiophenes indicate that the oil was expelled from a source rock at moderate thermal maturity and has not been cracked. The molecular and isotopic composition of oil-associated gases are consistent with this interpretation. We suggest that the oil remained uncracked because the residence time at temperatures >150-160°C was relatively short (<5 my based on 1D modeling) and apparently insufficient for cracking. We conclude that there is potential for finding unaltered liquid petroleum in other high-temperature reservoirs with relatively low geothermal gradient and recent burial in the Tarim basin and around the world. [ABSTRACT FROM AUTHOR]

• Thermal evolution of biomarkers trapped by asphaltene structure is distinctly delayed compared with that of free biomarkers. • The potential chemical conversion between asphaltene-occluded n -alkanes and n -alkenes may be related to the different metastable equilibrium of the system. • Steranes and terpanes occluded by asphaltenes can preserve the original characteristics of the diagenesis stage during thermal maturation. • The occlusion space formed by asphaltene aggregates presumably restricts the transformation of active biomarkers during the thermal evolution. Asphaltene-trapped (adsorbed or occluded) biomarkers are considered a valid source of information for crude oil with severe secondary alterations. However, thermal stress might change asphaltene-trapped hydrocarbons to some extent. Therefore, it is indispensable to investigate the thermal evolution behavior of asphaltene-trapped biomarkers. In this study, low-maturity bitumen from the Kuangshanliang area of the Sichuan Basin (China) was selected as a sample. The thermal evolution behavior of free and asphaltene-trapped saturated biomarkers was investigated by thermal simulation experiments. The results revealed, in addition to normal biomarkers, also a series of even carbon number n -alk-(1)-enes in asphaltene-occluded hydrocarbons. All of them were hardly influenced by secondary alterations. Moreover, due to the restriction of macromolecular structure, the thermal evolution of asphaltene-trapped biomarkers lags behind that of free biomarkers. Most biomarker parameters of occluded hydrocarbons changed little with increasing maturity. In particular, the distributions of occluded terpanes or steranes retained the characteristics of early diagenesis of organic matter, even if they suffered from strong thermal alteration. [ABSTRACT FROM AUTHOR]

Abstract: The petroleum charge history in the Lunnan Low Uplift (Tarim Basin, China) was investigated by comparing the geochemical characteristics of fluid inclusion (FI) oils from Ordovician and Triassic reservoirs with crude oils from stratigraphically different reservoirs. Quantitative Grain Fluorescence (QGF) and Total Scanning Fluorescence (TSF) were used to screen the reservoir samples so as to identify suitable samples for Molecular Composition of Inclusion (MCI) analysis. All of the samples contain C30 n-propylcholestanes, diagnostic of marine source rocks. The Ordovician-hosted FI oils differ from the Triassic-hosted FI oils, having higher relative abundances of C19 tricyclic terpane, C24 tetracyclic terpane and rearranged hopanes (Ts and C29 Ts), and higher Pr/Ph ratios, while the Triassic-hosted FI oils have lower Pr/Ph ratios and higher relative abundances of C23 tricyclic terpane, arylisoprenoids, 25-norhopanes and C35 homohopane. Several of the crude oils are similar to the Triassic-hosted FI oils. Based on the geochemical characteristics of the FI and crude oils combined with information on the burial history of the area, at least two petroleum charge episodes can be distinguished in the Lunnan Low Uplift. An early charge represented by the Ordovician-hosted FI oils was biodegraded, as evidenced by the presence of 25-norhopanes in the Triassic-hosted FI oils and crude oils but not in the Ordovician-hosted FI oils. Ordovician-hosted FI oils provide the only evidence for oil generated from Cambrian-Lower Ordovician source rocks. Triassic-hosted FI oils and crude oils in the Ordovician, Carboniferous and Triassic reservoirs are mixtures of biodegraded oil from an early charge episode, and more mature oil from later charge. [Copyright &y& Elsevier]

As the most polar component of crude oils, asphaltenes are characterized by their complex molecular structures and their sequestration of small organic molecules. These organic compounds are often protected from various secondary alteration processes, and thus might serve as useful molecular markers. However, little is presently known about the mode of occurrence of hydrocarbons isolated from asphaltenes by conventional approaches. In the current study, we collected veined bitumen samples from the Changjianggou Formation of the Longmen Mountains on the northwestern rim of the Sichuan Basin, extracted soluble organic matter with dichloromethane, precipitated asphaltenes with petroleum ether, and isolated hydrocarbons from the asphaltenes by centrifugation and hydrous pyrolysis. The results indicated that the n -alkane profiles of saturated hydrocarbons obtained by centrifugation and by hydrous pyrolysis at 300 °C not only were similar to each other, but also resembled those of typical crude oils more closely than the n -alkane profiles of the saturates fraction in veined bitumen extracts did. The asphaltene-bound aromatic hydrocarbons and resins were found to be too difficult to extract thoroughly by the current separation methods. A possible explanation is that saturated hydrocarbons are mostly associated with the peripheral substituents of asphaltenes via hydrophobic association, whereas aromatics and resins tend to interact with the asphaltene cores through π-π stacking, which is much stronger. Therefore, the dissociation or diffusion of the loosely bound saturated hydrocarbons would alter the geochemical information that they had originally recorded, whereas the covalently bonded or more tightly associated hydrocarbons are better shielded from secondary alteration processes. [ABSTRACT FROM AUTHOR]