Stable sulfur and nitrogen isotopic compositions of crude oil fractions from Southern Germany

Eleven samples of crude oil from the Molasse Basin of Southern Germany were fractionated and their contents of sulfur and nitrogen as well as the stable isotope compositions of these elements (${}^{34}\text{S}{}^{32}\text{S}$ and ${}^{15}\text{N}{}^{14}\text{N}$, resp.) investigated.According to the δ³⁴S determinations, all crude oils from the Tertiary base of the Western and Eastern Molasse belong to one oil family and differ significantly from the Triassic and Liassic oils in the Western Molasse.An enrichment of ³⁴S was observed with increasing polarity of crude oil fractions. The isotope distributions of sulfur in the polar constituents of the biodegraded oils from the sandstones of Ampfing, however, approach a homogeneous distribution.The nitrogen isotope distribution is rather uniform in Southern German oils. A regional differentiation can be recognized, although the overall isotopic variation is small. The δ¹⁵N values of the crudes and asphaltenes do not correlate.     

Origin and depositional environments of source rocks and crude oils from Niger Delta Basin: Carbon isotopic evidence

Thirty-nine crude oils and twenty-one rock samples from Niger Delta Basin, Nigeria have been characterized based on their isotope compositions by elemental analysis-isotope ratio mass spectrometry and gas chromatography-isotope ratio mass spectrometry. The bulk carbon isotopic values of the whole rock extracts, saturate and aromatic fractions range from –28.7‰ to –26.8‰, –29.2‰ to –27.2 ‰ and –28.5 ‰ to –26.7 ‰, respectively while the bulk carbon isotopic values of the whole oils, saturate and aromatic fractions range from –25.4 ‰ to –27.8 ‰, –25.9 ‰ to –28.4 ‰ and –23.5 ‰ to –26.9 ‰, respectively. The average carbon isotopic compositions of individual alkanes (nC₁₂-nC₃₃) in the rock samples range from –34.9‰ to –28.2‰ whereas the average isotopic values of individual n-alkanes in the oils range from –31.1‰ to –23.8‰. The δ¹³C isotope ratios of pristane and phytane in the rock samples range from –29.2 ‰ to –28.2 ‰ and –30.2 ‰ to –27.4 ‰ respectively while the pristane and phytane isotopic values range from –32.1‰ to –21.9‰ and –30.5‰ to –26.9‰, respectively. The isotopic values recorded for the samples indicated that the crude oils were formed from the mixed input of terrigenous and marine organic matter and deposited under oxic to sub-oxic condition in lacustrine-fluvial/deltaic environments. The stable carbon isotopic compositions were found to be effective in assessing the origin and depositional environments of crude oils in the Niger Delta Basin.     

A contribution to geochemical correlation between crude oils and potential source rocks in the eastern Molasse Basin (Southern Germany)

Nineteen core samples of potential source rocks for crude oils in the Eastern Molasse Basin were investigated with respect to their isotopic composition of stable carbon in organic extracts and kerogens. p] Some of the chemical and isotopic results give positive or negative indications for the relationship between crude oils and the selected core samples. The analytical data point to the clayish sediments of the Rupelian and Sannoisian as probable source rocks, but further sampling and methodological research will be necessary to confirm the preliminary results on these samples which proved to be of low maturity by their elementary composition.     

Correlation of crude oils and oil components from reservoirs and source rocks using carbon isotopic compositions of individual n-alkanes in the Tazhong and Tabei Uplift of the Tarim Basin,China

Carbon isotopic compositions were determined by GC–IRMS for individual n-alkanes in crude oils and the free, adsorbed and inclusion oils recovered by sequential extraction from reservoir rocks in the Tazhong Uplift and Tahe oilfield in the Tabei Uplift of Tarim Basin as well as extracts of the Cambrian–Ordovician source rocks in the basin. The variations of the δ¹³C values of individual n-alkanes among the 15 oils from the Tazhong Uplift and among the 15 oils from the Triassic and Carboniferous sandstone reservoirs and the 21 oils from the Ordovician carbonate reservoirs in the Tahe oilfield demonstrate that these marine oils are derived from two end member source rocks. The major proportion of these marine oils is derived from the type A source rocks with low δ¹³C values while a minor proportion is derived from the type B source rocks with high δ¹³C values. Type A source rocks are within either the Cambrian–Lower Ordovician or the Middle–Upper Ordovician strata (not drilled so far) while type B source rocks are within the Cambrian–Lower Ordovician strata, as found in boreholes TD2 and Fang 1. In addition, the three oils from the Cretaceous sandstone reservoirs in the Tahe oilfield with exceptionally high Pr/Ph ratio and δ¹³C values of individual n-alkanes are derived, or mainly derived, from the Triassic–Jurassic terrigenous source rocks located in Quka Depression.The difference of the δ¹³C values of individual n-alkanes among the free, adsorbed and inclusion oils in the reservoir rocks and corresponding crude oils reflects source variation during the reservoir filling process. In general, the initial oil charge is derived from the type B source rocks with high δ¹³C values while the later oil charge is derived from the type A source rocks with low δ¹³C values.The δ¹³C values of individual n-alkanes do not simply correlate with the biomarker parameters for the marine oils in the Tazhong Uplift and Tahe oilfield, suggesting that molecular parameters alone are not adequate for reliable oil-source correlation for high maturity oils with complex mixing.     

Geochemical analysis of mixed oil in the Ordovician reservoir of the Halahatang Depression, Tarim Basin, China

In this study,12 crude oil samples were collected and analyzed from the Ordovician reservoir in the Halahatang Depression,Tarim Basin,China.Although the density of oil samples varies considerably,based on saturated hydrocarbon gas chromatographic(GC),saturated and aromatic hydrocarbon gas chromatographic-mass spectrometric(GC/MS) and stable carbon isotopic composition analyses,all the samples are interpreted to represent a single oil population with similar characteristics in a source bed or a source kitchen,organic facies and even in oil charge history.The co-existence of a full suite of n-alkanes and acyclic isoprenoids with UCM and 25-norhopanes in the crude oil samples indicates mixing of biodegraded oil with fresher non-biodegraded oil in the Ordovician reservoir.Moreover,according to the conversion diagram of double filling ratios for subsurface mixed crude oils,biodegraded/non-biodegraded oil ratios were determined as in the range from 58/42 to 4/96.Based on oil density and oil mix ratio,the oils can be divided into two groups:Group 1,with specific density>0.88(g/cm3) and oil mix ratio>1,occurring in the north of the Upper Ordovician Lianglitage and Sangtamu Formation pinchout lines,and Group 2,with specific density<0.88(g/cm3) and oil mix ratio<1,occurring in the south of the pinchout lines.Obviously,Group 2 oils with low densities and being dominated by non-biodegraded oils are better than Group 1 oils with respect to quality.It is suggested that more attention should be paid to the area in the south of the Upper Ordovician Lianglitage and Sangtamu Formation pinchout lines for further exploration.     

Source of 1,2,3,4-tetramethylbenzene in asphaltenes from the Tarim Basin

1-Alkyl-2,3,6-trimethylbenzenes and a high relative amount of 1,2,3,4-tetramethylbenzene (TTMB) have been previously detected in the marine oils and asphaltenes in the oils from the Tarim Basin. In the present study, the stable carbon isotopic compositions of TTMB and n-alkanes in the pyrolysates of asphaltenes in the marine oils from the northern Tarim Basin and Silurian tar sands from the Tarim Basin were determined. TTMB has stable carbon isotopic compositions in the range from −23‰ to −24‰ and are about 12‰ more enriched in ¹³C than concomitant n-alkanes (−35‰ to −37‰) in the pyrolysates. The results indicate a contribution from green sulfur bacteria (Chlorobiaceae) to TTMB. Thus, the depositional environments of the source rocks for the marine oils and the bitumen in tar sands from the Tarim Basin are characterized by periods of euxinic conditions within the photic zone.     

Symmetry of pebble-deformation involving solution pits and slip-lineations in the northern Alpine Molasse Basin

Deformation features on pebbles of the Alpine Molasse Basin are most clearly developed in carbonate components. Ductile distortion is small; most of the pebbles moved against each other to produce solution pits and slip-lineations on the pebble surfaces. The complete lineation field has a triaxial geometry. From a compressional axis of divergence with maximum solution, fields of diverging lineations extend to meet at a plane of convergence. Their ends bend away from an intermediate axis towards an (extensional) axis of convergence. The strain-symmetry is pure shear for orthogonal lineation-field axes, uniaxial compression and extension representing special cases. The angle α between the divergent and the convergent axes decreases from 90 to 0° with the transition from pure to simple shear. For Molasse pebbles α angles between 90 and 60° were usually observed. Regional compression developed perpendicular to the Alpine structures and parallel to bedding, with increasing deviations near the Alpine border. Zones are recorded of vertical and horizontal extension and of compression perpendicular to bedding and horizontal extension perpendicular to the Rhinegraben existing at the northern border of the Molasse Basin.     

Petroleum geochemistry of the Potwar Basin, Pakistan: 1. Oil-oil correlation using biomarkers, δC and δD

Geochemical characterisation of 18 crude oils from the Potwar Basin (Upper Indus), Pakistan is carried out in this study. Their relative thermal maturities, environment of deposition, source of organic matter (OM) and the extent of biodegradation based on the hydrocarbon (HC) distributions are investigated. A detailed oil-oil correlation of the area is established. Gas chromatography-mass spectrometry (GC-MS) analyses and bulk stable carbon and hydrogen isotopic compositions of saturated and aromatic HC fractions reveals three compositional groups of oils. Most of the oils from the basin are typically generated from shallow marine source rocks. However, group A contains terrigenous OM deposited under highly oxic/fluvio-deltaic conditions reflected by high pristane/phytane (Pr/Ph), C₃₀ diahopane/C₂₉Ts, diahopane/hopane and diasterane/sterane ratios and low dibenzothiophene (DBT)/phenanthrene (P) ratios. The abundance of C₁₉-tricyclic and C₂₄-tetracyclic terpanes are consistent with a predominant terrigenous OM source for group A. Saturated HC biomarker parameters from the rest of the oils show a predominant marine origin, however groups B and C are clearly separated by bulk δ¹³C and δD and the distributions of the saturated HC fractions supporting variations in source and environment of deposition of their respective source rocks. Moreover, various saturated HC biomarker ratios such as steranes/hopanes, diasteranes/steranes, C₂₃-tricyclic/C₃₀ hopane, C₂₈-tricyclic/C₃₀ hopane, total tricyclic terpanes/hopanes and C₃₁(R + S)/C₃₀ hopane show that two different groups are present. These biomarker ratios show that group B oils are generated from clastic-rich source rocks deposited under more suboxic depositional environments compared to group C oils. Group C oils show a relatively higher input of algal mixed with terrigenous OM, supported by the abundance of extended tricyclic terpanes (up to C₄₁₊) and steranes.Biomarker thermal maturity parameters mostly reached to their equilibrium values indicating that the source rocks for Potwar Basin oils must have reached the early to peak oil generation window, while aromatic HC parameters suggest up to late oil window thermal maturity. The extent of biodegradation of the Potwar Basin oils is determined using various saturated HC parameters and variations in bulk properties such as API gravity. Groups A and C oils are not biodegraded and show mature HC profiles, while some of the oils from group B show minor levels of biodegradation consistent with high Pr/n-C₁₇, Ph/n-C₁₈ and low API gravities.     

Biomarker signatures from Neoproterozoic–Early Cambrian oil,western India

The Neoproterozoic–Early Cambrian time is the cradle of multicellular, eukaryotic life and thereafter metazoan life started populating the planet. Biomarkers, which record the chronicles of biotic events on Earth, have been investigated using gas chromatography–mass spectrometry from a suite of nine oil samples extracted from oil stained sediments and a crude oil of Neoproterozoic–Early Cambrian age from Bikaner-Nagaur Basin, western India. The biomarker distribution is characterized by high concentration of both tricyclic terpanes and pentacyclic hopanes. The predominance of C₂₉ regular sterane over C₂₇ and C₂₈ steranes indicates green algal contribution and may imply the prominence and diversification of the same algal group. The low pristane/phytane ratio and occurrence of substantial quantity of gammacerane, monomethyl 2-methyl-2-(2,4,8-trimethyltridecyl) chroman and 1,1,7,8-tetramethyl-1,2,3,4 tetrahydrophenanthrene are indicative of stratified water column as well as anoxic and enhanced salinity condition of the environment of deposition. This paper reports for the first time the presence of methyltrimethyltridecyl chromans (MTTCs) from Neoproterozoic–Early Cambrian time. Putative C₁₉ norsteranes, probably indicative of sponge input, are recorded in the studied samples and also reported from other infracambrian oils and sediments. Normal alkanes (n-C₁₇ and n-C₁₈) and isoprenoids (pristane and phytane) are highly depleted in δ¹³C. The overall biomarker distribution and carbon isotope data of oils from Bikaner-Nagaur Basin show similarities with those of other infracambrian oils like Huqf oils from Oman and Baykit High oils from eastern Siberia.     

Un réseau fluviatile d'âge Burdigalien terminal dans le Sud-Est de la France : remplissage,extension, âge,implications

An integrated study combining facies analysis, multiple group biostratigraphy, identification of depositional sequences and mapping has been conducted on the Miocene Molasse Basin of the external Alps (southeastern France). The filling of the basin is described as resulting from a succession of fluvial incisions subsequently filled during marine transgressions. The major incision is dated as Latest Burdigalian and the major transgression as Langhian. This revised interpretation of the Miocene physiographic evolution of the Molasse Basin implies a re-examination of previous stratigraphic correlations within the basin. To cite this article: D. Besson et al., C. R. Geoscience 337 (2005).     

Variations in Stable Carbon Isotopic Composition of n-Alkanes from Ordovician and Triassic-Derived Oils in Lunnan Oilfield, Tarim Basin, NW China： Global Paleoenvironmental Constraints

Molecular stable carbon isotope technique was employed to study well-sourced crude oils collected from a single drilling well and from the entire Lunnan oilfield, Tarim Basin, NW China. The stable carbon isotopic composition of n-alkanes from crude oils showed that Ordovi-clan-derived oils are enriched in ^13C and Triassic-derived oils are depleted in ^13C. This is consistent with the distribution and evolution trend of stable carbon isotope ratios in crude oils/organic matter from all over the world in geological history (Stahl, 1977; Andrusevich et al. ,1998). An extensive survey of literature indicates that, except for thermal maturity, organic matter input and depositional environment, paleoenvironmental background is another key factor that affects the stable carbon isotopic composition of Ordovician- and Triassic-derived crude oils. The results showed that gas chromatographic-isotope ratio mass spectrometry ( GC-C-IRMS), combining with biogeoehemical evolution of organic matter in geological history, may be a powerful tool in refining oil/oil, oil/source correlations in multi-age, multi-source petroliferous basins like Tarim.     

Oil families and their source rocks in the Weixinan Sub-basin, Beibuwan Basin, South China Sea

Thirty-one crude oils and 15 source rocks were selected for molecular geochemical and isotopic analyses in order to establish the genetic relationships between discovered oils and petroleum source rocks in the Weixinan Sub-basin, Beibuwan Basin, South China Sea. Three groups of oils were recognized. Group I oils are only found in the upper section of the Liusagang Formation, with a moderate abundance of C₃₀ 4-methylsteranes, low oleanane contents and lighter δ¹³C values, showing a close relation to the shale occurring in the upper section of the Liusagang Formation. Group II is represented by the majority of the discoveries and is distributed in multi-sets of reservoirs having different ages. The oils are characterized by a high abundance of C₃₀ 4-methylsteranes, low to moderate abundance of oleanane and heavy δ¹³C values, and shows a good correlation with the lacustrine shale and oil shale in the middle section of the Liusagang Formation. Group III oils occurred in the lower section of the Liusagang Formation. The oils have a lower concentration of C₃₀ 4-methylsteranes, relatively high abundance of oleananes and their δ¹³C values are intermediate. Oils of this group correlated well with the shallow lake-delta mudstone of the lower section of Liusagang Formation. These oil-source genetic relationships suggest a strong source facies control on the geographic distribution of oil groups within the Weixinan Sub-basin. The geochemical data indicate shale in the middle section of the Liusagang Formation has an excellent oil generation potential and the lower and upper sections contain dark shale and mudstone with good to fair oil potential. Future exploration or assessment of petroleum potential of the sub-basin could be improved by considering the proposed genetic relationship between the oil types and source rocks, as well as their distribution.     

Stable isotope(δ~(13)C_(ker),δ~(13)C_(carb),δ~(18)O_(carb)) distribution along a Cambrian outcrop section in the eastern Tarim Basin,NW China and its geochemical significance

This study investigated the geochemical features of the lower Paleozoic strata of Yaerdang Mountain outcrop along with the core samples from well TD2∈ in the eastern Tarim Basin,NW China.The total organic carbon abundance,hydrocarbon-generating precursor biospecies,and stable isotope ratios of organics and carbonate(δ~(13)C_(ker),δ~(13)C_(carb) and δ~(18)O_(carb)) were comprehensively studied for their possible correlative constraints during sedimentary evolution.The results revealed that the δ~(13)C_(ker)(VPDB) of Cambrian kerogens along the outcrop section varied from-34.6‰ to-28.4‰,indicating an increasing tendency from the lower Cambrian to the upper Cambrian.This was on the whole accompanied by the variation in the δ~(13)C_(carb) and δ~(18)O_(carb) along the profile,which might be associated with the changes in the sea level and also in the compositional variation of benthic and planktonic biomass.The large variation in the stable carbon isotope ratios up to 6‰ along the outcrop section reflected the heterogeneity of the Cambrian source rocks from the eastern Tarim Basin.Hence,the ~(13)C-enriched crude oils from well TD2∈might have been derived from a localized stratum of Cambrian source rocks.The results from this study showed the possibility of multiple source kitchens in the Cambrian-lower Ordovician portion of Tarim Basin.     

Hydrogen and carbon isotopes of petroleum and related organic matter

$\text{D}\text{H}$ and ${}^{13}\text{C}{}^{12}\text{C}$ ratios were measured for 114 petroleum samples and for several samples of related organic matter. δD of crude oil ranges from ?85 to ?181‰, except for one distillate (?250‰) from the Kenai gas field; δ¹³C of crude oil ranges from ?23.3 to ?32.5‰, Variation in δD and δ¹³C values of compound-grouped fractions of a crude oil is small, 3 and 1.1%., respectively, and the difference in δD and δ¹³C between oil and coeval wax is slight. Gas fractions are 53–70 and 22.6–23.2‰ depleted in D and ¹³C, respectively, relative to the coexisting oil fractions.The δD and δ¹³C values of the crude oils appear to be largely determined by the isotopic compositions of their organic precursors. The contribution of terrestrial organic debris to the organic precursors of most marine crude oils may be significant.     

Molecular correlation of free oil,adsorbed oil and inclusion oil of reservoir rocks in the Tazhong Uplift of the Tarim Basin,China

The free, adsorbed and inclusion oils were recovered by sequential extraction from eleven oil and tar containing reservoir rocks in the Tazhong Uplift of Tarim Basin. The results of gas chromatography (GC) and GC–mass spectrometry analyses of these oil components and seven crude oils collected from this region reveal multiple oil charges derived from different source rocks for these oil reservoirs. The initially charged oils show strong predominance of even over odd n-alkanes in the range n-C₁₂ to n-C₂₀ and have ordinary maturities, while the later charged oils do not exhibit any predominance of n-alkanes and have high maturities. The adsorbed and inclusion oils of the reservoir rocks generally have high relative concentrations of gammacerane and C₂₈ steranes, similar to the Cambrian-Lower Ordovician source rocks. In contrast, the free oils of these reservoir rocks generally have low relative concentrations of gammacerane and C₂₈ steranes, similar to the Middle-Upper Ordovician source rocks. There are two interpretations of this result: (1) the initially charged oils are derived from the Cambrian-Lower Ordovician source rocks while the later charged oils are derived from the Middle-Upper Ordovician source rocks; and (2) both the initially and later charged oils are mainly derived from the Cambrian-Lower Ordovician source rocks but the later charged oils are contaminated by the oil components from the Silurian tar sandstones and the Middle-Upper Ordovician source rocks.     

Fluorescence micro-spectrometry of synthetic and natural hydrocarbon fluid inclusions: crude oil chemistry,density and application to petroleum migration

The fluorescence spectra of crude oils, synthesized as hydrocarbon fluid inclusions (hcfi) in NaCI crystals, have been recorded and correlated with crude oil chemical analysis. The crude oils represent a wide range in total hydrocarbons, saturate and aromatic fractions, and resin-asphaltene concentration. The fluorescence properties (Lambda max and Q) of the hydrocarbon fluid inclusions display a systematic red shift to longer wavelengths from 440 nm to 595 nm with increasing aromatic content and increasing concentration of NSO-bearing compounds. A positive correlation also exists between Lmax-Q and the thermal maturity parameters nC17/pristane and nC₁₈/phytane. First order linear regression equations provide a method for constraining the chemical composition of natural hydrocarbon fluid inclusions. Lmax and Q correlate positively with oil density (°API), providing for an indirect method of estimating the API of a natural hydrocarbon fluid inclusion assemblage. Fluorescence spectra of non-biodegraded crude oils from the Upper Devonian Birdbear Formation, Saskatchewan, Canada, have been correlated with regionally widespread hcfi within carbonate carrier beds and reservoir rocks of the same formation. The two most dominant types of hcfi spectra match well with the fluorescence spectra from crude oils within the Birdbear Formation. A third, less common population of very-blue fluorescing hcfi (Lmax=415440 nm, Q ≤ 0.10) also occur within fractures, intercrystalfne cements or in fossil overgrowths. The Lmax-Q-API-chemical correlations establised for the synthetic hcfi suggests that the °API of these inclusions is probably > 45° and the saturate/aromatic ratio ranges from 3.2 to 5.1. Spectra from hcfi within quartz overgrowths and cements, fractures and carbonate cements from sandstone reservoirs in the Jeanne d'Arc Basin offshore Newfoundland, compared with fluorescence spectra of crude oils suggests that some of the reservoirs may have been filled by a relatively low maturity oil and then a higher maturity oil. This is reflected in the intermediate spectra of the crude oils relative to the spectra of two separate hcfi events. Other reservoirs appear to have been charged with a relatively high gravity oil which was later biodegraded. This is marked by a blue region spectra for the hcfi compared with a red-shifted spectra for the crude oil (°API = 19). The API of the original unaltered oil which charged the reservoir is estimated to be between 32 and 38° using the Lmax-Q-API relationship established for the synthetic hcfi.     

Origin of Crude Oil in the Lunnan Region,Tarim Basin

<正>The oil source of the Tarim Basin has been controversial over a long time.This study characterizes the crude oil and investigates the oil sources in the Lunnan region,Tarim Basin by adopting compound specific isotopes of n-alkanes and biomarkers approaches.Although the crude oil has a good correlation with the Middle-Upper Ordovician(O_(2+3)) source rocks and a poor correlation with the Cambrian-Lower Ordovician((?)-O_1) based on biomarkers,theδ~(13)C data of n-alkanes of the Lunnan oils show an intermediate value between(?)-O_1 and O_(2+3) genetic affinity oils,which suggests that the Lunnan oils are actually of an extensively mixed source.A quantification of oil mixing was performed and the results show that the contribution of the Cambrian-Lower Ordovician source rocks ranges from 11%to 70%(averaging 36%),slightly less than that of the Tazhong uplift.It is suggested that the inconsistency between the biomarkers andδ~(13)C in determining the oil sources in the Lunnan Region results from multiple petroleum charge episodes with different chemical components in one or more episode(s) and different sources.The widespread marine mixed-source oil in the basin indicates that significant petroleum potential in deep horizons is possible.To unravel hydrocarbons accumulation mechanisms for the Lunnan oils is crucial to further petroleum exploration and exploitation in the region.     

Evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis: A case study using a Brazilian source rock with Type I kerogen

Hydrous pyrolysis (HP) experiments were used to investigate the petroleum composition and quality of petroleum generated from a Brazilian lacustrine source rock containing Type I kerogen with increasing thermal maturity. The tested sample was of Aptian age from the Araripe Basin (NE-Brazil). The temperatures (280–360 °C) and times (12–132 h) employed in the experiments simulated petroleum generation and expulsion (i.e., oil window) prior to secondary gas generation from the cracking of oil. Results show that similar to other oil prone source rocks, kerogen initially decomposes in part to a polar rich bitumen, which decomposes in part to hydrocarbon rich oil. These two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation. During bitumen decomposition to oil, some of the bitumen is converted to pyrobitumen, which results in an increase in the apparent kerogen (i.e., insoluble carbon) content with increasing maturation.The petroleum composition and its quality (i.e., API gravity, gas/oil ratio, C₁₅₊ fractions, alkane distribution, and sulfur content) are affected by thermal maturation within the oil window. API gravity, C₁₅₊ fractions and gas/oil ratios generated by HP are similar to those of natural petroleum considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. API gravity of the HP expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes. C₁₅₊ fractions (i.e., saturates, aromatics, resins and asphaltenes) show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition. Gas/oil ratios (GOR) initially decrease from 508–131 m³/m³ during bitumen generation and remain essentially constant (81–84 m³/m³) to the end of oil generation. This constancy in GOR is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments. Alkane distributions of the HP expelled oils are similar to those of natural crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. Isoprenoid and n-alkane ratios (i.e., pristane/n-C₁₇ and phytane/n-C₁₈) decrease with increasing thermal maturity as observed in natural crude oils. Pristane/phytane ratios remain constant with increasing thermal maturity through the oil window, with ratios being slightly higher in the expelled oils relative to those in the bitumen. Generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous, with the exception of elevated ethane contents. The general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of HP to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality.     

Comparative studies on compounds occluded inside asphaltenes hierarchically released by increasing amounts of H2O2/CH3COOH

Being the heaviest fraction of crude oils, asphaltenes are liable to aggregate, and other molecules in the oils can be steadily adsorbed onto, and even occluded inside the macromolecular structures of the asphaltenes. These occluded compounds inside the asphaltenes can survive over geological time in oil reservoirs owing to effective protection by the macromolecular structures of the asphaltenes. The asphaltenes of a crude oil (ZG31) from the central Tarim Basin, NW China, were hierarchically degraded by increasing the amount of H₂O₂/CH₃COOH to release the occluded compounds. Besides the common components, series of even numbered n-alk-1-enes and 3-ethylalkanes were detected among the occluded compounds. Comparison of the biomarker distributions and the compound-specific C isotopic results between the compounds from the maltenes and those from the occluded fraction, the ZG31 reservoir was suggested to have been charged multiple times, with different charges being derived from different strata of source rocks.