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Origin of Beatrice oil by co-sourcing from Devonian and Middle Jurassic source rocks, Inner Moray Firth, United Kingdom
Abstract
Commercial hydrocarbons in the Moray Firth area of the North Sea occur in reservoirs ranging in age from Devonian to Tertiary, with the bulk of the reserves located in Upper Jurassic and Lower Cretaceous clastic rocks. The unusual location and chemical composition of Beatrice, compared to Piper and other North Sea oils generated from the Kimmeridge Clay, have contributed to the longstanding controversy on its origin. Biomarker and stable carbon isotope analyses conclusively show that Beatrice oil could not have been generated from the classic Kimmeridge Clay source rock, but is a mixture of products derived from effective Devonian and Middle Jurassic source rocks. This work demonstrates the power of a multiparameter geochemical approach in solving this difficult oil to source rock correlation problem. -from Authors
... Furthermore, the presence of bisnorhopane in the Jarvis oil ( Fig. 10; Grudziński, 2018; this study), a characteristic biomarker of Jurassic oils and source rocks in the North Sea (Grantham et al., 1980;Peters et al., 1989;Petersen et al., 2016), and its absence in the extracts of Zechstein samples analysed, suggests a Jurassic origin for the oil. The BNH/H ratio (0.3, Table 3) is in general much higher than it is in Zechstein oils (Słowakiewicz et al., 2018) generated from Ca2 sapropelic organic matter or in potential Lower Palaeozoic source rocks. ...
... The distributions of monoaromatic and triaromatic steroids in the Jarvis oil and in extracted organic matter from the Z3C/Ca3 sample from 3531 m also show significant differences between the analysed samples (Fig. 11). Peters et al. (1989) used a monoaromatic steroid ternary diagram to correlate between the oil from the Piper field and the Kimmeridge Clay Formation source rock, which provided evidence for the origin of the Piper oil. A similar ternary diagram for both monoaromatic steroids and steranes can be used to provide a better correlation between the samples in this study, because ternary diagrams represent compounds of different origin and hence they may show independent proof for correlation purposes (Peters et al., 2005). ...
... A similar ternary diagram for both monoaromatic steroids and steranes can be used to provide a better correlation between the samples in this study, because ternary diagrams represent compounds of different origin and hence they may show independent proof for correlation purposes (Peters et al., 2005). Although accurate measurement of C-ring monoaromatic steroids in the studied samples was not performed as they require high-resolution capillary gas chromatography and authentic standards to identify peaks, the biomarker data obtained for the Jarvis oil are in general similar to those for Jurassic oils and Kimmeridge Clay Formation source rocks in the North Sea (Peters et al., 1989(Peters et al., , 2005. ...
Oil in the Jarvis structure underlying the main Upper Jurassic reservoir at the Ettrick oilfield (Outer Moray Firth, UK northern North Sea) is present in Upper Permian (Zechstein) carbonates. The origin of this “Jarvis oil” is investigated in this paper using a multidisciplinary approach based on data from well‐logs and cores from wells 20/02‐2 and 20/02‐3. Reservoirs at the Jarvis structure consist of carbonates in the upper part of the Halibut Carbonate Formation (Ca2) and in the Carbonate Member of the Turbot Anhydrite Formation (Ca3). These carbonates are typical Zechstein dolomites composed of a range of facies from mudpackstones with storm beds deposited at moderate water depths to shoreface bioclastic‐oolitic packstones to shallow‐subtidal and intertidal microbial laminites. Interbedded anhydrites replace sabkha and lagoonal selenitic gypsum. Several shallowing‐upward units are recognised. Molecular analysis of the Jarvis oil, and comparisons with biomarker and other geochemical data from extracts of Zechstein cores and published data from different source rocks from the North Sea area, suggest that the oil was generated by marine, OM‐rich shales in the Upper Jurassic Kimmeridge Clay Formation. The oil was generated at peak oil window maturity and is characterised by high Pr/Ph, BNH/H and DBT/P ratios, and abundant C 28 steranes and C 28+29 monoaromatic and C 26 R + C 27 S triaromatic steroids. The molecular composition of organic material in extracts of core samples of Zechstein carbonates from wells in the Jarvis structure differs significantly from that of the Jarvis oil. Biomarkers such as BNH are absent in the core extracts, and there are different distributions and abundances of saturated and aromatic hydrocarbons, likely controlled by thermal maturity.
... imentary rocks with C org exceeding 1 % (Hall & Douglas, 1983;Duncan & Hamilton, 1988). Biomarker composition indicates that these rocks might act as a major source of Beatrice oil produced from offshore Moray Firth (Duncan & Hamilton, 1988;Peters et al. 1989). Kerogen type seems to be poorly defined and variable, ranging from oil-prone to gas-prone. ...
... β-carotane is a highly specific biomarker associated with anoxic, saline lacustrine deposition (Peters et al. 1989). Small concentrations of β-carotane have been identified in a few samples (13/397 and 13/402; Fig. 8). ...
... Its occurrence was also reported from other lacustrine sedimentary rocks including the Middle Devonian flagstones of the Orcadian Basin by Hall & Douglas (1983), Jiang & Fowler (1986) and Duncan & Hamilton (1988). Furthermore, β-carotane as biomarker for oil-sourcerock correlation was used to provide evidence that the Devonian flagstone succession has largely contributed to the hydrocarbon accumulation of the Beatrice field (Peters et al. 1989). ...
During Middle Devonian time a thick succession of organic-rich, mainly lacustrine flagstones developed within the Orcadian Basin. These petroleum source rocks crop out in northern Scotland. Nineteen samples were studied using organic petrology, palynology and organic geochemistry in order to characterize kerogen type, depositional environment, thermal maturity and petroleum generation potential. C org , carbonate and sulphur content as well as hydrogen index (HI) values are quite variable (e.g. HI from 79 to 744 mg HC/g C org ). Based on biomarker data, organic material mainly originates from aquatic organic matter deposited under lacustrine conditions with oxygen-depleted, but not permanently anoxic, bottom waters. Petrography reveals small quantities of vitrinite particles, indicating minor input of terrestrial material. This is supported by biomarker data and the palynofacies, which is characterized by a high amount of oil-prone amorphous organic matter (AOM) and generally few miospores. Maturity of the succession studied in Caithness and Orkney is between immature and oil mature. One-dimensional basin modelling shows that a significant remaining hydrocarbon generation potential exists within the Middle Devonian succession. In contrast to the low hydrocarbon generation in the onshore area, offshore oil generation was significant, especially after deposition of thick Upper Jurassic – Upper Cretaceous sediments. At the end of Cretaceous time, hydrocarbon generation ceased due to uplift. The contribution to known oil fields from the Devonian flagstones is a realistic scenario, including a contribution to the Beatrice oil field in the south of the modelled area.
... The sedimentary and structural development of the Inner Moray Firth offshore Scotland, where the Beatrice oil discovery was made, are discussed in Linsley et al. (1980) and Peters et al. (1989). The Inner Moray Firth includes a number of rift basins that form the western limb of the Mesozoic North Sea graben system. ...
... graben in a trilete trough system (Linsley et al. 1980). In contrast to the eastern Inner Moray Firth, the Inner Moray Firth Basin remained relatively stable following early Cenozoic uplift, so that the Kimmeridge Clay remained immature (Peters et al. 1989). The Siljan impact crater in central Sweden was formed by a bolide that impacted the terrestrial landscape in the late Devonian (Vlierboom et al. 1986;Juhlin et al. 2012;Lehnert et al. 2012;Ahmed et al. 2014). ...
Norwegian oils are generally considered sourced primarily from the Kimmeridge Clay equivalent shales such as the Draupne, Mandal, Spekk and Hekkingen formations, with secondary contributions from the mid–lower Jurassic, and also from the Triassic in the Barents Sea (Botneheia Formation). Still, as most of our age inferences concerning source-oil correlation are based on facies-specific biomarkers, a number of proposed correlations have been questioned.
Thus, source to oil correlations were frequently made on the basis of facies parameters, and rightfully so, but facies-specific signatures in oils will transgress age – and, in principle, not correlate with the phylogenetic evolution. This means that one could, in principle assign an oil to ‘the wrong’ age – when one is, in fact, linking it to a known source rock signature.
A series of 40 oil samples and core extracts, which cover a wide range both stratigraphically and geographically, have been analysed. In this paper, we present for the first time a Norwegian oil-age map based on age-specific biomarkers among the nordiacholestanes and triaromatic steroids parameters, and delineate also where we find Cretaceous- and Palaeozoic-derived oils. The reasons for this distribution pattern, compared to that of Mesozoic oils on the Norwegian Continental Shelf (NCS), are discussed.
... However, crude oils characteristically contain higher relative concentrations of tricyclic terpanes compared to reservoir extracts, but much lower concentrations of hopanes and gammacerane (Fig. 12). It is widely recognized that most commercial oil accumulations are largely charged and sourced from a mixed-input source system (Seifert, 1979; Peters et al., 1989; Dzou et al., 1999; Chen et al., 2003a Chen et al., , 2003b), and so is the case for the oils from the Yanchang Formation. This mixing effect may suppress the differentiation attempt using the C 27 -C 28 -C 29 steranes plotting approach but could be obviously overcome in the combined RQ-mode factor analysis based on a set of terpane biomarker parameters. ...
... C 27 , C 28 and C 29 steranes on a ternary diagram could also support the scenario of source-oil correlation discussed above, i.e., crude oils have a close genetic relationship with reservoir extracts, while source bitumens seem to be separate from the other two (Fig. 10). The reason for using C 27 -C 28 -C 29 steroids as indicators for distinguishing sample groups is that the distributions of these sterols do not appear to be extensively altered by catabolic or chemical processes (Huang and Meinschein, 1979), and the plot locations on this ternary diagram also do not change significantly throughout the oil-generative window (Peters et al., 1989Peters et al., , 2007). Plots of source rock extracts extend widely through C 27 end member to C 29 . ...
The Yanchang Formation in the Ordos Basin is the most important petroleum play not only for conventional oil and gas accumulations, but also for newly emerging shale oil and tight gas resources. The molecular characterization of the basinwide source rocks predicts three groups of generative petroleum types: paraffinic high wax oil, mixed base (paraffinic-naphthenic-aromatic) low wax oil, and gas and condensate. Supplementary to previous work, 68 samples including the crude oils, source bitumens and reservoir extracts from the Yanchang petroleum play are analysed. The distribution of two terpane classes (eight tricyclic terpanes and eight pentacyclic terpanes) are determined with subsequent simultaneous RQ-mode factor analysis for a composite data set of these samples alongside 216 published crude oils worldwide with known facies descriptions. Thermal maturity has been evaluated as a consistent distribution at first using a combined method of a maturity-related biomarker [Ts/(Ts + Tm)] and aromatic parameters (Methyldibenzothiophene Ratios) to alleviate the maturity differences effect when discussing geochemical characterization. The R-mode factor analysis consists of the first two factors that are describing 45 present of the cumulative total variance in the data set, and presents a sample grouping pattern in Q-mode factor analysis which is determined by different contributions of terpane associations, i.e., the tricyclic C21 coupled with pentacyclic C26, C27, C28 and C30, in the same factor space. Three terpane associations, the C26 and C28 terpanes, the C21 and C30 terpanes and the C27 pentacyclic terpenes, are respectively responsible for discriminating crude oil, reservoir extracts and source bitumens in RQ-mode factor analysis. Molecular compositions further address more detailed interrelationships among three sample groups that crude oils and reservoir extracts are sharing close genetic relationships both in depositional environment typing and C27-C28-C29 sterane distribution. Samples from source rocks vary much significantly. A mixing process which occurs after oils has been expelled from host source rocks into carrier units during accumulation. In addition, the migration-contamination of C29 sterols when oils are cross through the Chang 7–2 unit along migration pathways might also explain this lack of correlation between source rocks and oil-reservoir system.
... The presence of regular C 30 steranes is suggested to be an indicator of marine-derived organic matter (Moldowan et al., 1985). According to Peters et al. (1989), the relative content of C 30 steranes can be used to distinguish oil sourced from different shales in the North Sea, i.e., oil generated from the Kimmeridge Clay has high C 30 sterane content, whereas oil derived from the Devonian shale lacks C 30 steranes. According to previous MSSV-Hy measurements of source rock and reservoir oil from different areas of the world (Yang et al., 2022), the C 30 /(C 29 + C 30 ) sterane ratios are almost 1:1 correlated in the free and bound fractions. ...
... The presence of regular C 30 steranes is suggested to be an indicator of marine-derived organic matter (Moldowan et al., 1985). According to Peters et al. (1989), the relative content of C 30 steranes can be used to distinguish oil sourced from different shales in the North Sea, i.e., oil generated from the Kimmeridge Clay has high C 30 sterane content, whereas oil derived from the Devonian shale lacks C 30 steranes. According to previous MSSV-Hy measurements of source rock and reservoir oil from different areas of the world (Yang et al., 2022), the C 30 /(C 29 + C 30 ) sterane ratios are almost 1:1 correlated in the free and bound fractions. ...
... Among the Ordovician samples, in general, more negative δ 13 C values were found for the SO-08/15, SO-09/15 and SO-10/15 samples, located towards the north-eastern part of the study area (Fig. 10).Various factors might explain such differences. According to Peters et al. (1989), oils that are derived from the same type of organic facies and that are of similar maturity will generally differ only up to a maximum of 1-1.5‰ δ 13 C. Because the maturity range is limited in the investigated Ny Friesland samples (Fig. 5), it cannot have significant effect on the δ 13 C. Thus, δ 13 C variation of up to 2.5‰ for the investigated samples (Table 2) could be attributed to organic facies, consistent with the kerogen type differences already suggested (Fig. 8). ...
Lower Paleozoic source rock (SR) characteristics and paleo-depositional environments are not well understood in the Barents Sea region. Organic and inorganic geochemical analyses of 17 carbonaceous samples from the Lower Cambrian Tokammane Formation, the Lower to Middle Ordovician Kirtonryggen and Valhallfonna formations in Ny Friesland, north-east Spitsbergen, show that there is a striking difference in petroleum generation potential and bulk geochemical properties between the Cambrian and Ordovician samples, and also within the Ordovician samples. TOC contents of <0.20 wt% for the Lower Cambrian Tokammane Formation samples indicate poor source rock richness. TOC contents in the range between 0.3 and 2.1 wt% and HI values between 123 and 424 mg HC/g TOC for the Valhallfonna and Kirtonryggen formation samples suggest significant variation in remaining petroleum generation potential with oil-prone (Type II) to mixed oil- and gas-prone (Type II/III) kerogen. Source rock maturity parameters such as Tmax (range 435–449 °C) and production indices for most Ordovician samples suggest relatively uniform maturity levels, ranging from the early-, to the peak-, of the oil generation window (i.e. ca. 0.70–0.85% Ro). This maturity level could have significant implication on the original petroleum potential assuming early generation from carbonate source rocks. Bulk carbon isotope data show that the Lower Cambrian Tokammane Formation samples are heavier (δ¹³C range from −28.4 to −28.8‰) than the Lower to Middle Ordovician Valhallfonna Formation samples (δ¹³C range from −29.7 to −30.9‰). The differences in the source rock richness and kerogen type within the Ordovician samples are attributed to organic facies variation. Tentatively, three categories of source rock organic facies (B, BC and C) are supported based on assumed-initial hydrogen index values for the Ordovician samples. The reliability of the indicated organic facies could be supported by addition of biomarker data from bitumen extracts. To our knowledge, this is the first study revealing the existence of a potential Lower Paleozoic source rocks in this part of the High Arctic, and this facies may also exist on the continental shelf to the north and NE.
... It was first discovered in the Eocene Green River Shale in Colorado (Murphy et al. 1967) and has since been found in a variety of sedimentary rocks and crude oils. Although most carotenoids do not survive early diagenetic processes, β-carotane is well preserved in sediments and oils over a wide range of depositional settings (Jiang and Fowler 1986;Peters et al. 1989;Koopmans et al. 1997;Grba et al. 2014;Ding et al. 2017). β-carotane has been extensively reported as an indicator of saline and reducing lacustrine environments (Hall and Douglas 1983;Moldowan et al. 1985;Wang et al. 2021) or an extremely restricted marine environment (Hall and Douglas 1983;Moldowan et al. 1985;Wang et al. 2021). ...
β-carotane, rearranged hopanes, tricyclic and tetracyclic terpanes, and phenyldibenzofurans are important constituents of
petroleum. To date, however, there has been only limited data on tricyclic and tetracyclic terpanes from the Niger Delta
crude oils while β-carotane, rearranged hopanes, and phenyldibezofurans have not been reported. This study explored the
geochemical signifcance of β-carotane, rearranged hopanes, tricyclic and tetracyclic terpanes, and phenyldibenzofurans in
the Niger Delta crude oils within the context of their origins, depositional environments, and thermal maturities. These data
indicate that the crude oils were derived from source rocks with signifcant terrestrial organic matter and a low contribution
of marine organic matter. These rocks were deposited under oxic to suboxic conditions in a lacustrine to fuvial/deltaic envi-ronments within the early oil window to the peak of oil generations based on the abundance of the biomarkers. However, the phenyldibenzofuran-based and rearranged hopane-based maturity ratios showed no correlations with the already established maturity ratios, implying that thermal maturity is not the signifcant factor infuencing the relative abundance of these com-pounds in the Niger Delta crude oils. This study showed that β-carotane, rearranged hopanes, and tricyclic and tetracyclic terpanes can be used to determine the origin and depositional conditions of the crude oils from the Niger Delta Basin, Nigeria.
... The smaller Pr/Ph value represents a strongly reducing environment. However, the Pr/Ph value greater than 1 belongs to an oxidizing environment, whereas the Pr/Ph value greater than 3.0 usually represents the oxic environment with higher terrestrial input (Li, 1988;Peters et al., 1989Peters et al., , 2005Zhang et al., 2020). The Pr/Ph ratio of the E 2 s 3 and the E 2 s 4 from the Laizhouwan Sag are less than 1.7, indicating the water bodies of the E 2 s 3 and E 2 s 4 were weak oxidation-weak reducing environment to a strongly reducing environment during the deposition. ...
The Laizhouwan Sag comprises many sets of source rocks, and their crude oil properties are complex and changeable. This research evaluates the quality of source rocks using mudstone samples of the Shahejie Formation from typical wells from northern and southern subsags by incorporating a detailed organic-inorganic geochemical, palynology and petrological analysis. Moreover, it analyzes the difference between the paleoenvironment and paleoproductivity. It also discusses the migration characteristics of the sag in combination with seismic data to reveal the fundamental reason for the complex oil source characteristics of the Laizhouwan sag. The results show there are two sets of effective source rocks in the northern subsag of the Laizhouwan Sag, (i) the third member of the Shahejie Formation(E2s3) (ii) the fourth member of the Shahejie Formation (E2s4). Additionally, the E2s4 is a high-quality, effective source rock in the southern subsag of Laizhouwan Sag. (2) During the sedimentary period of the E2s4 in Laizhouwan Sag, the water bodies of the southern and northern subsags were separated. The organic matter (OM) in the E2s4 of northern subsag mainly comes from lower algae, mainly amorphous, and deposited in a weak reducing environment of brackish water. The OM in the E2s4 of southern subsags mainly comes from terrigenous higher plants, mainly composed of terrigenous amorphous assemblages, and it was deposited in a strongly reducing environment of brackish water to saline water. (3) Moreover, the water bodies of the southern and northern subsags gradually changed to unified water bodies during the sedimentary period of the E2s3. During this period, OM comes from lower algae, mainly from amorphous material, and the water bodies were transformed to a weak oxidation-reduction environment from freshwater-brackish water. The subsidence center of the Laizhouwan sag continued to move southward during the sedimentary period of E2s4-E2s3. Gradually the southern subsag became a sedimentary center containing higher paleoproductivity and eutrophic lake settings. The differences in organic source, sedimentary environment and paleoproductivity of source rocks in different subsags lead to the complexity of crude oil generation features.
... β-Carotane, a saturated hydrocarbon derived from a pigment with a C 40 carotenoid structure, was first reported in the Eocene Green River Shale in Colorado (Murphy et al., 1967) and later found in numerous sedimentary rocks and crude oils. Although most carotenoids do not survive early diagenetic processes, β-carotane, however, is well preserved in sediments and oils in various environments (Jiang and Fowler, 1986;Peters et al., 1989;Koopmans et al., 1997;Grba et al., 2014;Ding et al., 2017). β-Carotane is widely accepted as an indicator of saline and reducing lacustrine environments (Hall and Douglas, 1983;Moldowan et al., 1985) or highly restricted marine environments (Requejo et al., 1992). ...
Oils reservoired in the third (Es3) and fourth (Es4) members of the lacustrine Shahejie Formation from the Dongying Depression, Bohai Bay Basin, eastern China have been analyzed by gas chromatography–mass spectrometry. Two oil families have been classified by the data assessed using chemometric analysis, including hierarchical cluster and principal component analysis. The Family I oils from the Es4 reservoirs were mainly generated from source rocks of the Es4 Member whereas Family II oils in the Es3 and Es4 reservoirs have source input mainly from the Es3 Member inferred from a series of biomarkers, including β-carotane, phytane, gammacerane and their deried abundance ratios. Parameters derived from β-carotane, such as the ratios: β-carotane/C24 tetracyclic terpane, β-carotane/(C19 + C20) tricyclic terpanes, and β-carotane/(18α(H)-22,29,30-trisnorneohopane + 17 α (H)-22,29,30-trisnorhopane), are most useful for distinguishing the oils derived from different depositional environments. β-Carotane has a high resistance to biodegradation to at least PM level 5. The abnormally high concentration of β-carotane in a few severely biodegraded oils is attributed to the removal of most vulnerable components by biodegradation, resulting in relatively concentrated β-carotane.
... land plants; ). The C 28 sterols are derived from diverse precursors (Grantham and Wakefield, 1988;Peters et al., 1989Peters et al., , 2000, but the high contribution of C 28 steranes (Fig. 8) and high ratio of C 28 /C 29 steranes (Table 2) argue for an origin related to phytoplankton (e.g. diatoms, coccolithophores, dinoflagellates; Grantham and Wakefield, 1988). ...
Eocene and Lower Oligocene rocks are potential source rocks for crude oil accumulations in the Hungarian Palaeogene Basin. To enhance the understanding of the hydrocarbon system, this study (i) assesses the petroleum potential of Palaeogene formations, (ii) characterises the source rock facies of the accumulated oils, and (iii) provides an oil-to-source correlation. Rock-Eval data of samples from three boreholes (W–1, W–9 and W–12) show that most Palaeogene formations are mature at depths exceeding 2.1–2.5 km. The coal-bearing Kosd Formation includes good to excellent gas- (and oil-) prone source rocks. The overlying Buda Marl Formation is typically organic matter-lean but contains oil-prone rocks with up to 2.3 wt% TOC and a fair petroleum potential in borehole W–9. The Tard Clay Formation in W–12 reaches up to 1.9 wt% TOC and shows HI values up to 440 mg HC/g TOC, characterising the deposits as good petroleum source rocks. Based on low TOC contents, the Kiscell Clay Formation is not considered a source rock. Molecular parameters of 12 crude oil samples indicate a shaly source rock deposited in a marine/brackish environment. Salinity stratification, causing the development of oxygen-depleted conditions, is likely. The organic matter is dominated by aquatic biomass, including algae, dinoflagellates and chemoautotrophic bacteria. Minor angiosperm-dominated organic matter was transported into the basin from the shoreline. Specific V-shaped compound-specific carbon isotope patterns of n-alkanes observed in crude oils and extracts from the Tard Clay prove the dominant source rock. Minor differences between biomarker ratios are related to vertical and lateral facies variations with the Tard Clay Formation. The accumulated oils are slightly more mature than the Tard Clay in borehole W–12.
... δ 13 C (R20) values around − 23‰ were observed in the tar sand oils regardless their degradation levels. However, the analysis of organic extracts from the Amaral Machado shale samples points to two data groups with δ 13 C from − 22‰ to about − 28‰, supporting the existence of at least two intervals with distinct organic matter and depositional paleoenvironment type in the outcrop: facies Irati A and Irati B (Sofer, 1984;Peters et al., 1989;Sun et al., 2000;Li et al., 2015b). ...
The Pirambóia Formation tar sands constitute one remarkable occurrence of heavy oil in the eastern border of the Paraná Basin, São Paulo State, Brazil, being characterized as highly degraded oils related to the Irati-Pirambóia oil system. In this context, the aim of the present work was to investigate biomarkers that are more resistant to degradation and use them to establish a more reliable geochemical correlation between the tar sand oils of the Pirambóia Formation (collected from the Fazenda Betumita and Guareí I outcrops) and the organic extracts of black shales of the Irati Formation (facies Irati A and B, collected in the Amaral Machado Quarry, São Paulo State). For this purpose, analysis of stable carbon isotopes and diagnostic ratios of saturated and aromatic biomarkers were investigated, and the most reliable diagnostic ratios were selected based on the principal component statistical analysis. The results pointed to different degradation extent between the tar sand outcrops, being higher for the Guareí I samples. In this scenario, it was verified that most of the diagnostic ratios commonly used in oil-source rock correlation studies were susceptible to degradation processes. It was also observed that samples from Pirambóia and Irati formations are at the beginning of the oil generation window, with the C29 ββ/(αα + ββ) ratio as the most suitable to assess thermal maturity of extremely degraded oils. The multivariate statistical analysis of the results, based on ten more resistant diagnostic ratios, allowed to select six main variables responsible for the similarity between the samples from the Irati and Pirambóia formations: δ13C (‰), TPP ratio (C30 tetracyclic polyprenoids over diasteranes), %C28 and %C29 monoaromatic steranes, (C20 + C21)/(C23 + C24) tricyclic terpanes, and C23 tricyclic terpane/(C23 tricyclic terpane + C29 hopane). These geochemical parameters showed greater reliability in the correlation between the Pirambóia Formation tar sand oils and the Irati samples of the facies A, deposited in a restricted marine environment under anoxic-euxinic conditions.
... Substantial amounts of information obtained from Rock-Eval pyrolysis are essential for comprehensive analysis of the properties of source rocks (Peters et al., 1989). The rock pyrolysis experiment in this study was performed using a Rock-Eval-II instrument. ...
The Chepaizi Uplift possesses three sets of oil-bearing reservoirs, six sets of source intervals, multiple episodes of hydrocarbon charging, and variable physical properties of crude oils. In this study, based on geochemical characterization source intervals and the biodegradation rank of the crude oils, four oil populations named as group A, B, C, and D (D1, D2) were defined. The combined results of Q-cluster analysis (QCA) and discriminant analysis (DA) indicate that group A occurred mainly in Lower Neogene Shawan Formation (N1s) in the western Chepaizi Uplift and were primarily derived from the Middle-Lower Jurassic Xishanyao, Badaowan, Sangonghe formations (J2x-J1b-J1s) and a little of Paleogene Anjihaihe Formation (E2-3a) of the Sikeshu Sag. Group B occurred essentially in Upper Carboniferous Xibeikulasi Formation (C2x) of the western Chepaizi, and originated mainly from the J1b mudstone of the Shawan Sag. In addition, the crude oils of group C occurred mainly in the Lower Cretaceous Tugulu Group (K1tg) of the eastern Chepaizi and were primarily derived from Carboniferous-sourced oil from the Chepaizi Uplift. The crude oils of groups D (D1 and D2) are mixed with Permian (P1f and P2w) of Shawan Sag and Carboniferous-sourced oil from the Chepaizi Uplift. Based on the reconstruction of the migration history, the oils of group A in the N1s Formation of western Chepaizi migrated predominantly from the south (Sikeshu Sag) to the north and northeast, with wells Su1-2 and C27 as the initial filling points. The oils of group B in the N1s Formation of the western Chepaizi travelled predominantly from the southeast (Shawan Sag) to the north and northwest. The oils of group D1 in the C2x Formation of eastern Chepaizi migrated mainly from the northeast and southeast (Shawan Sag) to the west, with well P661 as the initial filling point. Wells SM011 and C64 are the initial filling points of the K1tg Group in the Hongche Fault Belt. Crude oils of group C in the K1tg Group travelled predominantly from the southeast (Shawan Sag) and northeast to the west into the eastern Chepaizi and from well P68 to the southwest. According to the paleo-oil preferential filling orientations and paleogeomorphology, some favourable targets for petroleum exploration of the Chepaizi Uplift are forecast in this study.
... The features of KCF source rock are a significant enrichment of C 33-35 homohopanes (de Leeuw and Sinninghe Damsté, 1990), a high abundance of 28,30-bisnorhopane (Grantham et al., 1980;Peters et al., 1989), a dominance of C 27 and C 29 steranes (Mackenzie et al., 1983;Huc et al., 1985), and the presence of isorenieratene derivatives (van Kaam-Peters et al., 1997;Sinninghe Damsté et al., 2001). ...
We report on the discovery of oil from the Boulby Mine and its likely productive source rock from Yorkshire in NE England, located to the west (<30 km) of the newly licensed petroleum exploration areas in the vicinity of the Mid-North Sea High. Oil samples from the mine, dripping out of halite in the roof, have likely been generated
from Zechstein Group Kirkham Abbey Formation (KAF) sapropelic carbonate rock as indicated by aliphatic and aromatic hydrocarbon biomarkers. Other potential source rocks of Carboniferous (Westphalian, Namurian, Vis´ean coals and mudrocks) and Jurassic (the Jet Rock, Bituminous Shales, Kimmeridge Clay Formation) age are ruled out on the basis of organic geochemical data. Boulby oil was generated in the peak-to-late oil-window and it is characterised by the high abundance of C32 and C34 homohopanes, slight even-over-odd predominance (EOP) of C20-25 n-alkanes indicating restricted carbonate-evaporite depositional conditions, and C29 ethyldiacholestane 20 S likely implying a clay-rich source rock. The structural framework and tectonic history of the Permian strata reveal the presence of several fault systems which served as conduits for migrating petroleum. Similar Zechstein-sourced oil is known from Poland and Germany, but the occurrence at Boulby is the first
positive identification of oil derived from Zechstein source rock in the North Sea area. The Boulby oil is reservoired in Zechstein 3 (Z3) Brotherton Formation dolomite and sealed by Z3 evaporite rocks. The proven oil occurrence at Boulby has significant implications in terms of reducing the risk of a lack of oil mature source rock for acreage offered in the neighbouring North Sea during the UK’s 30th and 31st licensing rounds.
... Since carbon isotope ratios are the volume characters of oil they are used to qualitative guess the source inputs of different types of oils. Peters et al., (1989) noted differences in carbon isotopes of all oils between oil of petresa oil field and bitumen of source rocks and concluded that oil origin of two types of oil source rocks, this is done using the following simple equation: ...
This study includes a palynological and organic geochemical study of Nahr Umr, Zubair, and Yamama Formations in the Subba field, southern Iraq represented by the wells (Su-14, Su-9, and Su-8). These analyses include the determination of quantity organic matter; which indicate is that, the rocks of Nahr Umr Formation are very good rocks for the production of hydrocarbons and its kerogen of type (II) is dominant, but thermal immaturated, while the ability of the Zubair Formation for the production is good to very good and its kerogen of type (I &II/III) is dominant, and low thermal maturity, and the ability of Yamama Formation is good for the production of hydrocarbons, and the kerogen of type (I) is dominant, and low thermal maturity.
Facies analysis of Nahr Umr, Zubair, and Yamama Formations shows the presence of two facies , they are :
(1) Distal dysoxic – Oxic shelf (2) Distal suboxic – Anoxic basin.
It is clear that the environment of rock deposition is a marine environment far from the coast.
The geochemical analyses of the crude oil accumulated in Nahr Umr, Zubair, and Yamama Formations in wells (Su-14, Su-9, and Su-8), the ratios of biomarkers which are related to their age are studied, such as, ratios: OL/H, C28/C29 and indicate Middle Triassic - Upper Jurassic age and Upper Jurassic - Lower Cretaceous age. But the biomarkers related to maturation, such as, Ph/nC18 and Pr/nC17 shows that the crude oil is thermally mature in the Yamama, and Zubair Formations .
The biomarkers and non-biomarkers related to the source, such as, the ratios: Tet/C23, C28 /H, Pr, Ph and CPI indicate that the source rocks of the Yamama, and Zubair Formations are carbonates or carbonates interfered with shale or marl deposited in anoxic marine environment with normal salinity and kerogen type (II) of algal origin, matured and did not undergo a biodegradation process .
On the other hand, analyses of carbon isotopes, such as, the ratios δ13C%, δ13Caro, δ13Csat, and Pr/Ph indicate that the previous conclusions are the same for biomarkers and non-biomarkers.
It is clear from the above results that the crude oil accumulated in Nahr Umr, Zubair, and Yamama Formations are from Middle Triassic - Upper Jurassic source rocks and the most important of them is Geli Khana and Sargelu Formations.
... (3) Terpanes Tricyclic terpanes were thought to be derived from algae such as Tasmanites algae or bacteria (Simoneit et al., 1986;Peters and Moldowan, 1993). C 19 or C 20 tricyclic terpanes are abundant in terrigenous organic matter, while C 23 tricyclic terpane is often the dominant homologue in sediments with a marine source (Peters et al., 1989). Abundance of C 19 tricyclic terpane is much lower than its C 23 homologue with the C 19 /(C 19 + C 23 ) tricyclic terpane ratio varying in a range of 0.08-0.25 (average 0.13). ...
... 甾烷源自真核生物体内的甾醇 [3,29] . C 27~29 甾烷三 角图在整个生油窗内很稳定, 可以有效地区分不同 源岩及相同源岩不同有机相的原油 [3,30,31] , 并被广泛 用于研究原油及沥青的亲缘关系 [32,33] . ...
... C 27 sterols are found mostly in algal organic matter and zooplankton, while land plants or freshwater microalgae dominantly contain C 29 sterols (Volkman, 1986;Kodner et al., 2008). The C 28 sterols are thought to be derived from various sources (Grantham and Wakefi eld, 1988;Peters et al., 1989Peters et al., , 2000. In the present case, the change in carbon number distribution of steranes from C 27 -to C 29 -dominance in Units 2 and 4 occurs in the same depth interval as the change in the predominance of short to intermediate molecular weight n-alkanes (Table 2), which may indicate an increased contribution from microalgae (Volkman et al., 1998) and macrophytes. ...
The Middle Jurassic Shimengou Formation in the Qaidam Basin, NW China, includes coals and lacustrine source rocks which locally reach oil shale quality (i.e. yielding >3.5 % oil on low‐temperature distillation). In the present study, the palaeo‐depositional environment and hydrocarbon potential of the 84.5 m thick Shale Member of the Shimengou Formation are investigated based on bulk geochemical parameters, organic petrographic data, biomarker analysis, and stable isotope geochemistry of 88 core samples.
The Shale Member was deposited in an anoxic freshwater lake which formed following the drowning of a precursor low‐lying mire. Variations in bulk geochemical parameters allow four informal units to be identified, referred to (from the base up) as Units 1 to 4. These contain intervals of oil shale of varying thicknesses. In Unit 1, mudstones in the interval referred to as oil shale Layer 1 (true thickness [TD]: 2.06 m) are OM‐rich as a result of algal blooms and photic zone anoxia, and correspond to an initial flooding event. Subsequently, productivity of aquatic organisms decreased, resulting in the deposition of organic‐lean mudstones in Unit 2. Oil shale Layers 2 (TD: 2.03 m) and 3 (TD: 8.03 m) near the base of Unit 3 were deposited during maximum water depths. As with Layer 1, high productivity by algal blooms resulted in photic zone anoxia in a stratified water column. The shales in the upper part of Unit 3 are characterized by high TOC contents and a gradual increased input of terrigenous OM, and were deposited in a stable semi‐deep lake. Finally, organic‐lean mudstones in Unit 4 were deposited in shallow lacustrine conditions. The reconstruction of depositional environments in thick, non‐marine shale‐rich successions by mineralogical, petrographic and inorganic geochemical methods may be challenging as a result of the homogenous composition of component mudstones. The results of this study indicate, however, that sub‐division and basin‐wide correlation of such intervals can be achieved by organic geochemical analyses.
Oil shales and organic‐rich mudstones in Units 1 and 3 of the Shimengou Formation Shale Member are excellent oil‐prone source‐rocks with a Source Potential Index of 3.2 t HC/m². Considering the large area covered by the Shimengou Formation in the northern Qaidam Basin (∼34,000 km²), the results of this study highlight the regional significance for future petroleum exploration. They indicate that variations in organic productivity and dilution by minerals are key factors controlling the abundance and type of organic matter in the formation. An understanding of these factors will assist with the identification of exploration targets.
... Algae have been proposed to be the leading primary producer of C 27 sterols, while land plants are associated with C 29 sterols [37]. In contrast, C 28 steranes are believed to have been derived from a variety of sources [38][39][40][41]. Based on a ternary diagram plotting the relative proportions of C 27 , C 28 and C 29 steranes (Fig. 8), we suggest that algal and mixed planktonic- bacterial OM sources dominate the lower oil shale layers (layers 1 to 3), whereas mixed plankton and land plant sources dominate the upper oil shale layers (layers 4 to 6). ...
In the Songliao Basin, northeastern China, the oil shale-bearing succession in the Upper Cretaceous Qingshankou Formation contains excellent source rocks. Oil shales with different total organic carbon (TOC) contents and oil yields developed in the lower member of the formation (K 2 qn ¹ ). In this study, we apply gas chromatography-mass spectrometry (GC-MS) to determine the geochemical characteristics, organic matter (OM) sources and depositional environments of various grades of oil shale. Rock- Eval pyrolysis indicates that type I kerogen is the predominant organic matter in the K 2 qn ¹ oil shale, though variability in n-alkanes, steranes and hopanoids contents implies that organic matter from a variety of sources is present. High-quality oil shales are dominated by phytoplanktonic/algal and bacterial organic matter, while lower-quality oil shales are dominated by planktonic kerogen with a minor contribution from land plants. Organic matter types can indicate a high shale oil conversion rate, and increased prospects for oil shale utilization. Oxygen-deficient bottom water conditions, related to salinity stratification, are evidenced by biomarker ratios (Pr/Ph, gammacerane index (GI)). We propose that the highest-quality oil shales were deposited under anoxic conditions, with strong salinity stratification of the water column. OM sources, redox conditions and water column salinity stratification were the key factors controlling the accumulation of highquality oil shale in the southeastern Songliao Basin.
... 1: HD25, 2: HD31C; 3: HD26; 4: HD261; 5: HD27; 6: HD301; 7: HD30; 8: YK1; 9: YK201H; 10: YK301; 11: YK3; of different petroleum sources to mixed gas or oil samples can be evaluated if the compositions (molecular or isotopic) of the end member sources are known. The compositions of the end members change linearly with mixing ratio(Peters et al., 1989; Chen et al., 2003; Li et al., 2010a; Zhu et al., 2011; Tian et al., 2012; Jenden et al., 1993;Xia et al., 1998; Jin et al., 2004).However, end member sources are often unknown or unavailable. In these casesstatistical algorithms may help evaluate mixing proportions. ...
... Thus, both Devonian and Jurassic sedimentary successions are plausible origins for hydrocarbons in the region. This is reflected in the attribution of regional hydrocarbon shows to alternatively Devonian (Marshall, 1998) or Jurassic (Underhill, 1991) sources, based on different interpretations of burial history, or to a mixture of both sources based on biomarker evidence (Peters et al., 1989(Peters et al., , 1999. ...
Black sediment veins up to 2 cm width penetrate the Caledonian Helmsdale Granite in the vicinity of the Helmsdale Fault, onshore Moray Firth. The black colour and geochemistry of the veins reflect a high content of organic carbon. Both Devonian and Jurassic shales are conceivable available sources, but sterane compositions relate the organic matter to the Jurassic shales. A content of extractable organic matter higher than in the shales suggests that the carbon in the veins represents oil rather than mechanically mobilized shale. The oil was present during sediment vein emplacement. The veins were emplaced forcefully, which may reflect high fluid pressure associated with post-Jurassic movement on the Helmsdale Fault.
... High BNH concentrations are related to clay-poor source rocks that are deposited under anoxic conditions and result in Type IIS kerogen formations (Peters et al., 2005). Variations in BNH signal intensity suggest differences in the redox conditions during deposition, but could also be due to: (a) maturity, since the concentration of BNH decreases with maturity (Peters et al., 1989), for example the Querecual Formation ( Fig. 9) and (b) biodegradation (Peters et al., 2005), for example the oil from Lagunillas (Fig. 8). ...
This work presents a study of vanadium, nickel and sulfur concentrations and biomarkers in a suite of crude oils and source rocks from three Venezuelan basins (Maracaibo and Eastern basins and Barinas sub-basin). Crude oils range from unaltered to altered by biodegradation, and source rocks are characterized by having different kerogen types (Type II, III or IV) and maturity levels (early mature to post-mature). Vanadium, nickel and sulfur concentrations, V/Ni or V/(V+Ni) and saturate biomarkers were used to classify the oils and source rocks based on inferred paleo-redox environment, lithology and maturity of the source rock. Oils are classified into five groups based on V/Ni ratios; they appear to be related to variations in the paleo-redox environment (from suboxic-dysoxic to anoxic-suboxic) of source rocks with variable lithological composition and organic matter input, regardless of their maturity or biodegradation level. These five groups are also classified based on biomarkers related to maturity, organic matter type, paleo-redox environment and source rock lithology. In source rocks, vanadium, nickel and sulfur concentrations, together with V/Ni or V/(V+Ni) ratios, provide information about the paleo-redox environment and are related to lithology, regardless of their maturity. These results also indicate variable paleo-redox conditions during the sedimentation of Venezuelan source rocks. All this suggests that, while the main source rocks in Venezuelan basins are well established, there are still uncertainties regarding their lateral and vertical variations in organic and inorganic facies and paleo-redox conditions. The presence of other source rocks contributing to the accumulation of hydrocarbons in the Venezuela basins is also a possibility.
... Stable carbon isotopes have long been used to classify oils or distinguish source depositional environments (Sofer, 1984;Peters et al., 1989;Sun et al., 2000;Li et al., 2015). The Mahu oils are isotopically very similar, generally ranging from À30.33‰ to À28.04‰ (Table 1), but some differences exist among them. ...
The origin of crude oils and their varied geochemical features along the western and northern slope of the Mahu depression in the Junggar Basin has been controversial. Based on the molecular and isotopic geochemistry of hydrocarbons from 46 drill-stem test crude oil samples and 36 core samples, three oil groups (I, II, III) and five subgroups (I1, I2, II, III1 and III2) have been recognized and oil-source correlations have been established. The subgroup I1 oils originated mainly from lower Permian Fengcheng (P1f) carbonate source rocks, subgroup I2 from P1f mudstone source rock and group II oils from Middle Permian Wuerhe (P2w) mudstone source rock whose potential was underestimated in the past. Group III consists of mixed oils, i.e., subgroup III1 received contributions from P1f carbonates and P2w mudstones and subgroup III2 is a mixture of oils from P1f mudstones and P2w-generated oils. In order to determine the main source rocks, the laboratory oil mixing experiments were carried out. Tricyclic terpane biomarker parameters (TTs) were used to quantify the source contributions. Whole oil carbon isotope ratios were also used to verify the proportions of different oils in each mixture. The results show that subgroup III1 oils have diverse mixing ratios in different reservoir, subgroup III2 oils are mainly from P1f mudstones and P2w source rock contributes little. Finally, the accumulation process of oil fields along the northern slope of the Mahu depression was analyzed and the contributions from different sources were revealed. This study provides an effective quantitative method to identify contributions from different lacustrine source rocks to mixed oils in the Mahu depression, which could be helpful in predicting location and composition of undiscovered oils.
... The distribution of C 27 -C 29 regular steranes is very stable in the oil-generation window and can be used for oil-oil and oil-source rock correlation and to assess source and depositional environ-ment (Seifert et al., 1984;Peters et al., 1989Peters et al., , 2005. With the temperature increasing from 350°C to 400°C, the relative abundance of C 27 5a,14a,17a, 20R-cholestane for GY-17 kerogen increases from 0.49 to 0.64 (Table 4), while C 28 5a,14a,17a, 20R-24-methylcholestane decreases from 0.30 to 0.19. ...
Hopanes and steranes are the two of the most commonly used biomarker classes in the application of organic geochemistry to petroleum exploration. The same carbon skeletons also occur as a bound fraction, and can be used in a relatively high maturity range compared to their extractable (free) counterparts as a result of protection by the kerogen macromolecular structure. The pools of free and bound biomarkers are expected to be thermally degraded over geological time. There has been little work to address the chemical stabilities of hopanes and steranes in both free and bound forms. This study uses anhydrous pyrolysis to simulate the thermal evolutions of biomarkers from two Type II kerogens. The bound biomarkers within the above thermally altered kerogen residues were also released by catalytic hydropyrolysis and discussed in this study. The anhydrous pyrolysis results show that source-related parameters based on hopanes are more stable than those based on steranes. The hydropyrolysis results show that the bound hopane distributions are quite stable even at 460 °C (Easy%Ro = 2.86), while the bound sterane distributions are changed beginning at 430 °C (Easy%Ro = 2.27). This indicates that the thermal stability of steranes is lower than that of hopanes in both free and bound fraction which can be explained by the different chemical structure and mode of incorporation of their precursors into kerogen.
... Nevertheless, the presence of complex hydrocarbon mixtures demands the implementation of additional and more specific geochemical and isotopic analyses to decipher them and to better understand the petroleum systems in the HB. A valuable tool used in the current study is the analysis of compound-specific carbon and hydrogen isotopic compositions, which has been successfully applied to better constrain oil-to-oil and oil-to-source correlations (e.g., Schoell and Hayes, 1994;Li et al., 2001;Schimmelmann et al., 2004) and to characterize and quantify oil mixtures (e.g., Peters et al., 1989;Chen et al., 2003). Furthermore, diamondoid data have been included because they are very suitable to determine high thermal maturity contributions from source rocks topetroleum fluids in reservoirs (e.g., Chen et al., 1996;Li et al., 2000;Fang et al., 2012). ...
... The distribution of the C 27 -C 28 -C 29 regular steranes was widely used in oil-source correlations due to the stability of regular steranes in the oil window (Peters et al. 1989). The distribution of the C 27 -C 28 -C 29 regular steranes in the hydropyrolysates H-SW-8 was dominated by the C 27 -aaaR sterane (Fig. 4A), while in the EOM from the P 1 q mudstone WC-3, it was dominated by the C 29 -aaaR sterane. ...
There are abundant bitumens and oil seepages stored in vugs in a Lower-Triassic Daye formation (T1d) marlite in Ni’erguan village in the Southern Guizhou Depression. However, the source of those oil seepages has not been determined to date. Multiple suites of source rocks of different ages exist in the depression. Both the oil seepages and potential source rocks have undergone complicated secondary alterations, which have added to the difficulty of an oil-source correlation. For example, the main source rock, a Lower-Cambrian Niutitang Formation (Є1n) mudstone, is over mature, and other potential source rocks, both from the Permian and the Triassic, are still in the oil window. In addition, the T1d oil seepages underwent a large amount of biodegradation. To minimize the influence of biodegradation and thermal maturation, special methods were employed in this oil-source correlation study. These methods included catalytic hydropyrolysis, to release covalently bound biomarkers from the over mature kerogen of Є1n mudstone, sequential extraction, to obtain chloroform bitumen A and chloroform bitumen C from the T1d marlite, and anhydrous pyrolysis, to release pyrolysates from the kerogen of T1d marlite. Using the methods above, the biomarkers and n-alkanes released from the oil samples and source rocks were analysed by GC–MS and GC-C-IRMS. The oil-source correlation indicated that the T1d oil seepage primarily originated from the Є1n mudstone and was partially mixed with oil generated from the T1d marlite. Furthermore, the seepage also demonstrated that the above methods were effective for the complicated oil-source correlation in the Southern Guizhou Depression. © 2015 Science Press, Institute of Geochemistry, CAS and Springer-Verlag Berlin Heidelberg
... 46), drilled in 1984 to a depth of approximately 80 m, indicated organic carbon contents up to 2.4%. Indeed, the lacustrine Middle Old Red Sandstone rocks are thought to have been a significant contributory source for economic hydrocarbon resources trapped in Mesozoic sandstone reservoirs in the Beatrice oilfield, Moray Firth (Marshall et al., 1985; Peters et al., 1989). ...
There is potential for increased groundwater-rock reaction due to the emplacement of a deep disposal facility for radioactive wastes. Characterisation of dissolving/precipitating phases will be important for fluid flow and sorption studies. Increased groundwater-rock reactions may also mobilise naturally-occurring hydrocarbons preserved in veins, fluid inclusions and bulk rocks. The development of elevated concentrations of organic species in porefluids in the repository environment may lead to enhanced radionuclide solubility and migration.
Laboratory experiments have been conducted to assess the potential for water-rock reaction and mobilisation of organics from a typical organic-bearing flagstone from Caithness in synthetic groundwater. Experiments were conducted under both ‘reducing’ and ‘oxidising’ conditions to assess the effects of redox conditions upon organic mobilisation and the scope ofwater-rockreactions. Elevatedtemperaturesandpressureswereusedtoenhancethespeed of water-rock reactions.
A sample of organic-rich Caithness Flagstone (‘Facies B’) taken from outcrop at Castletown Quarry, near Thurso,Caithness was used for the study.Mineralogically,theFlagstone consisted of quartz, K-feldspar, plagioclase feldspar, muscovite, biotite, chlorite, carbonates (calcite, dolomite and ankerite), gypsum and trace sulphides. The disaggregated Flagstone was reacted with a synthetic, neutral pH, Na-Ca-HCO3-C1groundwater (TDS -300 mg/l) under batch conditions at 70 O C , 30 MPa at a water/rock ratio of 2:1 for 3 months under both ‘reducing’ and ‘oxidising’conditions.
No significant amounts of organic species were identified in the most evolved fluid samples from the experiments. Water-rock reaction was relatively minor, consisting principally of dissolution of carbonate and sulphates with minor contributions from silicates such as biotite andfeldspars.Nosignificantdissolution of sulphideswasobserved.Evolvedfluid compositions were dilute (TDS = 500 mgA) with little difference between ‘oxidising’ and ‘reducing’experiments. Fluidswerealkaline(pH=8),withaslightlyhigherpHdeveloped throughout much of the ‘oxidising’experiment, which was probably related to the dissolution of Fe-rich biotite. Steady-state (time invariant) concentrations were developed for Na, K, Mg, Ca, Sr, Ba, Mn and SO,2-. SiO, and HC0,- concentrations were still increasing at run termination. Slightly greater concentrations of most chemical components were developed in the ‘reducing’ experiment. All components showed net gains in solution in both experiments exceptforNa in the‘reducing’experiment. Iron hydroxidewas the only solidphase positively identified as a product of water-rock reaction.
The results of the experiments suggest minor groundwater-rock reaction in the Caithness Flagstones due to the emplacement of a radioactive waste repository. The mobilisation of organics from rocks into the groundwaters at Dounreay would also be relatively insignificant, but it should be noted that the organics present in the sample used in the experiments were a kerogen-type material, but elsewhere in the Caithness Flagstones more volatile or liquid hydrocarbons are known to occur in small amounts, and whichcould be more mobile.
This report was prepared by the British geological Survey under contract to United Kingdom Nirex Limited (NIREX). The main technical work reported here was carried out in the period 1 April 1989 to 3 1 March 1990, and the report is based upon, and solely refers to information available at that time. Thus for example, where the report refers to ‘current knowledge’ this shouldbereadtomean‘knowledgeexistingatthetimetheworkwascarriedout’. The work forms part of the Nirex Safety Assessment Research Programme.
... First studies applied the "oil fingerprinting" to predict the mixing and commingled features between oils (Hwang et al., 2000Kaufman & Ahmed, 1990). Peters et al. (1989) have used the carbon isotopic composition of the oil and source rock extracts to evaluate the mixing between Jurassic and Devonian hydrocarbons in Beatric Basin, UK. Source-, age-and biodegradation-related biomarkers have been applied to distinguish and recognize oil mixing in some Scottish (Peters et al., 1999b), Colombian (Dzou et al., 1999), Lioahe Basin (Koopmans et al., 2002) and Williston Basin (Jiang & Li, 2002) oil fields. ...
Located in the northern part of Arabian Peninsula, Syria is one of the Middle East oil countries. The most petroliferous province in Syria is the Euphrates Graben system in the eastern part of the country. Oil and gas have been discovered in this graben in the mid 1980's by Shell E&P and its partners. Since then no comprehensive study has been performed to investigate the origin of crude oils produced from more than 60 oil fields in the area. This study deals with this issue from a petroleum geochemistry perspective and tries to answer open questions regarding the source of light and heavy oils produced over the Euphrates Graben. Eighty two oil samples in addition to 37 rock samples have been analysed geochemically in order to investigate the molecular composition of hydrocarbons and the maturation degree of their associated source rocks. Routine geochemical analysis in addition to stable isotopes and diamondoid analyses were carried out for 30 oil samples. Based on gross composition, biomarker and non-biomarker characteristics, oil-oil correlation identified three oil families in the study area: Family 1, Family 2A and Family 2B. Crude oils of Family 1 have been found to be generated from a marine, clay-rich and highly mature source rock. The related source rock is older than Jurassic in age based on age-related biomarker parameters. Maturity-related parameters (aliphatic biomarkers) and non-biomarkers (like diamondoids) imply that a highly mature source rock is responsible for generating Family 1 crude oils. These features fit very well to Palaeozoic Tanf Formation (Abba group) which is equivalent to Lower Silurian Hot Shales found elsewhere in the Middle East and North Africa. However, the Upper Cretaceous R'mah Formation and Shiranish Formation were found to be responsible for generating the remaining crude oils studied here. Compositional and molecular differences between families 2A and 2B were attributed to facies and subtle maturation variations. Geochemical oil-source rock correlation supported the classification of oil families that Family 2A was most likely generated from the Shiranish Formation, while the R'mah Formation was the source rock for Family 2B oils. According to the very complex tectonic situation of this rift basin and, additionally, the lack of geological data, it was not possible to definitely retrace the migration pathways for oils from source rocks to reservoirs. However, an attempt to figure out the potential migration fairways is presented by concepts for trap configurations for specific areas especially for crude oils found in shallow Miocene reservoirs. To predict to which extent these oil families could mix with each other, oil mixing mathematical models have been applied for crude oils, which have different signatures from different source. The results of the theoretical mixing were promising and showed that some oils in the southeastern part of the graben generated principally from the Upper Cretaceous R'mah Formation, and have got significant contribution from a Silurian source rock. These findings about petroleum mixtures could support the attempts to find more hydrocarbon plays in the Palaeozoic section in south- and northeastern part of the graben by retracing possible oil migration routes. Secondary alteration processes inuenced the petroleum composition particularly in shallow reservoirs. Geochemical investigations for crude oils in the northwestern part of the graben showed that biodegradation took place resulting in lower API gravities and poorer light ends.
... igh concentration occurs in Lower Oligocene sediments deposited within a stratified water column , characterized by low Pr / Ph and low MTTC ratios ( Table 2 ) . b - Carotane was first identified in the Green River Shale ( Murphy et al . , 1967 ) and was later found in numerous sedimentary rocks and crude oils ( e . g . , Jiang and Fowler , 1986 ; Peters et al . , 1989 ; Keely et al . , 1993 ) . It is suggested to be indicative of highly reducing conditions involving salinity stratifi - cation , since it has typically been found in lacustrine and highly re - stricted marine depositional settings ( Peters et al . , 2005 ) . The aromatic hydrocarbon composition is further characterized by the occurrence ...
The Eggerding Formation, typically about 45 m thick, forms part of the deep marine Oligocene succession in the Molasse Basin, which comprises from bottom to top the Schöneck (formerly "Fish Shale"), Dynow ("Bright Marlstone"), Eggerding ("Banded Marl") and Zupfing formations ("Rupelian Marl"). The Eggerding Formation and the lower part of the Zupfing Formation have been studied using core and cuttings samples and a multidisciplinary approach involving core description, geochemistry, palynology and nanno-paleontology. The Dynow Formation and the lower part of the Eggerding Formation were deposited during nannoplankton zone NP23 (Martini, 1971). The transition between the Dynow and Eggerding formations is characterized by a gradual decrease in carbonate contents. The Eggerding Formation deposited in near-shore environments contains several sand layers. In contrast, the Eggerding Formation deposited along the northern slope is generally poor in sand. Its lower part consists of dark grey laminated shaly marlstone with white bands rich in coccolithophorides. TOC contents are about 5 %. The upper part of the Eggerding Formation consists of a homogenous sequence of marly shale and includes in average 1.6 % TOC. Oxygen deficient conditions prevailed during deposition of the Eggerding Formation. Marine palynomorphs are present in all samples from the Eggerding Formation, but calcareous nannoplankton is restricted to its lower part. Salinity variations are recorded in rocks of the lower part of the Eggerding Formation. The environment during deposition of its upper part was more stable. Log signatures, which are comparable over tens of kilometres, provide evidence for the lateral continuity of the Eggerding Formation deposited on the upper slope. Slope instabilities are indicated by slumps and extensive submarine slides. Sliding reached a maximum at the transition from the Eggerding to the Zupfing Formation, when locally a succession up to 70 m thick was removed from the northern slope. The slided material was redeposited either on the northern slope or at the base of the slope. The Eggerding Formation is overlain by the Zupfing Formation (NP24), consisting of clay marl up to 450 m thick. Oxygen-depleted conditions continued during deposition of the Zupfing Formation, but only the lowermost few meters of the Zupfing Formation ("Transition Zone") are rich in organic matter (1.5 % TOC). Whereas the lower part of the Eggerding Formation (TOC 1.9-6.0 %; HI up to 600 mg HC/g TOC) holds a very good source potential for oil (and gas), its upper part and the Transition Zone (TOC: ~1.5 %; "true" HI 500-600 mg HC/g TOC) are characterized by a good potential. Biomarker data suggest that the latter contributed significantly to the Molasse oils. In contrast, the contribution of the Dynow Formation and the lower Eggerding Formation was minor.
... These characteristics make it possible that reservoirs of source-mixed gas can be generated from the same source rocks with various mature stages, or generated from two or more different source rocks with various mature stages. Source-mixed gas commonly exists in coal-containing and hydrocarbon-containing basins in the world [2][3][4][5][6][7]. In these basins, the most commonly two types of source-mixed gas are as follows: the mixing of coal-type gas and oil-type gas and the mixing of gas from the same source rock with various mature stages [8][9][10][11]. ...
The current study tested the gas component and carbon isotopic composition of gas samples from 6 oil-gas fields at the northern margin of Qaidam Basin, and established a chart to quantitatively identify the mixing ratio of source-mixed gas. Besides, this research quantitatively investigated the natural gas generated by different types of organic matter. The results show that different ratios of source-mixed gas exist in the 6 oil-gas fields at the northern margin of Qaidam Basin. Among them, Mabei has the highest mixing ratio of coal-type gas, followed by Nanbaxian, Mahai, Lenghu-4, Lenghu-3 and Lenghu-5, with the ratios of coal-type gas 91%, 87%, 83%, 66%, 55% and 36%, respectively. Lenghu-3 and Lenghu-4 oil-gas fields were mainly filled by coal-type gas earlier. For Lenghu-3, the gas was mainly generated from low matured source rocks in lower Jurassic Series of Lengxi sub-sag. For Lenghu-4, the gas was mainly generated from humus-mature source rocks in lower Jurassic Series of the northern slope of Kunteyi sub-sag. Gas in Lenghu-5 was mainly later filled oil-type gas, which was generated from high matured sapropelics in lower Jurassic Series of Kunteyi sub-sag. Earlier filled coal-type gas was the main part of Mahai, Nanbaxian and Mabei oil-gas fields. Gas source of Mahai was mainly generated from high mature humics in lower Jurassic Series of Yibei sub-sag; for Nanbaxian, the gas was mainly generated from high matured humics in middle-lower Jurassic Series of Saishiteng sub-sag; for Mabei, the gas was mainly generated from humus-mature source rocks in middle Jurassic Series of Yuqia sub-sag.
The Chang 9 oil layer deposits within Ansai District, Ordos Basin, yield considerable reserves of crude oil, yet their source remains ambiguous. This research endeavor was designed to characterize the Chang 9 crude oil and the Chang 7 and Chang 9 source rocks (SRs) of the Yan-Chang Formation via organic geochemical analysis. The results indicate that the Chang 9 crude oil exhibits a Pr/Ph ratio of 0.84–2.29 and Ga/C30H less than 0.1, implying formed in a weak reduction to weak oxidation freshwater environment. The regular sterane C27-C28-C29 configuration assumes an inversed “L” type, reflecting mixed sources and dominant terrestrial plant input. Ratios such as C2920S/20S+20R (0.54–0.6) and C29ββ/ββ+αα (0.44–0.58) indicate a mature oil stage. The depositional environment of the C7 and C9 SRs is similar, with weak oxidation to reduction conditions, and consists mainly of Type I and II organics, with a relatively higher maturity of the C9 SRs. A difference in C19/C23TT and C30D/C30H was found between the C7 and C9 SRs. The results show that the C9 crude oils have a similar C19/C23TT with the C9 SRs and similar diahopanes distribution with Class II SRs (C7 and part of the C9 SRs). Thus, the C9 crude oils most likely originate from the C9 SR mixed with the C7 SRs.
Analysis of biomarkers in geological materials such as shales is very crucial because they can provide useful information on the depositional conditions and environments, organic matter input, thermal maturity as well as the geological age of shales in some cases. The paleoenvironment, and its impact on organic matter enrichment of the shales, plays a vital role in the exploration and development of the resource. Paleoenvironmental reconstruction can be conducted using elemental, isotopic, maceral, and biomarker proxies. However, the literature on the biomarkers for paleoenvironment reconstruction to reveal the organic matter enrichment of shales in many petroleum systems throughout the world is still insufficient. Hence, this paper seeks to critically review the application of biomarkers during paleoenvironmental reconstruction in shales. The uses of biomarkers as indicators of modern and ancient marine and brackish/saline lacustrine depositional environments are considered. This review shows that biomarkers could be used to establish the sedimentary depositional environments, redox conditions, and organic matter enrichments of shales that are critical to deep energy exploitation. Nevertheless, despite the fact that biomarkers are significant indicators of depositional conditions, secondary processes such as source facies, thermal maturity, migration, and reservoir alteration can greatly influence their uses as paleoenvironmental condition indicators in source rocks and oils. Hence, for a reliable paleoenvironmental evaluation, there is a need to combine isotopic, elemental and maceral proxies with biomarkers.
There are multiple hydrocarbon-generating sags on the peripheral plane of Baijiahai Uplift, and there are multiple layers of source rocks in the vertical direction. How to identify which sags and source rocks are the sources of oil and gas in Baijiahai Uplift is the focus of oil and gas exploration. In this paper, based on the geochemical characteristics of oil and gas, the genesis of multi-source oil and gas is identified and summarizes the law of oil and gas enrichment. The results show that the carbon isotope of crude oil in this area is -26.73‰ to -29.51‰, Pr/nC17 and Ph/nC18 are low, sterane and light hydrocarbon parameters indicating that crude oil is a mixture of Permian and Jurassic source rocks. Using the formula: (δ13Coil) = (δ13Coil)C46 X + (δ13Coil)C1 (1-X). It is concluded that the mixed source oil and gas mainly come from Jurassic source rocks, and there is a small amount of mixture of Permian source rocks. The dry coefficient of natural gas in Baijiahai Uplift is between 0.92 and 0.98, most of which are dry gas. The average carbon isotope of ethane is about -26‰, which is similar to natural gas in Kelameili gasfield, and both are derived from Carboniferous source rocks in Dongdaohaizi Sag. The distribution of faults has a certain control effect on the migration and accumulation of oil and gas. Oil and gas are mainly distributed in Dongdaohaizi fault zone and Baijiahai fault zone. The next exploration direction should be close to the faulted structural belt of the hydrocarbon-generating sag.
The Inner Moray Firth Basin (IMFB) forms the western arm of the North Sea trilete rift system that initiated mainly during the Late Jurassic-Early Cretaceous with the widespread development of major NE-SW-trending dip-slip growth faults. The IMFB is superimposed over the southern part of the older Devonian Orcadian Basin. The potential influence of older rift-related faults on the kinematics of later Mesozoic basin opening has received little attention, partly due to the poor resolution of offshore seismic reflection data at depth. New field observations augmented by drone photography and photogrammetry, coupled with U-Pb geochronology have been used to explore the kinematic history of faulting in onshore exposures along the southern IMFB margin. Dip-slip N-S to NNE-SSW-striking Devonian growth faults are recognised that have undergone later dextral reactivation during NNW-SSE extension. The U-Pb calcite dating of a sample from the syn-kinematic calcite veins associated with this later episode shows that the age of fault reactivation is 131.73 ± 3.07 Ma (Hauterivian). The recognition of dextral-oblique Early Cretaceous reactivation of faults related to the underlying and older Orcadian Basin highlights the importance of structural inheritance in controlling basin- to sub-basin-scale architectures and how this influences the kinematics of IMFB rifting.
Supplementary material: https://doi.org/10.6084/m9.figshare.c.5635432
In this essay we provide a short introduction to some basics of stable isotope geochemistry and an overview of few common applications in petroleum geochemistry. We identify the processes that are responsible for the carbon and hydrogen isotopic compositions of biological and geological organic matter and indicate the utility of stable isotopes in oil-source rock correlations. Stable isotope analyses are also exploited in the investigation of different alteration processes within oils and petroleum reservoirs. State of the art work is presented, and future research needs are identified.
Nuclear magnetic resonance (NMR) approach has unique advantages in the geochemical analysis of crude oil because it can provide information on chemical functional groups. Previous studies have focused on marine crude oils and investigated the interrelationship between the ¹H spectra and physical properties of the oil. However, the organic geochemical significance of the comprehensive NMR information and its effectiveness for studying non-marine crude oil are still not clear. Here we investigated crude oil from the Eocene Shahejie Formation in the lacustrine Dongpu Sag, Bohai Bay Basin, China, with NMR techniques. Our results show that the NMR spectra of these crude oils provide important information on organic matter functional groups, including aliphatic hydrocarbons, cycloalkanes, aromatic hydrocarbons, and other structural types. The NMR parameters of the studied crude oils reliably reflect the source rock sedimentary environment, and organic matter source and thermal maturity. Comparatively, ¹H and ¹³C NMR spectra are useful for evaluating organic matter source and thermal maturity, respectively. It was found that the organic matter that produced crude oil in the northern part of the basin is of better quality, and deposited in a higher-salinity and more reducing sedimentary environment, than in the south. The sedimentary environment in the central part of the basin reflects transitional characteristics with large variation. This complements our understanding of traditional organic (biomarker) geochemistry. Our data show that NMR parameters robustly reflect the chemistry of crude oil, particularly the composition of functional groups, and its geochemical application to studies of crude oil can be further expanded, from marine to non-marine, from ¹H spectroscopy to ¹³C spectroscopy, and from physical property to geochemical characterization.
Two arrangements of silica gel was evaluated for SARA separation by liquid column chromatography of two oils with different API gravity in order to determine the appropriate conditions for efficient elution of aromatic compounds. Gas chromatography analysis coupled to a mass spectrometer, in the TIC and SIM modes, were made to the saturated and aromatic fractions of the two oils in study. The arrangements activated silica at 400 °C and activated silica at 400 °C + 1% H2O were equally efficient in separating monoaromatic steroids in the aromatic fraction, and both in turn more efficient than with the silica array activated at 150°C (previously evaluated). The alkylnaphthalenes and biphenyls were separated into more efficiently by the activated silica array at 400 °C + 1% H2O compared to the silica array activated at 400 °C
In this study, gas condensate of Bandar Abbas areas, Kopeh Dagh and Qom (Central Iran) have been studied in organic geochemistry. In this regard, 7 gas condensate samples (3 samples from Bandar Abbas area, 3 samples for Kopeh Dagh region and 1 sample for Central Iran) were used to determine the geochemical characteristics of gas chromatography, gas chromatography-mass spectrometry and Isotope of carbon studies. Based on the parameters obtained from the Biomarkers study, sedimentary environment source rock of the hydrocarbons of the Bandar Abbas area with lithology carbonate and marl with kerogen type II and III, hydrocarbon producing organic material in the Kopeh Dagh basin was mainly deposited in shallow marine and coastal areas (kerogen type III) and maturity in comparison with other regions with higher maturity. The Biomarker’s parameters showed that the source rock was deposited in central Iran (Serajeh Qom field) in marine environment with shale and carbonate lithology and has the lowest degree of maturity compared to the other two studied regions. This study shows that source rock age is the of the studied hydrocarbons in the Kopeh Dagh and Bandar Abbas areas during the second geological era, the source rock of the of hydrocarbons in the Serajeh field of Qom, related to the third geological era. Also, the difference in maturation of gas condensate samples in these three areas indicates that the samples of the Kopeh Dagh region have the highest maturation and samples related to central Iran with the lowest maturation.
In a comprehensive geochemical study, the genetic relationship among 14 samples of gas condensates from the Persian Gulf was investigated for evaluating the respective source rocks in terms of age and sedimentary paleoenvironment. Chemometric analysis was used for categorization and determination of a certitude range to determine the genetic type of the condensate families in the studied basin. The samples were collected from Late Permian – Triassic reservoirs (Dalan and Kangan formations) located in 6 gasfields (gas condensate) hosting some of Iran's most important gas/gas condensate reserves. Obtained from gas chromatography‐mass spectrometry (GC‐MS), a total of 16 biomarker parameters (10 maturity‐related parameters and 6 sedimentary environment‐related parameters) were used to evaluate the samples in terms of thermal maturity (and hence their positions in the maturity chart), the sedimentary environment of the source rock, and lithology. Application of Hierarchical Clustering Analysis (HCA) and Principal Component Analysis (PCA) on the collected data led to the categorization of the samples into three main genetic groups, namely Groups I – III. Groups I and III were found to be located in the east and the west of the Persian Gulf, respectively, while Group II was developed in between the two other groups.
Mixtures of compositionally different petroleum occur in the Norwegian North Sea, one of the world’s major oil-producing regions. The objective of this contribution is to appraise the source, maturity, in-reservoir mixing and alteration processes in a set of condensate and oil samples covering the main producing areas in the South Viking Graben (SVG). Furthermore, this study focuses on unraveling complex mixtures of petroleum and quantifying mixing ratios of hydrocarbons generated from Jurassic source rocks. The present research is based on a multiparameter approach that comprises the molecular composition of light hydrocarbons and heterocyclic and polycyclic aromatic compounds as well as the δ13C of individual hydrocarbons in oils, condensates and Upper and Middle Jurassic source rock extracts from the SVG. According to the relative contribution of oils from Type-III kerogen-rich source rocks, seven populations (A-G) of mixed petroleum are identified by combining source-related ratios of heterocyclic and non-heterocyclic aromatic hydrocarbons and δ13C values of n-alkanes, pristane (Pr) and phytane (Ph). The heterocyclic and polycyclic aromatic hydrocarbons provided a useful means of discriminating mixed hydrocarbons from source rocks of distinct organic matter type, depositional environment and lithology in the SVG. The 13C-enrichment of (C10-C14) n-alkanes and Pr and Ph were good indicators of the scale of the terrigenous source contribution and allowed the quantitative determination of the proportions of Jurassic source contributions enriched in Type-II and Type-III kerogens in complex petroleum mixtures from the southern part of the SVG.
Abundant gas condensates have been proven in the Ordovician carbonate reservoirs in the Tazhong area, the centre of the Tarim Basin, where complicated geological evolution and multiple hydrocarbon accumulations have occurred. Property, geochemistry, and stable carbon isotopes of the Ordovician condensate are characterized to identify the oil and gas origins in the Tazhong area. Fluid inclusion data, combined with numerical modelling methods was used to determine petroleum accumulation processes. Our results suggest that oils are characterized by mixed sources, with 64% of contributions from the Middle-Upper Ordovician (O2+3) source rocks and 36% of contributions from the Lower-Middle Cambrian (Є1+2) source rocks. Gases are primarily generated from the thermal cracking of pre-existing oils in the underlying strata, with a small amount derived from kerogen cracking accompanied with oil generation. Three petroleum filling stages are determined, including the filling of the Є1+2-derived oils during the Late Hercynian period, filling of the O2+3-derived oils during the Yanshan period and oil-cracking-gas charge during the Himalayan period. The accumulation processes and relative contribution ratios of the two source rocks vary among the reservoirs and are mainly related to the transport system. Due to the lack of faults in the regions away from the No. 1 Fault Belt, the Є1+2-derived oils are difficult to fill into the Ordovician reservoirs through the gypsolyte, and thus the accumulated oils are mainly from the O2+3 source rocks. The percentage of the O2+3-derived oils is high in the southeast and northwest segments of the No. 1 Fault Belt, but relatively low in the middle segment and the vicinity of the No. 10 Structure Belt. Likewise, the late gas charge intensity is controlled by regionally varying conduit systems. Gas condensate formed in reservoirs with high gas/oil ratios. Otherwise, light oil retains with respect to low gas/oil ratios.
Chunguang oilfield is a new focus of the exploration in Junnggar Basin with the heavy crude oil distributing in Jurassic, Cretaceous and Tertiary strata. Based on the analysis of the geochemistry and fluid inclusion in the reservoirs, the source, accumulated period and process of the heavy crude oil reservoir has been investigated. The results indicate that the heavy crude oil can be divided into three types based on the degradation and sources. The heavy crude oil was mainly derived from the Permian source rocks, and latterly mixed by the heavy crude oil generated by the Jurassic source rocks. The accumulated period of the heavy crude oil has two stages. One was ranged from Cretaceous to Paleogene and the heavy crude oil was sourced from Permian source rocks of the Shawan depression and latterly mixed by the heavy crude oil generated by the Jurassic source rocks. The second period was from Neogene to present and the heavy crude oil was mainly derived from the Jurassic source rocks. Combined with the geological evolution, the heavy crude oil accumulated process has been recovered.
According to geochemical characteristics in combination with thermal evolution, there exist mainly three sets of source rocks in Sikeshu depression of Junggar basin, namely Jurassic (Badaowan Formation, Sangonghe Formation and Xishanyao Formation), Cretaceous and Paleogene. The Badaowan Formation source rocks which contain high abundance of organic matter of primarily III and II 2 type have fairly good hydrocarbon-generation potential. The Sangonghe Formation source rocks have poor condition of hydrocarbon generation in that they have low abundance of organic matter and inferior type of kerogen. The organic matter abundance in source rocks of Xishanyao Formation is relatively high, but its hydrocarbon-generation potential is not ideal owing to relatively small thickness and poorer type of organic matter. The Cretaceous source rocks in Sikeshu depression have maximum thickness of 300m, but the condition of hydrocarbon generation is not favarable due to the lower maturity. Paleogene source rocks with high abundance of organic matter and Type II organic matter have poor hydrocarbon-generation potential because of lower maturity. Through oil-source rocks correlation and quantitative identification of mixed oil, it is concluded that the crude oil in Chepaizi area was mainly derived from the Jurassic source rock in Sikeshu depression and mixed with the immature crude oil from the Cretaceous source, but the hydrocarbon generation of the Paleogene source rock is very little due to no distribution of the source kitchen. It is inferred that coal -formed oil dissolved the biomarker -rich Cretaceous bitumen of relatively low thermal maturity, and overprinting occurred during oil migration.
The East Orkney and Dutch Bank basins are located to the north of the Moray Firth rift arm in the UK North Sea. The East Orkney Basin measures approximately 60 by 30km and is bounded to the west, north and east by large normal faults. The West Fladen High consists of a series of horsts and grabens, and separates the East Orkney Basin from the Dutch Bank Basin, which is situated immediately to the north of the Witch Ground Graben and to the west of the Fladen Ground Spur. Although exploration well results for the limited penetrations of structural highs on the margins of the East Orkney Basin have been disappointing, geophysical and geochemical analyses all appear to indicate the presence of a mature source in the region. Integration of wireline data, core samples, and the interpretation of 2Dseismic data within the area allow mapping of the main structures in the basins and correlation to the adjacent well penetrations, thus not only enabling a tectonic and stratigraphic history, but also a framework for prospectivity to be established. A pillow-shaped sedimentary package at approximately 3 seconds two-way traveltime within the centre of the East Orkney Basin represents the downdip equivalent of stratigraphy on the West Fladen High, and is interpreted to be a Zechstein Group salt body, underlain by a thick sequence of Lower Permian (Rotliegend Group) and Devonian strata. Cored intervals from well 14/2-1 on the West Fladen High contain carbonates, evaporite dissolution breccias and anhydrites, implying a lateral change in sedimentary facies between structural highs and lows. Rifting took place through the Triassic and Jurassic, followed by relative tectonic quiescence in the Cretaceous, but as in adjacent areas, the Cenozoic witnessed structural inversion related to plume-generated uplift in the NorthAtlantic and the activation/reactivation of underlying faults coupled with deformation of the basin fill adjacent to these structures. Regional tilting from the Paleocene to early Eocene led to an influx of siliciclastics into the Dutch Bank Basin. The main play type is thought to consist of Rotliegend Group and Devonian sandstone reservoirs on the West Fladen High, sealed by Zechstein Group anhydrites or Cretaceous/Tertiary mudstones and charged by a deeply buried Devonian (Orcadian) lacustrine source. Although hydrocarbons are interpreted to have utilized normal faults as migration pathways, comparison with adjacent areas and observations of numerous oil seeps on the sea surface suggest that reservoir breach through reactivation of these faults to the seabed poses the main exploration risk. This fault reactivation has resulted from differential uplift combined with synchronous extensional faulting that affected adjacent areas, including the Inner Moray Firth.
The methods for calculating the relative source contribution proportion of the mixed oils at home and abroad were analyzed. A new method for determining the relative source proportion of mixed oils was proposed by using the grey correlation analysis on the n-alkanes distribution curves of the simulative mixed oils and the experimental mixed oils. When the degree of relevance between the simulative mixed oils and the experimental mixed oils is maximum, the proportion is considered to be the relative source contribution proportion of the mixed oils. The method was tested with the natural mixed oils in Daerqi Oilfield of Erlian Basin. The application result indicates that the useful results can be obtained using this method. The proportion of the simulative mixed oils can be altered optionally by using the new method, which is simple and favorable to be popularized.
In this study, chemometrics was used to unmix a set of oil samples that had been mixed in the laboratory using three end-member oils. It was shown that the concentrations of individual compounds in the mixed oil varied linearly with the fractional contribution of each end-member oil. However, biomarker ratios in the mixed oils varied non-linearly with the amount of each end-member oil. This study demonstrates that concentrations and ratios of biomarkers yield different results when de-convoluting mixed oils. Concentrations of biomarkers are therefore more suitable than the biomarker ratios for unmixing mixed oils. Alternating least squares of biomarker concentrations (ALS-C) provides an excellent way to calculate the number, proportions, and compound compositions of the end-members in mixed oil samples. The ALS-C results are accurate, regardless of whether end-member oils are included in the sample set. The biomarker ratios of end-member oils cannot be directly obtained by ALS, but can instead be calculated using related compound concentrations computed by ALS-C. This method should be applied and verified widely using actual geochemical data.
Study of the contribution from Enping Formation to oil accumulation in Zhuyi depression has an important application value to the enlargement of exploration area and the discovery of new reserves, and the related research is less. In this paper, the correlation of oil and source rock in Zhu I depression, Pearl River Mouth Basin is discussed first, and then the relative contribution of source rock in the Eocene to Oligocene Enping Formation (Ee) was investigated by combining end-member oil mixing experiment and biomarkers absolute concentrations. Oil-source correlation results show that the oils in Zhu I depression can be divided into three classes. The first class derived from Eocene deep-water lacustrine Wenchang Formation (Ew) mainly distributes in Huilu low uplift, Panyu 4 sag and Liuhua uplift, etc. The second class derived from the Ee distributes only in the northern of Huizhou sag. The third class (mixed oils) derived from both the Ew and the Ee distributes in the southern of Huizhou sag and Enping sag. End-member oil mixing experiment shows that the plate established by concentration and geochemical indexes, such as steranes and terpanes concentration, was suitable to indicate the relative contribution of two types of source rock in Zhu I depression. Results show that mudstones in the Ew was the main source rock in Zhu I depression, the relative contribution of the Ee is only appear in the Huizhou sag and Enping sag.
The plays reviewed in this paper are those developed where Permian and older organic-rich rocks have been preserved. These have sourced approximately 60 × 109 barrels of oil equivalent in the area under consideration, in oil, gas and oil shale developments, and range in age from the Cambrian to Permian. They were deposited in marine to terrestrial environments, and their development was controlled by the evolution of life forms, changes of relative sea-level and the plate tectonic configuration of the depocentres. Clastic and carbonate reservoir distribution was controlled by tectonic phases and relative sea-level variations. Trapping is by both structural and stratigraphic mechanisms. Preservation of source and reservoir potential is dependent on a lack of intense orogenic activity and should, therefore, be sought away from zones of intense tectonism that post-date potential source rocks.
Proven play types are extrapolated to under-explored areas where similar potential may exist, and the potential of methane extraction from coal beds is suggested.
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