C29 Steranes Research Articles

Oil origins, mixing and biodegradation in southwestern Junggar Basin, NW China

The southwestern Junggar Basin is an attractive region for oil exploration. A major discovery of high oil production rate from a recently drilled borehole stimulated a new round of extensive petroleum exploration in this region. The potential source beds are within the Permian, Triassic, Jurassic, Cretaceous and Paleogene strata, but no effective oil-prone source rock samples have been drilled so far due to deep burial, leading to that oil source correlation remains controversial in the region. A total of 38 crude oils and the free, adsorbed and inclusion oils obtained from 18 oil-containing reservoir rocks from the southwestern and southern Junggar Basin were analyzed by GC, GC–MS and GC–IRMS for the purpose to classify oil groups, determine oil origins, and identify effective source beds in sags. Crude oils in the southwestern Junggar Basin can be classified into two end groups and an intermediate group, namely PO, JO and PJO oils, which were originated from the Permian lacustrine source beds, Jurassic terrigenous source beds and both, respectively. Ratios of C19/C20 tricyclic terpanes and C24 tetracyclic/(C24 tetracyclic + C26 tricyclic) terpanes are the most sensitive parameters to distinguish these three groups of oils. These two ratios increase from PO, PJO to JO oils. JO oils can be further classified into two subgroups, i.e. J1O and J2O. J2O oils have substantially higher amounts of C27 and C28 steranes relative to C29 steranes, higher amount of gammacerane, lower amount of C29 diasteranes, and lower isomerization ratios of steranes, compared with J1O oils. J1O oils were exclusively originated from the Jurassic source beds while J2O oil were mainly originated from the Jurassic source beds mixed with minor oils generated from the Paleogene and Cretaceous lacustrine source beds. In the Chepaizi uplift, the major PO oils and extracted oils from 14 reservoir rocks were mainly originated from source beds within the Lower Wuerhe Formation of Middle Permian (P2w). However, the remaining minor oil samples and extracted oils from the other four reservoir rocks were clearly originated from source beds in the Fengcheng Formation of Lower Permian (P1f) on the basis of molecular parameters and δ13C values of individual n-alkanes, indicating the presence of effective oil-prone source beds within the Fengcheng Formation in the Shawan sag. In shallow reservoirs within the Neogene Shawan Formation (N1s), PO, PJO and J1O oils are severely biodegraded while J2O oils have nearly no biodegradation effect because the former entered the reservoirs much earlier than the latter.

Geochemically Distinct Oil Families in the Gudong Oilfield, Zhanhua Depression, Bohai Bay Basin, China.

Twenty crude oil samples were obtained from the Gudong Oilfield and their organic geochemical characteristics were analyzed. The oil samples were classified into three families by hierarchical cluster analysis and principal component analysis based on 13 source-related and depositional environment-related biomarker parameters. Oils in family I have low ratios of C19/C23 tricyclic terpanes and C24 tetracyclic terpane/C26 tricyclic terpanes, and relatively high ratios of steranes/hopanes and C30 4-methylsteranes/ααα20R C29 sterane, thus indicating that microalgae were the dominant organic matter input for the source rocks of family I. The gammacerane/C30 hopane ratios are higher than that of family II and family III, whereas the C35/C34 homohopane ratios are lower, thus indicating a suboxic, brackish water environment for the source rocks. The inferred source rock is the first member of the Shahejie Formation in the Huanghekou Sag. Family II is characterized by high ratios of C19/C23 tricyclic terpanes and C24 tetracyclic terpane/C26 tricyclic terpanes but relatively low ratios of steranes/hopanes and C27/C29 αααR steranes. These findings suggest that the original organic matter of the source rocks had a greater contribution from terrigenous higher plants than from microalgal. The relatively low ratios of gammacerane/C30 hopane and C35/C34 homohopane suggest that the source rocks were deposited in an oxic environment with a low salinity, thus corresponding to the Dongying Formation in the Huanghekou Sag. Family III oils have high C27/C29 ααααR steranes ratios and low C30 4-methylsteranes/ααα20R C29 ratios, which indicate the contribution of microalgae (especially zooplankton algae) to the source rocks. The relatively high abundance of C35 homohopane and low gammacerane/C30 hopane ratios suggest a weakly reducing condition with low salinity, which is in accordance with the third member of the Shahejie Formation in the Gunan Sag. The C31S/(S + R) homohopane ratios imply that oil samples in this study are in the mature stage, although the ratios of C2920S/(20S + 20R) and C29ββ/(αα + ββ) steranes suggest that the maturity of family II is higher than that of family I and family III.

HIGHER LANDPLANT –DERIVED BIOMARKERS IN LIGHT OILS AND CONDENSATES FROM THE COAL‐BEARING EOCENE PINGHU FORMATION, XIHU SAG, EAST CHINA SEA SHELF BASIN

The Cenozoic Xihu Sag in the East China Sea Shelf Basin contains large reserves of coals together with liquid petroleum derived from coal‐associated sediments. However, the origin of the petroleum is not well understood. In this study, biomarker assemblages in a suite of recently discovered light oils and condensates from the Paleogene succession in the western margin of in the Xihu Sag were investigated using gas chromatography – mass spectrometry. The objectives were to investigate the samples' thermal maturity and the depositional environment of the precursor source rocks which generated the oils. The light oils are believed to have been derived from coaly source rocks in the Eocene Pinghu Formation.Assessment of thermal maturity based on CPI, pristane/n‐C17 ratio and isomerisation ratios of C29 steranes and C31 homohopanes suggest that the hydrocarbons have a relatively low maturity in the early to mid oil generation window. The distribution of isoprenoids relative to n‐alkanes, the high pristane/phytane ratios (5.1–10.7), the almost complete absence of gammacerane and C33+ homohopanes, and the low dibenzothiophene/phenanthrene ratios indicate that the source rocks of the hydrocarbons were deposited in a relatively oxic and sulphate‐poor fluvio‐deltaic environment which was favourable for coal measure development.Abnormally abundant gymnosperm‐derived diterpanes including labdane, 19‐norisopimarane, fichtelite, rimuane, pimarane, isopimarane, 17‐nortetracyclic diterpene, phyllocladanes and abietane were detected in the samples analysed. 16a(H)‐Phyllocladane was identified unambiguously and kauranes were confirmed to be absent. In addition, three 19‐norisopimarane isomers, 13β(H)‐atisane, and 20‐normethylatisane were tentatively identified in the studied samples. The distributions of n‐alkanes, isoprenoids and regular steranes, the presence of 4β(H)‐eudesmane and oleanane, high Pr/Ph ratios and the abundant diterpanes together suggest that the hydrocarbons were derived from a coaly source rock. Gymnosperms of the conifer families Cupressaceae (especially the former Taxodiaceae) and Pinaceae are interpreted to be the major source of the diterpanes and to have made a significant contribution to the coaly source rock. However, the low abundance of oleanane relative to diterpanes may underestimate the contribution from angiosperms relative to gymnosperms. This could be due to differential preservation and alteration of the di‐ and triterpenoid precursors during diagenesis and the occurrence of non‐specific precursors in higher land plants.

Understanding the geobiology of the terminal Ediacaran Khatyspyt Lagerstätte (Arctic Siberia, Russia).

The Khatyspyt Lagerstätte (~544Ma, Russia) provides a valuable window into late Ediacaran Avalon-type ecosystems with rangeomorphs, arboreomorphs, and mega-algae. Here, we tackle the geobiology of this Lagerstätte by the combined analysis of paleontological features, sedimentary facies, and lipid biomarkers. The Khatyspyt Formation was deposited in carbonate ramp environments. Organic matter (0.12-2.22 wt.% TOC) displays characteristic Ediacaran biomarker features (e.g., eukaryotic steranes dominated by the C29 stigmastane). Some samples contain a putative 2-methylgammacerane that was likely sourced by ciliates and/or bacteria. 24-isopropylcholestane and 26-methylstigmastane are consistently scarce (≤0.4% and ≤0.2% of ∑C27-30 regular steranes, respectively). Thus, Avalon-type organisms occupied different niches than organisms capable of directly synthesizing C30 sterane precursors among their major lipids. Relative abundances of eukaryotic steranes and bacterial hopanes (sterane/hopane ratios=0.07-0.30) demonstrate oligotrophic and bacterially dominated marine environments, similar to findings from other successions with Ediacara-type fossils. Ediacara-type fossils occur in facies characterized by microbial mats and biomarkers indicative for a stratified marine environment with normal-moderate salinities (moderate-high gammacerane index of 2.3-5.7; low C35 homohopane index of 0.1-0.2). Mega-algae, in contrast, are abundant in facies that almost entirely consist of allochthonous event layers. Biomarkers in these samples indicate a non-stratified marine environment and normal salinities (low gammacerane index of 0.6-0.8; low C35 homohopane index of 0.1). Vertical burrowers occur in similar facies but with biomarker evidence for stratification in the water column or around the seafloor (high gammacerane index of 5.6). Thus, the distribution of macro-organisms and burrowers was controlled by various, dynamically changing environmental factors. It appears likely that dynamic settings like the Khatyspyt Lagerstätte provided metabolic challenges for sustenance and growth which primed eukaryotic organisms to cope with changing environmental habitats, allowing for a later diversification and expansion of complex macroscopic life in the marine realm.

Oil-charging history constrained by biomarkers of petroleum inclusions in the Dongying Depression, China

Free oils and inclusion oils were extracted from the third member of the Eocene Shahejie Formation (Es3) reservoir sandstones of the wells Chun 51 and Liang 28 in the Dongying Depression, China, and then analyzed by gas chromatography–mass spectrometry (GC–MS). Results show that biomarker distribution characteristics of the free oils and their associated inclusion oils are similar in each Es3 reservoir sandstones of the two wells, but the distributions of Pr/Ph ratio, gammacerane, hopane series and C27–C29 steranes in well Chun 51 oils are strikingly different from those of well Liang 28 oils. However, the C29 sterane ββ/(ββ + αα), Ts/(Ts + Tm) and C31 hopane 22S/(22S + 22R) ratios of inclusion oils are higher than those of related free oils in all the samples, this may indicate that maturity indicators decreased after reaching the maximum and relatively high mature oils were trapped in petroleum inclusions. Comparison with biomarkers of source-rock extracts shows that oils in the Es3 reservoir of well Chun 51 were generated from the upper Es4 source rocks, whereas oils in the Es3 reservoir of well Liang 28 were derived from the lower Es3 source rocks. Moreover, the microthermometric data and burial history indicate one oil-charging episode in the Es3 reservoirs of the two wells, during the late Neogene. It's concluded that different charging histories of these two reservoirs were attributed mainly to the sealing effect of the fault.

Geochemical comparison of three oil families from the Gippsland Basin, SE Australia

The biomarker and aromatic compounds, including polycyclic aromatic hydrocarbons (PAHs), in three oil families composed of 29 crude oils from the Gippsland Basin, SE Australia were studied using gas chromatography-mass spectrometry. Environment-related parameters, such as the Pr/Ph ratio and the gammacerane index, indicate that all the oils originated from a lacustrine/fluvial-deltaic environment with fresh water. Thermal maturity-related parameters, including aliphatic and aromatic maturity indicators (e.g. C29 sterane isomerisation parameters, alkylnaphthalene indices, and methylphenanthrene index), show that all the oils from the GA1 oil family have a similar thermal maturity in the peak-late oil window. However, oils from the GA2 and GB families vary in thermal maturity and are interpreted to be mixtures of less mature and more mature crude oils. Source-related biomarkers (e.g. isopimarane, labdane and phyllocladane) and PAHs (e.g. retene and oleanane-/ursane-/lupane-derived aromatic triterpenoids) suggest that the GA1 oils were mainly derived from source rocks rich in conifer-derived organic matter. The organic matter source of the GA2 and GB oil families included both angiosperms and gymnosperms, with a relatively stronger angiosperm contribution to the organic matter in the source rock(s) of the GB oils, based on the PAH analysis. Moreover, higher plant-derived triterpenoids can be effectively used to correlate oil families across the study area, supplementing the n-alkane carbon isotope and biomarker data of the three oil families reported previously.

Geochemical characteristics of crude oil and oil-source correlation in the western Qaidam Basin, China

The Cenozoic in the western Qaidam Basin is rich in oil and gas resources and has good prospects for exploration. The maturity, sedimentary environment, and biological source of the crude oil in the western Qaidam Basin are discussed based on the composition characteristics of biomarkers in crude oil and source rocks. The above is performed to classify the genetic types of crude oil and determine the oil source relationship. It is found that the crude oil shows the characteristics of low mature–mature and is formed in the reducing environment with high salinity. The organic matter is from the mixed source with dominant aquatic plants input. According to the sedimentary environment, parent material types, and maturity characteristics, the crude oil in the western Qaidam Basin can be classified into four types. (1) Type I is from the Shizigou-Yuejin areas, which have a high content of gammacerane, a low value of Pr/Ph, C27 sterane predominance, and “tail-upwarping” phenomenon. (2) Type II is from the Qiekelike-Zhahaquan and Nanyishan-Youquanzi areas, which have C27 sterane predominance and no “tail-upwarping” phenomenon. Its content of gammacerane is lower than type I. (3) Type III is from the Dafengshan and Huangguamao areas, which have C29 sterane predominance and no “tail-upwarping” phenomenon. (4) Type IV is from the Kaitemilike area, which has a C27 sterane predominance, no “tail-upwarping” phenomenon, and lower content of gammacerane than that of others. The result of the oil-source correlation shows that the crude oil is dominantly derived from source rocks of the lower Ganchaigou Formation (E3) and the upper Ganchaigou Formation (N1).

Geochemical Appraisal of the Depositional Environment and Source Organic Matter of Crude Oils from Some Oil Fields in Bayelsa State, Nigeria

The organic geochemical characterization of crude oil samples from the oil fields of the Niger delta was carried out using gas chromatography–-mass spectrometry (GC–-MS) to genetically characterize the oil samples in terms of their biomarker composition. Geochemical characteristics such as depositional environments, kerogen type, and source of organic matter were analyzed using aliphatic biomarkers as a supporting tool. Five samples were randomly collected from Tebidaba, Clough Creek and Azuzuama fields in Bayelsa State, Nigeria. The saturated hydrocarbons were analyzed using GC–MS. The n-alkanes, isoprenoids, biomarkers hopanes, and steranes fingerprints were extracted from chromatogram for m/z 57, 191, 217 values respectively. The results revealed that the five studied samples were characterized by C29 sterane predominance and the presence of oleanane, depicting organic matter with vascular land plant material inputs and a deltaic contribution. Ternary plots showed that the oils were deposited in an estuarine environment. The pristane (Pr) /nC17 versus phytane (Ph)/nC18 showed that TEB 08 and WELL 2 are in the anoxic environment inferring kerogen II and a mixture of types I and II respectively. TEB 12, CCST, and AZU ST has kerogen type III deposited in an oxic environment.

Biomarker evidence of algal-microbial community changes linked to redox and salinity variation, Upper Devonian Chattanooga Shale (Tennessee, USA)

AbstractLate Devonian marine systems were characterized by major environmental perturbations and associated biotic community changes linked to climate change and widespread oceanic anoxia. Here, we provide high-resolution lipid biomarker chemostratigraphic records from the Upper Devonian Chattanooga Shale (Tennessee, USA) to investigate algal-microbial community changes in the southern Illinois Basin that were related to contemporaneous shifts in marine redox (as proxied by trace metals, Fe-species, and Corg/P) and salinity conditions (as proxied by B/Ga, Sr/Ba, and S/total organic carbon). The Frasnian was characterized by dominantly bacterial lipids (high hopane/sterane), near-marine salinity, and a shift from oxic to increasingly reducing conditions in response to increasing organic carbon sinking fluxes. Aryl isoprenoids and aryl isoprenoid ratios reveal that the O2-H2S chemocline was unstable and intermittently shallow (i.e., within the photic zone). The Frasnian-Famennian boundary was marked by a shift in microalgal community composition toward green algal (e.g., prasinophyte) dominance (lower C27 and higher C28 and C29 steranes), a sharp reduction in watermass salinity, and a stable O2-H2S chemocline below the photic zone, conditions that persisted until nearly the end of the Famennian. We infer that changing watermass conditions, especially a sharp reduction in salinity to possibly low-brackish conditions (<10 psu), were the primary cause of concurrent changes in the microalgal community, reflecting tolerance of low-salinity conditions by green algae. Transient spikes in moretane/hopane (M/H) ratios may record enhanced terrestrial weathering at the Frasnian-Famennian and Devonian–Carboniferous boundaries, triggered by coeval glacio-eustatic falls and increased inputs of soil organic matter. High M/H and pristane/phytane, in combination with low chemical index of alteration and K/Al, record a decrease in chemical weathering intensity during the Famennian that may have been due to contemporaneous climatic cooling, and a concurrent reduction in silt content may reflect stabilization of land surfaces by vascular plants and resulting reduced sediment yields. This study demonstrates the effectiveness of combining organic and inorganic geochemical proxies (including novel paleosalinity indices) for determination of environmental controls on the composition and productivity of plankton communities in paleomarine systems.

Sterane biomarker analysis of Sargelu Formation, Miran West Field, MW-2 well, Kurdistan Region, NE Iraq: Implications for origin of organic matter, palaeoenvironment and maturity

Sargelu Formation (Middle Jurassic) is well known to be one of the most important and wide distributed source rocks in the Middle East. In this study, nineteen cuttings samples from Sargelu Formation were studied from one subsurface section within Miran West Field (well MW-2) in Zagros Folded Belt, Kurdistan region of Iraq. The Formation was penetrated from the interval 2375m to 2475m, which is mainly composed of argillaceous limestone and shale. The Total Organic Carbon (TOC wt %) for all samples were calculated from the sonic and resistivity logs using Passey et al., method for TOC estimation from wireline logs. The range of TOC percentage in the selected interval is between 0.654 and 6.53%. In addition, all samples have been analyzed by Gas Chromatography/ Mass Spectrometry (GC/MS) in order to identify and study the biomarkers distribution in the selected rocks. The short chain n-alkanes between C15-C18, with isoprenoids pristane (Pr) and phytane (Ph) are dominants in the Sargelu formation. The average of Pr/Ph ratio in the samples was 0.95. Furthermore, most of the studied samples show unimodal envelope chromatograms, maximum peak carbon n-C15- n-C20, and low CPI values (0.89-1.17). The calculated odd over even predominance (OEP) for the studied samples show near value 1.0 (av. 0.94). The TOC values reflecting well preservation and high productivity of organic matter in reducing/anoxic depositional environment. Moreover, ratios of Pr/Ph indicating to anoxic and commonly marine carbonate environments; and also unimodal envelope of n-C15- n-C20 shows a predominance of marine input, and the organisms derived from phytoplankton, zooplankton and benthic bacteria with minor photosynthetic and terrestrial plants. The studied samples have C29 20S/(20S+20R) and ββ/ (ββ+αα) isomerization values ranging from 0.39 - 0.58 and 0.48 - 0.65 respectively, indicating high mature source rocks of Sargelu Formation in this well. In most studied samples, the C27 and C29 steranes predominate over the C28 steranes, reflecting a high contribution of aquatic planktonic-bacterial organic matter with a minor terrigenous organic matter input.

Geochemical characteristics of Middle-Upper Ordovician source rocks in the Kalpin outcrop profiles and marine oil-source correlation, Tarim Basin, NW China

The Middle-Upper Ordovician source rocks developed in six outcrop profiles in the Kalpin area, Tarim Basin, NW China were analyzed using an organic geochemical screening method. Most TOC values of source rocks of Salgan Formation of Middle-Upper Ordovician developed in the Dawangou, Kamatikan, and Tonggusibulong outcrop profiles are greater than 1.0%, whereas the TOC value of the source rocks of Yingan Formation of Upper Ordovician only developed in the Dawangou outcrop ranged from 0.14% to 1.29%, with an average value lower than that of the Salgan Formation source rocks. Combined with the analysis results of source rocks of Yuertusi Formation of Lower Cambrian developed in the Xiaoerbulake, Sugaite and West Yuti outcrop profiles, the source rocks of Yuertusi, Salgan and Yingan Formations showed similar molecular geochemical characteristics, with low Pr/Ph value, C23 greater than C21 tricyclic terpane, high gamacerane and C28 sterane content. The similarity in molecular compounds of Cambrian to Ordovician source rocks in the Kalpin area may be a result of the high maturity. In the relative distribution of C27–C29 regular steranes, the marine oils with C28 sterane lower than 25% showed great difference with that of the source rocks of Lower Cambrian Yuertusi Formation. In the distribution of carbon isotopic curves, the source rocks of Lower Cambrian Yuertusi Formation have lighter carbon isotopes, compared with that of the Middle-Upper source rocks, especially in kerogen carbon isotopes, Lower Cambrian Yuertusi Formation lighter 5‰ than that of Middle-Upper Ordovician source rocks. Overall, the carbon isotopes fractionation of saturate, bitumen, aromatic fraction, resin, asphaltene, and kerogen is small in source rocks from Middle-Upper Ordovician Salgan and Yingan Formations in the Kalpin area. It is suggested that the carbon isotope of kerogen of source rocks can be used as a parameter for oil-source correlation excluding the TSR of the oil reservoirs.

Geochemical Research of the Organic Matter of Coal from the Sergeevskoe Brown Coal Deposit

The composition of brown coal in the Buzulinsk suite of the Sergeevskoe brown coal deposit (Upper Amur region, Russia) was studied using organic geochemistry methods. The distribution of various types of bitumoids over the depth of the section was revealed. The following compounds were identified in hydrocarbon biomarkers by chromatography and chromatography–mass spectrometry: C14–C40n-alkanes, iC13–C25 acyclic isoprenoids, C27–C30 sterane and C19–C35 terpane structures (hopanes and homohopanes, moretanes, and tri- and tetracyclanes), and aromatic hydrocarbons (phenanthrenes, dibenzothiophenes, and mono- and triaromatic steroids). It was shown that the main source of the terrigenous organic matter of Sergeevskoe coal is the highest ground vegetation. The contribution of aquagenic biomaterial was due to facies changes in the regimes of coal accumulation.

Stable carbon isotope evidence for the origin of C28 steranes in lacustrine source rocks from the Qikou Sag, Bohai Bay Basin, Eastern China

C27–C29 steranes are common constituents of crude oils and hydrocarbon source rocks and are usually dominated by either C27 or C29 compounds. In the current study, however, steranes dominated by C28 components were detected in eight lacustrine source rock samples in the first member of the Shahejie Formation in the Qikou Sag, Bohai Bay Basin of Eastern China. Ratios of C28/(C27 + C28 + C29) ααα 20R steranes in four samples can exceeded 50%. Furthermore, C27 triaromatic steroids, presumably originating from C28 steranes, were also observed at high levels, relative to C26 and C28 homologues. Stable carbon isotope compositions of a C28 ααα 20R sterane and C27 20R triaromatic steroid were found to be similar, with δ13C at −37‰ and −36‰ respectively, much lower than values for pristane (by ∼7‰) and total organic carbon (by ∼10‰). The abnormally low δ13C values of the steroids suggest that C28 ααα 20R sterane was biosynthesized by algae blooming in the water column during phases of overturn and mixing, such as in autumn, during which recycled CO2 and nutrients welling up from hypolimnion to the epilimnion are assimilated, contributing to a high algal productivity and low δ13C in algal organic matter.

Compound specific sulfur isotopes of saline lacustrine oils from the Dongpu Depression, Bohai Bay Basin, NE China

Lacustrine oils from type I-II kerogen from the Dongpu Depression of Bohai Bay Basin have been characterised by compound specific sulfur isotope and hydrocarbon biomarker analyses. The sample suite included sixteen saline lacustrine oils from the northern part of the Dongpu Depression, most of which (i.e., all but two interbedded samples) could be separated into four tectonically aligned oil families (OF1-4) on the basis of differences in their hydrocarbon composition (e.g. high MW n-alkanes, isoprenoids, polycyclic terpenoids). The other two oils studied were freshwater lacustrine oils from the south of the Dongpu Depression, the hydrocarbon composition of which indicated a fifth oil family (OF5). The δ34S values of organic sulfur compounds (δ34SOSCs) in the oils showed several general differences consistent with the five hydrocarbon biomarker defined oil families, including the relative magnitude of their δ34S values: Ave δ34SOSCs values: OF1 = 19‰ (relatively depleted δ34S); OF2 = 28‰ (enriched δ34S); OF3 = 24‰ (intermediate δ34S); OF4 = 25‰ (intermediate δ34S); and OF5 = 18‰ (depleted δ34S); and the respective δ34SOSCs profiles of the oils, e.g., the intermediate δ34S values of the LT oils (OF3) showed little variance with alkylation (<4‰), whereas the intermediate δ34S values of the higher maturity Wenliu oils (OF4) showed 34S enriched alkylated DBTs compared to base DBT (Δδ34SalkylDBT-DBT = +7‰). This demonstrates the potential of δ34SOSCs data assisting the genetic correlation of S-rich saline lacustrine oils. However, separate correlations between some of the δ34SOSCs data and hydrocarbon indicators of paleo-environmental (C35-/C34-hopanes), thermal maturity (C29 sterane and MDBT parameters) and TSR (Δδ34SBTs–DBTs = 6–12‰) impacts suggest each of these factors also influenced the δ34S character of the Dongpu oils. Therefore, δ34SOSCs data should be used cautiously in correlation of oils from complex petroleum systems and where possible integrated with other complimentary analytical information.

Formation Environment and Development Models for the Lower Cambrian Source Rocks of the Southern North China Plate, China.

In this article, the lower Cambrian marine shale of the southern part of the Ordos basin is taken as an example to investigate the formation environment and development models of source rocks with high organic abundance in the ancient strata of the southern North China plate. The lower Cambrian shale source rocks had a thickness of 10–80 m, with high total organic carbon contents (an average of 2.68% and maximum of 9.39%) and favorable organic matter types—mainly sapropelinite macerals—and yet low S1, S2, and hydrogen index, which indicate that the source rocks have relatively high thermal maturity. Therefore, it is demonstrated that marine shale of the lower Cambrian proves to be excellent gas source rocks at the southern part of the Ordos basin and are presently distributed mainly in the south part of the North China plate. During the early Cambrian period, paleoproductivity was relatively high, as indicated by the rich C27 sterane contents, high sterane/hopane ratios, and high tricyclic terpane/hopane ratios in biomarkers and high P and Ba values in trace elements. The tectonic setting promoted the formation of highly abundant source rocks with favorable preservation conditions, as suggested by the relatively high V/Cr ratios and low Zr/Rb and Pr/Ph ratios. Thus, the paleoproductivity and preservation conditions were the main factors controlling the occurrence of highly abundant source rocks. The formation of highly abundant source rocks was under the joint effects of the tectonic setting and the undercompensation environments of the passive continental marginal slope of the Paleo-Qinling Ocean and deepwater bays. The paleo-geomorphologic troughs and/or fault depressions (because of tectonic movement) and deepwater bay environments together influenced the development scale of highly abundant source rocks, whereas the deepwater shelf environment of the continental marginal slope ensured the high quality of the source rocks.

Chemometric identification of crude oil families and deconvolution of mixtures in the surrounding Niuzhuang sag, Bohai Bay Basin, China

A total of 46 crude oil samples recovered from the surrounding Niuzhuang sag were investigated to gain insight into the petroleum systems in the Dongying depression. Chemometrics identified four genetically distinct oil families. Family 1 fails to match any of the source rocks that have been discovered thus far. The candidate source rock must contain algal organic matter that could produce more negative carbon isotopic composition, large quantities of wax, C29 steranes, and tricyclic terpenoids compared to the Eocene Shahejie (Es) Formation intervals Es3 and Es4 and deposited in a reducing, stratified saline water environment. Family 2 is featured by high ratios of sterane/hopane, gammacerane/hopane, and C35/C34 homohopane and low pristane/phytane ratios. The source rock is the upper Es4 interval. Family 3 is characterized by distinctive or even opposite features to family 2. The source rock is the lower Es3 interval. Family 4 is a mixed oil derived from the lower Es3 and upper Es4 source rocks at different thermal maturation. Three end-member oil samples, EM1, EM2, and EM3, were identified by alternating least-squares. As a minor contributor, EM1 has an average value of 10%. As the main contributors, EM2 and EM3 average 53% and 37%, respectively. Oil samples from EM1 and EM2 are derived from the upper Es4 source rock, but EM1 was generated at a lower thermal maturity than EM2. Oil from EM3 was derived from the lower Es3 source rock at peak hydrocarbon generation.

DIAMONDOIDS AND BASIN MODELLING REVEAL ONE OF THE WORLD'S DEEPEST PETROLEUM SYSTEMS, SOUTH CASPIAN BASIN, AZERBAIJAN

The South Caspian Basin has been one of the world's most prolific petroleum provinces since the 19th Century. However, despite the large number of discovered petroleum accumulations, the source rock sequence has not been penetrated by the drill in the offshore basin and is therefore poorly defined. In this paper, geochemistry together with broad estimates of in‐place volumes of petroleum fluids, onshore outcrop data and basin modelling have been used to place constraints on the source rock description.Diamondoids, the most thermally stable group of hydrocarbons, have been measured in a suite of liquid petroleum samples from Pliocene fluvio‐deltaic sandstone reservoirs at the Shah Deniz gas‐condensate field and the Azeri‐Chirag‐Gunashli oil field, offshore Azerbaijan. Samples from both fields exhibit elevated concentrations of diamondoids and C29 steranes, indicating a mixture of thermally cracked and non‐cracked petroleum. We use diamondoid concentrations to estimate that 4.8 B brl of oil may have been cracked to 12 Tcf of gas below the Shah Deniz reservoirs. Source rock properties from the outcropping Oligocene – Miocene Maikop and Diatom Formations have been used to model source rock maturation. The results indicate that pre‐cracking volumes of petroleum could be explained reasonably by the presence of source rock intervals in the offshore that are of similar richness but increased thickness compared to measured onshore outcrops.Relatively high diamondoid concentrations in Shah Deniz condensate (up to 160 ppm 3‐ + 4‐methyldiamantanes) are in agreement with gas isotope compositions (δ13C1 – δ13C3) with respect to thermal maturity. Both parameters indicate the presence of source rock that is at a high level of thermal maturity at a vitrinite reflectance equivalent (VRE) of ca. 1.5–2.0% Ro. Given the low geothermal gradients in the South Caspian Basin (16 – 17°C/km at Shah Deniz) and the relatively high temperatures required for maturation due to rapid, relatively recent burial and heating, the source rock must be buried to depths in excess of 13 km in the Shah Deniz drainage area. In the absence of any evidence of a working Mesozoic petroleum system in the South Caspian Basin, this depth of burial highlights the significant thickness of Paleogene sediments in the offshore basin. Of prolific petroleum‐producing basins, only in the deep‐water Gulf of Mexico are actively‐generating source rocks buried to similar depths.

ORGANIC‐RICH SHALES IN THE UPPER TRIASSIC ZANGXIAHE FORMATION, NORTHERN QIANGTANG DEPRESSION, NORTHERN TIBET: DEPOSITIONAL ENVIRONMENT AND HYDROCARBON GENERATION POTENTIAL

This study reports on the organic geochemical characteristics of high‐TOC shales in the Upper Triassic Zangxiahe Formation from a study area in the north of the Northern Qiangtang Depression, northern Tibet. A total of fifty outcrop samples from the Duoseliangzi, Zangxiahe South and Zangxiahe East locations were studied to evaluate the organic matter content of the shales and their thermal maturity and depositional environment, and to assess their hydrocarbon generation potential.Zangxiahe Formation shales from the Duoseliangzi profile have moderate to good source rock potential with TOC contents of up to 3.4 wt.% (average 1.2 wt.%) and potential yield (S1+S2) of up to 1.11 mg HC/g rock. Vitrinite reflectance (Ro) and Tmax values show that the organic matter is highly mature, corresponding to the condensate/wet gas generation stage. The shales contain mostly Types II and I kerogen mixed with minor Type III, and have relatively high S/C ratios, high contents of amorphous sapropelinite, low Pr/Ph ratios, high values of the C35 homohopane index (up to 3.58%), abundant gammacerane content, and a predominance of C27 steranes. These parameters indicate a saline, shallow‐marine depositional setting with an anoxic, stratified water column. The source of organic matter was mainly aquatic OM (algal/bacterial) with subordinate terrigenous OM.Zangxiahe Formation shale samples from the Zangxiahe East and Zangxiahe South locations have relatively low TOC contents (0.2 to 0.8 wt.%) with Type II kerogen, suggesting poor to medium hydrocarbon generation potential. Ro and Tmax values indicate that organic matter from these locations is overmature.The discovery of organic‐rich Upper Triassic shales with source rock potential in the north of the Northern Qiangtang Depression will be of significance for oil and gas exploration elsewhere in the Qiangtang Basin. Future exploration should focus on locations such as Bandaohu to the SE of the study area where the organic‐rich shales are well developed, and where structural traps have been recorded together with potential reservoir rocks and thick mudstones which could act as seals.

Change in Maturity of Coals of the Same Genotype Occurring at Different Depths, as Determined by Saturated Hydrocarbon Biomarkers

Saturated hydrocarbon biomarkers have been determined in chloroform extracts of coals occurring at different depths (190, 205, and 322 m) of the Vinogradovskii open-pit mine (Belovo, Kuzbass), using gas–liquid chromatography and gas chromatography–mass spectrometry. The relative distribution of hydrocarbon (HC) biomarkers—n-alkanes, isoprenanes, steranes, and terpanes—shows that the coals are genetically uniform. In terms of hydrocarbon composition, they are weakly mature, although they relate to long-flame D-type coals by the degree of metamorphism. With an increase in the coal occurrence depth, the HC biomarker ratios that reflect the degree of maturity of organic matter slightly increase. As coal occurrence depth increases, the carbon preference index of n-alkanes decreases, the maturity coefficients $$K_{{{\text{mat}}}}^{1}$$ and $$K_{{{\text{mat}}}}^{2}$$ by C29 steranes and the dia/reg ratios of C27 steranes increase; the terpane Ts/Tm ratio and S/R epimer ratio of C31 and C32 homohopanes increase, and the moretane/hopane ratio decrease.

Organic geochemical traits and paleo-depositional conditions of source rocks from the Carboniferous to Permian sediments of the northern Mahu Sag, Junggar Basin, China

The organic geochemical traits of Carboniferous to Permian hydrocarbon source rocks (SRs) from the Mahu Sag, Junggar basin, have been investigated in terms of thermal maturity (TM), hydrocarbon potential (HP), organic matter (OM) source input and paleoenvironment. A total of forty-seven (47) core samples from five (5) wells have been surveyed through standard organic geochemical approaches, including the total organic carbon (TOC) and the rock pyrolysis (RP) measurement. Fifteen (15) of the samples were bitumen extraction and fractionation, and their aliphatic hydrocarbons and aromatic hydrocarbons were carried out for the gas chromatography–mass spectrometry (GC-MS) analysis. The results indicate that the studied samples came from the C and the P1f are the moderate or good SRs, but samples from the P2w and P1j are not good enough, most of them are poor or moderate SRs. The TM was indicated by the temperature of maximum pyrolysis yield (Tmax), the Carbon Preference Index (CPI) and Odd to Even Preference (OEP) values, the C30 M/H versus Tm/Ts, the C29 ββ/(ββ+αα) versus C29 20S/(20S + 20R), and the alkyl naphthalene ratios. Result shows that almost all the samples from the P1f are in the mature stage at present; some samples of P1j and C are in the premature or mature stage, others are completely immature; all P2w samples are in the immature stage at present. The OM source was indicated by the n-Alkane distribution, the relative quantity of C27–C28–C29 steranes, the (C19+C20)/C23 tricyclic terpane (TT), and the Terrigenous/aquatic ratio (TAR). The deposition environment was inferred by the pristane/phytane (Pr/Ph), the Gammacerane index, and the relative quantity of fluorene compounds (Fls), dibenzothiophen compounds (DBTs) and dibenzofuran compounds (DBFs). Result shows that the mainly OM source of the P2w, P1f, P1j, and C were the saline lacustrine algal, but some samples of the P1j were mixed with the higher plants; most samples deposited in the strong reduction environment except the samples came from the P2w and some samples came from the P1j. Considering the OMs’ content, type, origination, deposited paleo-environment and TM, the SRs of the P1f are considered the best sources rocks with the best conditions of the oil and gas generation.