Regular Steranes Research Articles

Petrographic and geochemical signatures of the Upper Permian Gondwana coals: Newcastle Coal Measures, Northern Sydney Basin, Australia

This research presents an integrated approach to organic petrographical and geochemical characteristics of the Upper Permian Newcastle Coal Measures outcropping in the northern Sydney Basin, southeast Australia. Twenty-seven coal, coaly mudstone and mudstone samples were collected and analyzed by using organic petrography (maceral composition and vitrinite reflectance) techniques, Rock–Eval pyrolysis, bitumen extraction and gas chromatography - mass spectrometry (GC–MS). The obtained results indicate that the samples exhibit promising gas-prone source rock potential and contain a predominantly terrestrial in origin organic matter, with limited contribution by marine organisms. The prevalence of terrestrial organic matter is inferred by the presence of collotelinite and sporinite macerals in most of the samples and the ternary plot of C27, C28 and C29 regular steranes. Further, the low C27/C29 ratio, the cross-plots of C27/(C27 + C29) regular steranes vs. Pr/Ph ratio, the C27/C29 vs. Pr/Ph and the C24 tetracyclic/C26 tricyclic terpane ratio point also to the terrestrial origin of the organic matter. The obtained values of vitrinite reflectance, Tmax, OEP27–31 and CPI25–33, along the cross plots of 20S/(20S + 20R) versus ββ/(ββ + αα) suggest that the samples are immature and were subjected to a low burial depth. The examined samples indicate accumulation in a delta-plain environment of deposition, under fluctuating oxic/anoxic conditions, in a humid climatic zone that is characterized by dry periods, interrupting the longer-termed humid climatic regime. This research adds knowledge on the source rock potential in the northern Sydney Basin and on the environmental and climatic setting of a time interval just prior to the major Permian - Triassic climatic crisis.

Geochemical Characteristics and Significance of Molecular Markers in the Paleogene-Neogene Crude Oils of the Northwest Qaidam Basin.

The western Qaidam Basin is rich in oil and gas resources, constituting over 90% of the total oil and gas resources in the whole basin. However, the regional distribution characteristics of molecular markers of crude oil and the petroleum system elements relevant to the distribution of oil and gas in the northwest Qaidam Basin are still unclear, which restricts further exploration of oil and gas reservoirs. A total of 38 crude oils were collected from the Xiaoliangshan Sag and Mangya Sag in the northwest Qaidam Basin and analyzed by gas chromatography-mass spectrometry (GC-MS). The indicators of sedimentary environment, organic matter source, and thermal maturity show regular changes from the west to the east in the Xiaoliangshan Sag and Mangya Sag. The nC21 -/nC22 +, n(C21 + C22)/n(C28 + C29), and C27-C28-C29 regular sterane distribution characteristics indicate that the input proportion of lower aquatic organisms in source rocks (E3-N1) gradually increases, while the input proportion of terrigenous organic matter gradually decreases. The triaromatic dinosterane index (TDSI) and methyltriaromatic steroid index (MTDSI) indicate that the input proportion of dinoflagellates gradually increases. The gradual increase in the Pr/Ph ratio indicates a decrease in the reducibility of the sedimentary environment of source rocks. The gammacerane index (Ga/C30H) and methylated-2-methyltrimethyltride-cylchromans (MTTCs) indicate that the degree of stratification and salinity of water body gradually decrease. A total of 23 thermal maturity parameters indicate that crude oil is in a mature evolution stage, and the thermal maturity of crude oil increases with depth, indicating that there are the characteristics of hydrocarbon accumulation close to source rocks. The variation features of sedimentary environment, organic matter origin, and thermal maturity indicators from the west to the east in the Xiaoliangshan Sag and Mangya Sag are controlled by the sedimentary structure characteristics of the study area.

GEOCHEMICAL ANALYSES OF EOCENE OILS IN DEEPLY BURIED SANDSTONE RESERVOIRS IN THE DONGYING DEPRESSION, BOHAI BAY BASIN, NE CHINA

We report the results of organic geochemical analyses of 19 crude oil samples from reservoir sandstones in the 4th Member of the Eocene Shahejie Formation from wells in the Minfeng Sag, Dongying Depression, Bohai Bay Basin (NE China). In addition, 42 Shahejie Formation core samples of dark‐coloured mudstones, including 28 extracts, were analysed. Geochemical data included Rock‐Eval measurements, gas chromatography, GC‐MS and diamondoid analyses.Maceral analyses showed that mudstones in the 4th Member of the Shahejie Formation (“Es4”) contain Types I and II1 kerogen. The member can be divided into upper (Es4s) and lower (Es4x) intervals. Oil‐prone Es4s rock samples have good to excellent hydrocarbon‐generating potential based on calculated initial TOC values; Rock‐Eval Tmax values indicate that they are sufficiently mature for hydrocarbon generation. Analytical results suggest that both Es4s and Es4x mudrocks are potential source rocks for oils produced at fields in the Minfeng Sag.Analysed crude oils from the Minfeng Sag were classified into three genetic groups. Group I oils are mature to highly mature and have undergone a moderate degree of thermal cracking. They are characterized by a low β‐carotane/nC25 ratio and C30 4‐methylsterane index (4MI); high values of oleanane index (oleanane /C30‐hopane), C27 diasterane/C27 regular sterane (C27Dia/C27), regular sterane/17α hopane and gammacerane/C30 hopane (G/H); and medium pristane/phytane ratios (Pr/Ph). This suggests that Group I oils are mostly derived from source rocks in the upper part of the Es4x unit which are interbedded with evaporites. Group II oils are mature and have high 4MI and Pr/Ph ratios, low oleanane index, regular sterane/17α hopane and C27Dia/C27 ratios, and mediumβ‐carotane/nC25 and G/H. These features are similar to those of Es4s source rocks, indicating their genetic correlation. Group III oils show the lowest maturity and highβ‐carotane/nC25 and regular sterane/17α hopane, and low oleanane index, Pr/Ph and 4MI. Previously‐published data indicates that oils similar to those in Group III were mainly sourced by Es4s mudstones.

The Early Cretaceous Sembar Formation, Southern Indus Basin, Pakistan: Biomarkers and Trace Element Distributions to Investigate the Sedimentary Palaeoenvironment and Organic Matter Input.

The Early Cretaceous clay-rich facies of the Sembar Formation represent the most significantly occurring organic-rich sediments in the Southern Indus Basin of Pakistan. In this study, detailed geochemical research of total organic carbon, biomarker, mineralogy and trace elemental compositions, together with kerogen microscopic analysis, were carried out and used to understand the organic matter input and the dispositional environmental setting of the organic-rich Sembar shale. The Sembar shales have high organic matter, as indicated by the total organic carbon (TOC) content of up to 2.31 wt %. These shales contain a high abundance of liptinites (i.e., alginite and bituminite), with significant reactive vitrinite maceral, reflecting a mixed-organic matter with a high contribution of marine-derived input. The biomarker distributions evidence the finding of mainly marine organic matter. The biomarker characteristics such as Pr/Ph, Pr/n-C17, Ph/n-C18, and tricyclic terpane ratios together with C27-C29 regular sterane distributions show that the source of organic matter was primarily marine-derived from mainly phytoplankton algae, along with amounts of land plant input, and accumulated under a low oxygenated environment. The Sembar shale facies are characterized by high Mo trace element content and high V/Ni and Mo/TOC ratios, suggesting anoxic and nonsulfidic environmental conditions during time deposition. The geochemical proxies such as the Sr/Ba ratio and gammacerane/C30 hopane (G/C30) index suggest that the Sembar shale facies were deposited in a relatively low moderate stratified water column. The higher gallium (Ga) than rubidium (Rb), with high Ga/Rb ratios, indicates a high abundance of the kaolinite mineral, thereby deducing the subaerial weathering during the warm and humid climatic conditions. In this case, these warm and humid climatic conditions cause an influx of masses of nutrients, which could be attributed to increasing marine primary bioproductivity. These large masses of nutrients into the photic zone are also attributed to the presence of the upwelling system during the deposition time. Therefore, such conditions of bioproductivity and preservation of organic matter (OM) resulted in the accumulation of organic carbon in the shale facies of the Early Cretaceous Sembar Formation.

Investigating the hydrocarbon potential of the Paleogene coal seams in Kapuni field, Taranaki basin, New Zealand: Implications for coal-oil correlation

Hydrocarbon generation in Taranaki Basin, New Zealand, has been proven in several source rocks within the syn- and post-rift basin-fill sedimentary successions. These source rocks are mainly hosted in the marginal and deep marine Upper Cretaceous shales, which generate marine and terrigenous oils. Some of the terrigenous oils could have been linked to the Paleogene coals; however, the capability of these coals to generate and expel liquid hydrocarbons is poorly-investigated. In this study, we present organic geochemistry, kerogen petrography, wireline logging, and basin modelling to evaluate the hydrocarbon generation potential of the Paleogene coals and coal-rich facies of the Kapuni Group sediments in Kapuni Field, Taranaki Basin. A compositional correlation between oil in the Kapuni Group reservoirs and coal extracts was performed to decipher the oil origin and define its parent source rock. Kapuni oils display high pristane/phytane (Pr/Ph) > 5, low dibenzothiophene (DBT)/phenanthrene <0.1 and high relative abundance of C29 regular steranes >60%, typifying their generation from a terrigenous source rock deposited in an oxic, fluvio-deltaic environment. Similar values were also observed in the muddy coal extracts of Farewell Formation, thereby reflecting a positive coal-oil correlation. The maturity-relevant biomarkers (Ts/Tm trisnorhopanes; C29 steranes isomers, and 22S-, 22R C32 homohopanes) are similar in both oils and Farewell coal extracts confirming oil expulsion from Farewell coals during the peak oil window maturity. These results demonstrate the generation and expulsion of coal-oil, thereby shedding light on the prospectively of the Paleogene plays in the Taranaki Basin.

Sedimentary environment shift and organic matter enrichment mechanism in response to volcanic ash influence: A case study of the Permian Lucaogou Formation, Santanghu Basin, NW China

The second member of the Lucaogou Formation (P2l2) in the Tiaohu and Malang Sags of the Santanghu Basin (study area) underwent periodic volcanic activity and frequent lithological changes. This study comprehensively analyzed the organic geochemistry, mineral composition, organic matter (OM) types, volcanic cycle, and palaeoenvironment of shale in the study area. Techniques such as total organic carbon (TOC), rock pyrolysis (Rock-Eval), organic petrology, scanning electron microscopy (SEM) with energy-dispersive spectrum (EDS) analysis, X-ray diffraction (XRD), trace elements, and saturated hydrocarbon gas chromatography and mass spectrometry (GC–MS) were employed. The findings suggest that limited terrigenous input during the sedimentary period of the P2l2 led to the deposition of a distinctive mixture of volcanic ash (felsic) and carbonate (dolomite and calcite), with a low average clay mineral content of 6%. The P2l2 shale emerged as a high-quality source rock, predominantly composed of type I and II kerogens, with moderate OM maturity. The deposition environment was characterized by hot and arid conditions, high salinity, and intensive reducibility, which was favorable for algae development and conducive to OM preservation. Notably, two lamalginite types, labeled as lamalginite “A” and lamalginite “B,” were identified. Lamalginite “B”-rich shales were deposited in a hotter and drier climate compared to lamalginite “A”-rich shales. Lamalginite “B”- rich shale inexhibited high levels of C28 regular sterane and β-carotenes, distinguishing it from lamalginite “A”-rich shale. A comprehensive analysis involving organic petrology, SEM, sedimentary environment, and biomarker characteristics suggests that lamalginite “B” may be a salt-tolerant green alga, while lamalginite “A” may be a cyanobacterium. Finally, an OM enrichment model for the P2l2 shale was established.

Oil-source correlation in the Yangjiang Uplift, South China Sea: A comparative analysis of mathematical and fingerprint methods

In recent years, significant exploration breakthroughs have been achieved in the Yangjiang Uplift. However, the source of crude oil is ambiguous, and the prevailing view suggests a remote hydrocarbon supply. To clarify the source of the crude oil in the Yangjiang Uplift, 30 source rocks and 15 crude oil samples collected from the Wenchang A Sag and Yangjiang Uplift are subjected to Rock-Eval pyrolysis, maceral analysis, vitrinite reflectance, and biomarker analysis, among other experiments. Principal component analysis and hierarchical cluster analyses are performed. The results indicate that the source rocks in the Yangjiang Uplift exhibit robust hydrocarbon-generating potential, with S1 + S2 values ranging between 0.04 and 140.5 mg/g (averaging: 13.54 mg/g), indicative of reaching the oil generation period. Using 13 biomarker compounds, two types of biomarkers are selected to compare the sources of the crude oils: pristane/phytane (Pr/Ph) representing the depositional environment and tricyclic terpanes (TTs) representing the source input. The crude oil in the Yangjiang Uplift can be divided into two types: one with high values of bicadinane-T (T)/C30 hopane and ΣC30-4 methyl sterane/ΣC29 regular sterane and another with a low ratio of (C19TT + C20TT)/C23TT according to the charting method. The investigated crude oil is mixed with the source rocks of the Wenchang A Sag and the Yangjiang Uplift. Furthermore, owing to the differences in the mixing ratios, the crude oil in the study area exhibits two distinct characteristics. Type A is characterized by a higher proportion of the Wenchang A Sag crude oil in the mixture, whereas type B is characterized by a higher proportion of local crude oil. This study establishes that the Yangjiang Uplift boasts large petroleum resources.

OIL FAMILIES AND GEOCHEMICAL COMPOSITION OF DEVONIAN OILS AT THE RECHITSA FIELD, PRIPYAT BASIN, BELARUS

The sedimentary column at the Rechitsa oilfield in the Pripyat rift basin, Belarus, is dominated by an Upper Devonian synrift succession. The succession includes uppermost Frasnian and mid‐Famennian salt units which are about 1000 m and 2000 m thick respectively. Reservoir rocks consist of sandstones and carbonates in the intra‐, inter‐ and sub‐salt successions. In this paper, the geochemical analysis of 15 oil samples from different stratigraphic intervals at the Rechitsa field is used as a basis for reservoir characterisation. Geochemical studies included biomarker and stable C, N and S isotope analyses.Four genetic oil groups were identified and are referred to as Groups A to D. Oils in Group A came from upper intra‐ and inter‐salt reservoir rocks; the oils are early mature, enriched in heavy (C36+) hydrocarbons, heteroatoms, aryl‐isoprenoids and gammacerane, with low Pr/Ph = 0.6 and a sulphur isotope composition averaging 22.7‰ CDT. Oils in Group B were from sub‐salt reservoirs and are at peak maturity with Pr/Ph = 1, an increased proportion of C27 regular steranes, and a sulphur isotope composition of 8.1‰ CDT. The single oil sample in Group C was from a Proterozoic reservoir. The oil was overmature with a low content of heavy fractions, heteroatoms and steranes; its hopanes composition indicated that it was generated by the same source rock as the oils in Group B. Oils in Group D came from inter‐salt reservoir rocks and were composed of a mixture of Groups A and B oils in roughly equal proportions, as indicated by their average isotope, molecular and biomarker compositions.Observed differences in oil composition were explained in terms of contributions from at least two different source rocks together with variations in source rock maturity. Group A oils were interpreted to have been generated by Famennian carbonate‐rich source rocks containing dominantly marine and bacterial organic matter deposited in an anoxic evaporitic setting. Source rocks for Groups B and C oils were suggested to be composed of OM‐rich marine shales of Frasnian age or older.The geochemical characteristics of the Devonian oils from Rechitsa field, and the oil‐oil and oil‐ source rock correlations reported, will contribute to a better understanding of the petroleum system in the Pripyat Basin although direct oil‐ source rock correlations are not yet available. The presence of at least two source rocks for the Rechitsa oils has been suggested, respectively comprising carbonates in the inter‐salt succession and marine shales and/or carbonates in the sub‐salt succession. The main controls on oil composition in the Devonian reservoir units were the varying contributions from the different source rocks and differences in source rock thermal maturity associated with variations in burial depth and tectonics, together with the stratigraphic distribution of reservoir units which was in turn controlled by the presence of the thick Frasnian and Famennian salt units.

Geochemical and Organic Petrological Characteristics of the Bituminous Carbonate Succession (Upper Cretaceous Shu'ayb Formation) in Northern Jordan: Implications for Organic Matter Input and Paleosalinity, Paleoredox, and Paleoclimatic Conditions.

Bituminous carbonate rocks of the Upper Cretaceous Shu'ayb Formation from the Ajloun outcrop in Northern Jordan were geochemically and petrologically analyzed in this study. This study integrates kerogen microscopy results with geochemical results (i.e., biomarker, stable carbon isotope, and major elemental compositions) to understand the organic matter (OM) inputs and to reveal the dispositional setting and its effect on the occurrence of OM. The Shu'ayb bituminous carbonate rocks have high total organic carbon (TOC) and sulfur (S) contents, with average values of 12.3 and 4.59 wt %, respectively, indicating redox conditions during their precipitation. The high abundance of alginite (i.e., lamalginite) in the Shu'ayb bituminous carbonate sediments is a further evidence for redox conditions. The finding of mainly marine-derived OM was also demonstrated by the biomarker distribution and carbon isotope composition. The biomarkers are represented by a narrow Pr/Ph ratio of up to 0.97, abundance of tricyclic terpanes, and high C27 regular sterane, indicating that the OM was primarily derived from phytoplankton algae, along with small amounts of land plant-derived materials, and were accumulated under reducing conditions. The studied Shu'ayb bituminous carbonate facies is composed of mainly calcium (CaO; average, 45.10 wt %), with significant amounts of silicon (Si2O3; avg., 9.35 wt %), aluminum (Al2O3; avg., 6.91 wt %), and phosphorus (P2O3; avg., 1.47 wt %) and low amounts of iron (Fe2O3) and titanium (TiO2) of less than 1 wt %, indicating that the detrital influx was low in an open water depth system with higher primary bioproductivity. The geochemical proxy suggests that the Shu'ayb bituminous carbonate facies was established in a saline water environment, with Ca/Ca + Fe and S/TOC values of more than 0.9 and 0.50, respectively, which could be attributed to the increase in reducing conditions of the water column. The chemical index of alteration values of more than 0.8 also indicate that the Shu'ayb bituminous carbonate facies formed during warm and humid climatic conditions, thereby resulting in intense subaerial weathering.

Nature and occurrence, geochemical characteristics, and families of the crude oils in Sirt Basin, Libya: Implication for super rift basin petroleum system

In this study, we investigated the nature and characteristics of petroleum fluids in a super-global basin situated in the central north of Libya. With over 100 discovered fields (comprising oil and gas), this study aimed to understand the basin's petroleum accumulation mechanism (PAM), thereby shedding light on the factors contributing to significant petroleum discoveries in North Africa (Libya). The primary objective of this study was to provide a detailed regional refined oil family distribution and new insights into the total petroleum system (TPS) of the basin. This analysis was based on the integration of regional geology and organic geochemistry. Additionally, we utilized the physical properties of petroleum, such as API and sulphur content (%S), to obtain a better understanding of the regional physical nature of petroleum types and properties. Organic geochemical data for the basin fields were compiled, focusing on key biological marker and carbon isotope (‰ δ13C) data for saturated and aromatic compounds. These data were used to understand the origin, depositional source, and thermal maturity of the generated, migrated, and accumulated petroleum fluids. The study established specific types of organofacies and their relationships with petroleum phase characteristics, including type and quality, categorized into known groups (e.g., B, C, and D/E). Hierarchical cluster analysis (HCA) and map-based presentation approaches were used to determine the spatial types and distributions of oil and gas families in the basin. This was achieved by selecting the input parameters from various datasets and defining the significant parameters to characterize the distribution patterns. The findings indicate that the bulk fluid of the Sirt Basin primarily resembled Brent oil, which was characterized by a very low sulphur content (less than 1.4%). The API gravity ranged from 30 to 65, reflecting a diverse range of oil types within the basin. The crude oils in the basin were primarily derived from marine organofacies, predominantly from type B. This inference is supported by related biomarkers such as regular steranes and isoprenoids. Furthermore, the analysis of carbon isotopes provided a similar indication, with values ranging from −32 to −27 for ‰ δ13C for saturates and −31.2 to −25.4 ‰ δ13C for aromatic compounds. The thermal maturity biomarker ratio (Ts/Ts + Tm) of the Sirt Basin crude oils varied from 0.35 to 0.92, suggesting different levels of thermal maturity, typically ranging from the mid to late mature stages. This observation is consistent with the indication based on the 22S/22S + 22R ratio. The basin exhibited four dominant oil families and eight subfamilies with the same geochemical characteristics (HCA-based analysis), including early and later generations, relatively sulphurized oils, and condensate families.

Molecular organic geochemistry and origin of oil in the Potwar Basin, Pakistan

The Potwar Basin (PTB) is a prominent geological feature located in northern part of Pakistan, and is considered as one of the active and productive regions for petroleum and gas exploration in Pakistan. In this study, eight crude oil specimens originating from three distinct fields within the PTB were comprehensively examined to decipher the environmental conditions, source of organic matter (OM) and oil-oil correlations using gas chromatography coupled with flame ionization detection (GC-FID) and gas chromatography-mass spectrometry (GC–MS). The molecular marker and hierarchical cluster analysis of PTB oils reveal two different crude oil families. Family-I showed relatively low values of Pr/Ph, C19TT/C23TT and C25TT/C24TeT, C27-C29 regular steranes, dibenzothiophene (DBT), fluorene (FL) and dibenzofuran (DBF), as well as C26/C28 TAS (20S) and C27/C28 TAS (20R). These results suggest that Family-I crude oils derived from marine environment of suboxic water bodies with higher contribution from green algae or planktonic microbes. However, Family II contains comparatively high values of the aforementioned molecular parameters, indicating that crude oils mainly originated from a lacustrine environment with a higher contribution of plant organisms under oxidizing conditions. Saturated hydrocarbon maturity parameters such as CPI and OEP, and C3122S/(C3122S + C3122R) and C3222S/(C3222S + C3222R) indicate PTB crude oils are thermally mature, while aromatic indices reveal that Family-II crude oils are high mature. The present research defines that PTB crude oils contributed from mixed organic matter sources of marine and lacustrine majorly from marine sedimentary environment with the bloom of algae and/or higher plants.

Petroleum potentiality of the Balambo Formation in Bekhme and Razan sections, Kurdistan region, northeastern Iraq

Balambo Formation (Early Cretaceous) had been studied in Razan and Bekhme sections, Erbil Governorate, Kurdistan Region-Iraq, to determine the hydrocarbon generation potentiality for the studied rocks. The samples were analyzed for TOC, Rock Eval pyrolysis and GC-MS technique. The Balambo Formation’s TOC wt. % content is relatively high, ranging between 0.95 to 7.59 wt.% (average 2.91 wt.%). The Formation has the potentiality to generate gas and oil owing to its suboxic-anoxic depositional environment, marine origin organisms, suitable maturity level, and the type of kerogen is predominantly types III and subordinate amount of mixed type II-III according to the Rock-Eval pyrolysis data and isoprenoid/n-alkane. The C27%, C28% and C29% regular steranes distribution suggested the studied formation is deposited in marine environment. The samples were proven to be mature based on the ratios of the Tmax, steranes 20S/ (20S+20R)C29 to ββS/(ββS+ααR)C29 steranes and C32 22S/(22S+22R) hopane. Although the Ts/(Ts+Tm) ratio data point to an early mature stage, vitrinite reflectance predictions ranged from 0.55 to 0.75%, once more pointing to a mature stage.

Influence of HEM Drilling Fluid on Organic Geochemical Characteristics of Deep-Water Source Rocks in the Qiongdongnan Basin.

The influence of oil-based drilling fluid on the geochemical characteristics of source rocks has been widely reported in the northern South China Sea. However, contamination from water-based HEM drilling fluid has long been neglected in previous deep-water petroleum exploration. To further understand the impacts of HEM drilling fluid on deep-water source rocks, the organic matter abundance and type, kerogen maceral composition, and saturated biomarkers of the deep-water source rocks in the Qiongdongnan Basin were investigated. The influence of HEM drilling fluid on the organic geochemistry data of cuttings is significant but minor for sidecores. It is evident that the organic drilling additives in HEM drilling fluid can increase the organic matter abundance and optimize the organic matter types of shale cuttings. Specifically, the total organic carbon, S1, S2, and hydrogen index are increased by 28.5 ± 6.1, 90.8 ± 2.0, 34.2 ± 2.0, and 51.9 ± 4.0%, respectively. Furthermore, the organic drilling additives will greatly enhance the levels of C29 regular steranes, especially for C29-ααα-20R sterane, with the influence still persisting even when conducting GC-MS-MS analysis. The highly abundant 17α (H) -22, 29, 30-trisnorhopane, 17β (H)-22, 29, 30-trisnorhopane, C29-3117α (H), 21β (H) hopanes, and C29-31 17β (H), 21α (H) hopanes may directly originate from the organic drilling additives. It is dangerous to directly use organic geochemical data from deep-water source rock cuttings contaminated by HEM drilling fluid as it may lead to conclusions that are entirely inconsistent with the basin's geological background.

Organic geochemical characteristics of the Late Cretaceous coal and carbonaceous shale succession from the Taranaki Basin, New Zealand: Implications for sedimentary environmental setting and petroleum generation potential

This comprehensive study investigates the organic matter characteristics within the Late Cretaceous Rakopi and Taniwha formations, based on data from four exploration wells situated in New Zealand's Taranaki Basin. It employs a multifaceted approach, integrating bulk geochemical analyses, biomarker measurements and carbon isotopes to unveil the geological history of these formations. Analytical results include total organic carbon content, ranging from 7.27 to 75.78 wt%, and generation potentials spanning from 28.24 to 309.16 mg hydrocarbon/g rock. These observations underscore the source rock potential of these Late Cretaceous strata. These rocks show a mixed organic matter of hydrogen‐rich Type II and Type II/III kerogens, as evidenced by hydrogen index values (HI) between 237 to 428 mg hydrocarbon/g rock. These formations demonstrate promise potential for both oil and gas generation. Biomarker analysis uncovers distinct signatures, featuring a pristane/phytane (Pr/Ph) ratio ranging from 3.27 to 10.91, a Tm/Ts ratio surpassing 7 and elevated concentrations of C29 regular steranes relative to C27 and C28 regular steranes. These biomarker characteristics suggest a composite organic matter composition, influenced by terrigenous organic matter, likely deposited in oxygenated fluvial deltaic environments. Bulk carbon isotopic data corroborate these findings, highlighting the abundance of terrigenous organic matter. Collectively, these insights reveal that the coal and carbonaceous shale intervals in the examined wells are in the early stages of oil generation. Therefore, the Rakopi and Taniwha formations have not yet yielded commercially viable oil and/or gas quantities. In this case, these formations hold substantial promise for future exploration activities in relatively deep wells, with limited oil expulsion from coals.

Intensified bacterial productivity during the Paleocene–Eocene thermal maximum: Molecular evidence in the Tarim Basin in the eastern Tethyan realm

The investigation of bulk and molecular compositions in organic matter at the Bashibulake Section in the SW Tarim Basin, West China, across the Paleocene–Eocene boundary reveals a complex mixture of marine and terrigenous origins during the Paleocene–Eocene Thermal Maximum (PETM) in the eastern Tethys. Source-related biomarkers, such as n-alkanes, isoprenoid alkanes, steranes, hopanes and methylhopanes, exhibit diverse compositions influenced by both marine and terrigenous sources. Sterane and hopane isomer distributions, indicative of immature OM, are primarily controlled by biological configurations. Changes in compound class abundance and isomer ratios reflect variations in source inputs and depositional conditions. Elevated concentrations of n-alkanes from higher plants, along with ratios of C29-C32 moretanes/hopanes and C31/C32 homohopanes, suggest increased terrigenous OM supply during the PETM. However, the significant differences in concentration between n-alkanes from higher land plants and bacterial hopanes, coupled with the presence of 2α-methylhopanes, prevalence of C27 compounds in regular steranes, and absence of oleanane suggest a dominant aquatic bacterial contribution. The study highlights the role of enhanced continental flux and warming in stimulating microbial activity, enriching OM, a factor often overlooked by other analytical methods. The absence of carbonate carbon and low trisnorhopane isomerization provide supportive evidence of ocean acidification and carbonate dissolution during the PETM. Reduced pregnanes and tricyclic terpanes, along with low degree of hopane and sterane isomerization, indicate rising sea levels and low salinity. The findings emphasize the significance of the biomarker approach in identifying OM origin and characterizing the depositional environment in PETM-related sequences, suggesting a more substantial role of bacterial contributions than previously recognized.

The source and preservation of lacustrine shale organic matter: Insights from the Qingshankou Formation in the Changling Sag, Southern Songliao Basin, China

Organic-rich shale in the Cretaceous succession of the large non-marine Songliao Basin in northeastern China, especially the Qingshankou Formation of the Turonian and Coniacian stages, provides a unique record for studying the role of global climate control on organic matter accumulation. Organic enrichment in the Qingshankou Formation along the Southeastern Uplift of the basin has been widely reported and is implicated in the formation of algal blooming and a saline anoxic water environment. However, studies on the Qingshankou Formation in the Changling Sag are relatively few, which leaves a significant gap to understand the controlling factors of organic enrichment at a basin scale. In this study, the sedimentary environment of the first member of the Upper Cretaceous Qingshankou Formation (K2qn1) is reconstructed from petrological and geochemical data to discuss the sources and preservation mechanisms of lacustrine shale organic matter in the Changling Sag (southern Songliao Basin). The K2qn1 is subdivided into three stratigraphic units: Sq1 phase, Sq2 phase, and Sq3 phase. Biomarker (abundance of tricyclic terpane and regular steranes) and petrographical (maceral composition) data indicate that the organic matter in K2qn1 was mainly from terrigenous plants, with some algal input. Inorganic minerals (major and trace elements) and petrological (framboidal pyrite size) data suggest a humid climate and saline anoxic water environment at the Changling Sag during the most organic-rich Sq1 phase. During the Sq2 and Sq3 phases, a relative low lake level and semi-arid climatic conditions likely prevailed. Moreover, these results imply that apart from a saline anoxic water environment, the persistence of continentally derived organic matter in lacustrine shale is mainly controlled by clay minerals. Accordingly, this study proposed a new enrichment model for lacustrine shale organic matter. The new model complements existing lacustrine shale sedimentary models for sources of organic matter and emphasizes the role of clay minerals in preserving organic matter.

Characteristics and origin of low-organic-matter carbonate source rocks in the Middle–Upper Ordovician, Tarim Basin, northwestern China

The continually-discovered large volumes of marine hydrocarbons indicate a huge exploration potential within the carbonate rocks of Ordovician in the Tarim Basin, northwestern China. The Middle–Upper Ordovician (O2+3) carbonate source rocks are at a highly mature stage. These rocks presently contain a low amount of total organic carbon (TOCpd ≤0.5%) (TOCpd means the present-day TOC). A mass balance approach is used to identify the source rocks that have expelled hydrocarbons. The characteristics and origin of hydrocarbon expulsion from low-TOCpd source rocks are studied, which are significant for oil exploration in the basin. The results showed that a low-TOCpd O2+3 source rock having expelled hydrocarbons was type I and had a very narrow oil window. With a high rock maturity and a high original TOC (TOCo) value exceeding 1%, nearly 80% of the generated hydrocarbons were expelled. The content of gammacerane and C28 steranes in the oil and source rock extracts were relatively lean, with a V-shaped distribution of regular steranes, suggesting a possible genetic relation between the low-TOCpd source rocks and the marine oil in the Tabei area. Hydrogen-rich planktonic algae or acritarchs were the main hydrocarbon parent materials, distributed in the subsiding platform-slope facies. Organic matter was preserved under reducing conditions, and source rocks were formed with a favorable kerogen type and a moderate hydrocarbon generation potential. This study illustrates the hydrocarbon expulsion of low TOCpd source rocks in northern Tarim Basin, which is greatly significant for analyzing the genesis of marine crude oil in Tarim Basin, and evaluating the distribution of marine source rocks. This research method is theoretically significant for oil and gas exploration in the same type of highly-mature carbonate paleobasins.

Geochemical and Organic Petrological Evaluation of Organic Matter from Tertiary Sediments of Baga Field in Chad Basin, Northeast Nigeria

The Upper Cretaceous sediments in Bornu are considered an important regional source rock in the Chad Basin. This study therefore evaluated the geochemical and organic petrological evaluation of organic matter in tertiary sediments of Chad Basin, Northeast Nigeria by collecting 25 cutting samples from these organic-rich shale sediments from four wells drilled in Baga field in the Nigeria sector (Bornu) of the Chad Basin, in order to geochemically assess the type of organic matter, thermal maturity, and palaeoenvironmental conditions. Results reveal that Bornu sediments contain high organic matter more than 2.0 wt% TOC and have an excellent oil-generation potential. This is supported by high bitumen extractions and hydrocarbon yields with values 5827 and 3547 ppm, respectively. The investigated biomarkers indicated that the shale sediments contain a high abundance of C27 regular sterane concentrations, high C27/C29 regular sterane ratios and relatively low value of the biomarker sterane/hopane ratio as well as the presence of tricyclic terpanes. A mainly suboxic to relatively anoxic preservation conditions is inferred from Pr/Ph ratios (1.03–2.53). This is support by normal alkane distributions, which are characterized by dominance of types I/II kerogen and low medium molecular weight n-alkane compounds, respectively. This is further supported by lower amounts of acyclic isoprenoids compared to n-alkanes (e.g., pristane/n-C17 and phytane/n-C18 ratios). This is also supported by a mixture of algal and amorphous organic matter that was deposited in a lacustrine environment identified from kerogen microscopy. Based on the analyzed biomarkers, triterpanes and terpanes thermal maturity indicates that the Bornu sediments organic matters have entered into early mature stage for oil generation. This is also supported by vitrinite reflectance values of 0.57–0.71 % Ro indicate that these organic matters have reached oil window maturity.

Correlation Between Chang‐9 Crude Oil and Potential Source Rocks, Upper Triassic Yan‐Chang Formation, Middle Area of Ordos Basin: Correlation Between Crude Oil in the Chang‐9 Member and Potential Source Rocks

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.

Geochemical characteristics of Cambrian bitumen and Cambrian-Ordovician source rocks in the Keping area, NW Tarim Basin

The Cambrian Yuertus Formation and Ordovician Saergan and Yingan formation source rocks, which TOC contents of 0.38%–4.30%, are well developed in the Keping area of the Tarim Basin. Reservoir bitumen had been found in the Cambrian Wusongger Formation and Shayilike Formation. In this study, the geochemical characteristics of the bitumen and source rocks were analyzed through biomarkers for oil-source correlation. The results show that the characteristics of the bitumen and Yuertus Formation source rocks are similar. Comparatively, the Yuertus Formation source rocks and bitumen have lower Pr/Ph values and higher C28/C29 regular steranes values. The maturity characteristics and depositional environment of the Cambrian source rocks in the Keping area and the platform basin areas are similar. Plots of Ph/n-C18versus Pr/n-C17, Ts/(Ts+Tm) versus 4-/1-MDBT (methyl dibenzothiophene), and DBT/P (dibenzothiophene/phenanthrene) versus Pr/Ph distinguish the bitumen and source rocks well. As an original plot, we found that the Fla/Py (fluoranthene/pyrene) versus MP/P (methyl-phenanthrene/phenanthrene) intersection plot can be used to identify the possible sources of polycyclic aromatic hydrocarbons (PAHs) to a certain extent and can distinguish between the Cambrian and Ordovician source rocks in this study. Comprehensive analysis revealed that the bitumen samples most likely originated from the Yuertus Formation source rocks. It was also found that the biomarker characteristics such as the shape type of the C27-C28-C29 regular steranes, triarylosteranes, and triarylosteroids are not applicable to distinguishing the Cambrian and Ordovician source rocks in the Keping area. These research findings provide references for studying the Lower Paleozoic oil-source correlation in the platform in the Tarim Basin.