Introduction

Deep and ultra-deep hydrocarbon exploration has emerged as a global research hotspot in the energy sector1. The Tarim Basin, the largest marine carbonate petroliferous Basin in China, has proven abundant deep (> 4500 m) to ultra-deep (> 6000 m) petroleum resources (light oil, condensate, and heavy oil) through exploration in the Lungu-Tahe, Tazhong, Fuman, and Shunbei oilfields2,3,4. However, the identification of effective source rocks in the Lower Paleozoic petroleum system remains a significant point of contention5,6. The debate on the marine oil source in the Paleozoic Tarim Basin has persisted for nearly 40 years since the discovery of industrial oil flow in the Shacan 2 well in 1984, with the focus shifting from Carboniferous to Cambrian-Ordovician source rocks7. As exploration progressed, analytical techniques improved, and more outcrops and profiles became available, the main source rocks have been identified as the Lower Cambrian Yuertus Formation (Є1y), Middle-Upper Ordovician Heituao Formation (O1−2h), Middle-Lower Ordovician Shaergan Formation (O2−3s), and Lianglitage Formation (O3l)8,9,10,11,12,13,14,15.

Despite evidence supporting the Cambrian and/or Ordovician source rock end-members, three key scientific issues remain unresolved in exploration practice: (1) Contradictions between oil-source correlation conclusions and actual geological conditions, for example, the ZS1 oil is believed to originate from Ordovician source rocks based on its typical “six-low-one-high” characteristics and light carbon isotopes (δ13C: −32‰ to −37‰)16. However, the reservoir (Upper Cambrian Awatage Formation, Є3a) and the inferred Ordovician source rocks are separated by evaporite layers, lacking effective migration pathways17; (2) Inconsistencies between biomarker compounds, corresponding parameters (triaromatic steroids, triaromatic dinoflagellate steroids, etc), and isotopes (carbon and sulfur) in classical oil source correlation. The YM2 oil exhibits significant aryl isoprenoid distributions and high sulfur isotope values8,18 typical of Cambrian source rocks, but its n-alkane’ carbon isotopes (δ13C: −35‰) indicate a classical Ordovician end-member oil19; (3) The exploration and characterization of Cambrian source rocks in the Tarim Basin remain inadequate, with limited understanding of the internal heterogeneity within the Є1y and a paucity of systematic evaluations of effective source rock intervals and their geochemical characteristics15,20,21,22. Although the Ordovician strata are considered significant source rock intervals in the Tarim Basin, the restricted distribution of O1−2h, O2−3s, and O3l raises questions about their potential as high-quality source rocks. In contrast, the Є1y exhibits a basin-wide distribution and possesses a relatively higher hydrocarbon generation potential7,23.However, long-term research on the Є1y has predominantly focused on the in-depth analysis of hydrocarbon generation potential and geochemical characteristics of thick, organic-rich siliceous rocks and shales, while neglecting the hydrocarbon potential of other lithofacies. In addition to thick shales and calcareous mudstones, also exhibit favorable hydrocarbon generation potential, particularly in the northern Tarim region22. Notably, aryl isoprenoids (AIs), a distinctive biomarker for Cambrian source rocks, have only been detected in a limited number of thick shale samples from the Є1y24. As stable biomarkers in oil-source correlation studies, AIs are also ubiquitous in the marine oils and pyrolysates of oil asphaltenes in the platform-basin regions of the Tarim Basin. Nevertheless, the thick shales reported to contain these compounds exhibit a discontinuous distribution and may not be the primary source rocks contributing to the high abundance of AIs in the oils. Consequently, in addition to thick shales, there may exist an unidentified high-quality source rock within the Є1y, underscoring the critical need for a refined evaluation of the Cambrian source rocks.

Recent major discoveries in the Shunbei and Fuman oilfields have highlighted carbonate petroleum systems similar to ZS1 as key targets for deep and ultra-deep oil and gas exploration in the Tarim Basin25,26. Therefore, systematically investigating the hydrocarbon generation variations, distribution, and geochemical characteristics of potential source rocks of different lithologies within the Є₁y interval will aid in identifying the source of the associated oil and gas. This will provide a scientific basis for advancing oil and gas accumulation models in the Tarim Basin and guiding exploration practices.

Geologic setting

The Tarim Basin, located in northwestern China, represents a typical cratonic basin. Its evolution experienced three major stages: Precambrian cratonization, Paleozoic passive continental margin, and Mesozoic-Cenozoic foreland basin development27 forming the current “four uplifts and five depressions” structural framework. During the Neoproterozoic, the breakup of the Rodinia supercontinent and assembly of Gondwana28,29,30 led to frequent hydrothermal activities and fluctuations in marine chemistry and biochemistry31.

Intense hydrothermal activity provided the ocean with abundant nutrient elements and widespread anoxic to sulfidic environments, promoting biological development and proliferation, thus creating favorable depositional conditions for high-quality Cambrian source rocks in the Tarim Basin31,32,33. The Cambrian explosion led to massive accumulation of organic matter in oceans, providing abundant biological input for Tarim Basin’s Cambrian high-quality source rocks33.

Under this global context, the Lower Cambrian Yuertus Formation (Є1y) in the Tarim Basin developed a series of high-quality potential source rock assemblages with different lithofacies (siliceous rocks, shale, and calcareous shale). The Є1y is underlain by dolomite-bearing Qigebulake Formation of the Sinian System and overlain by limestone and dolomite of the Xiaoerbulake Formation, presenting favorable geological advantages for forming good carbonate oil and gas reservoirs. Current Є1y source rock exploration results show that the eastern Tarim and its periphery, situated in deep-water slope and basin settings, mainly developed thick deep-water siliceous rocks and mudstones. The northern Tarim area, primarily developed in gentle slope and carbonate platform settings, mainly developed medium-thick dolomite, calcareous mudstone, and mudstone. Influenced by hydrothermal diffusion, the northern Tarim area also occasionally formed thin-bedded siliceous rocks and siliceous mudstones. The northwestern to Keping area mainly developed in platform facies, with outcrops and profiles showing significant siliceous rocks, mudstones, and dolomites in the Akesu area, exhibiting frequent hydrothermal disturbances during deposition. In areas unaffected by hydrothermal activity, extensive mud-limestone, mudstone, and dolomite formations developed, while siliceous rock formation was restricted.

Fig. 1
Fig. 1The alternative text for this image may have been generated using AI.
Full size image

(A) Simplified structural map of the Tarim Basin within China (data after He et al.34). (B) Simplified structure map and sampling location of Tarim Basin.

Materials and methods

Sample

Hydrocarbon source rock samples from the Є₁y interval in the Tarim Basin are primarily derived from wells and profiles in the southeastern Tarim, northern Tarim, and Akesu area. A total of 39 representative core, cuttings, and outcrop samples were collected for this study (Fig. 1). These samples encompass various lithologies of potential source rocks, including calcareous mudstone, shale, and siliceous rocks. Specifically, four shale core samples were collected from Well YD2 in the southeastern Tarim, while 19 samples of calcareous mudstone cores and cuttings were obtained from the northern Tarim (4 from Well LT3, 6 from Well QT1, 8 from Well LT1, and 1 from Well XHe1). In the Keping area, 13 profile samples were collected from the SARK profile (6 siliceous rocks and 7 shales), along with 4 shale samples from the XE profile. Additionally, one sample each of shale and siliceous rock was collected from Well ZH1 in the central Tarim. For a comprehensive study of Є₁y, this paper also integrates the findings of Chen et al.35. In order to facilitate a comparative analysis of the geochemical characteristics between Cambrian and Ordovician source rocks, pertinent data on typical Ordovician source rocks were also compiled for this study.

Analytical methods

Biomarker analysis

All rock samples were crushed to 100 mesh size and extracted using a mixture of 7% methanol and 93% dichloromethane (v: v) through Soxhlet extraction of 80 g rock samples for 72 h. A liquid column chromatography method using alumina (100–200 mesh) as a filler was employed to sequentially wash out saturated hydrocarbon fractions and aromatic hydrocarbon fractions from the extract using n-hexane and a mixture of dichloromethane/n-hexane (v: v = 1:2).

The instrument model used for aromatic hydrocarbon GC-MS analysis is HP Agilent 6890/5975 chromatography-mass spectrometry, with HP-5MS (60 m × 0.25 mm × 0.25 μm) chromatographic column, automatic injection, full scan/multi ion mode. The carrier gas used is high-purity He (up to 99.999%), with a flow rate controlled at 1mL/min. The initial temperature of the column box is 50 ℃, kept constant for 1 min, then heated to 100 ℃ at a rate of 20 ℃/min, and then heated to 315 ℃ at a rate of 3 ℃/min, kept constant for 20 min. The initial temperature of the sample inlet is 300 ℃, and a pulse non splitting mode is adopted. The pulse pressure is 35.0psi for 1.00 min, and the nitrogen gas is purged at a flow rate of 10.0mL/min for 2.00 min. The injection port temperature is 290 ℃, the ion source temperature is 230 ℃, and the transmission line temperature is 300 ℃. The mass spectrometry part is an EI ion source with an ionization voltage of 70 eV.

Mass spectral data were collected in full scan mode and analyzed for saturated and aromatic fractions under selected ion monitoring (SIM) mode. Relative compound ratios were calculated based on peak areas relative to internal standard peaks.

Isotope analysis

Compound-specific carbon isotope analyses of n-alkanes were performed on three SARK samples at the Key Laboratory of Deep Oil and Gas, China University of Petroleum (East China). After group fraction separation of source rock extracts, the saturated hydrocarbon fraction was subjected to urea adduction to isolate n-alkanes, iso-alkanes, and cycloalkanes. The carbon isotopic compositions of n-alkanes were measured using gas chromatography-isotope ratio mass spectrometry (GC-IRMS) with an HP6890 gas chromatograph interfaced to a GV Isoprime IRMS via a combustion interface. All samples were analyzed in duplicate, with analytical reproducibility typically within ± 0.35‰.

Results and discussion

Identification and distribution prediction of potential source rocks

The hydrocarbon generation potential of source rocks is typically reflected by geochemical data such as total organic carbon (TOC). However, for the evaluation of source rocks in specialized research areas, such as the emerging assessment of highly thermally evolved ancient source rocks, stable parameters and appropriate criteria should be selected for identification (Fig. 2)36. According to current outcrop and drilling data, the thickness of the Є1y formation increases significantly from west to east (Fig. 3a). In the northern Tarim region, the maximum drilled thickness of Є1y is 82 m (LT1), while in the eastern Tarim region, the maximum drilled thickness is 112 m (YL1)20,22,37. The predicted thickness in the Northern Depression exceeds 200 m23 indicating that Є1y has significant hydrocarbon supply advantages (Fig. 3a).

As the lower limit of organic carbon and the main basis for evaluating the potential source rocks in the Lower Paleozoic petroleum system of the Tarim Basin, TOC > 0.5% is widely accepted as representing ordinary to very good source rocks34,35,38. As one of the important Paleozoic source rocks, the potential source rock types of Є1y still require extensive statistical analysis. Evidently, siliceous rocks that may serve as potential source rocks are primarily developed in the northwestern Tarim and Keping regions, with TOC ranging from 0.08 to 14.89%, averaging 2.12%. Siliceous rocks with high TOC abundance are mainly distributed in DEG, KLX, SARK, KGKT, and other areas (Fig. 2a). There is also a certain distribution of siliceous rocks within the Northern Depression, but existing data is insufficient to substantiate their potential hydrocarbon generation capacity (Fig. 3b).

As effective source rocks developed throughout the basin, shales in Є1y have TOC values ranging from 0.06 to 22.54%, with an average of 2.97% (Fig. 2a). Along the eastern margin of the northern Tarim region, the TOC of thick shales in LT3, LT1, and QT1 increases progressively, while decreasing towards the western margin in XH1 and XHe1, with XHe1 exhibiting the lowest TOC. In the northwestern Tarim to Keping region, TOC fluctuates frequently, with relatively higher values in KGKT, SARK, KLX, DEG, and XKT1. Shales are the primary source rocks of Є1y, distributed nearly basin-wide, mainly in the Northern Depression. As the sedimentary facies gradually transitions from deep-water basin to carbonate platform in the northwestern to southwestern Tarim, the mudstone thickness decreases (Fig. 3c).

Differing from the aforementioned two known lithological source rocks, extensive exploration has revealed that calcareous mudstones demonstrate hydrocarbon generation potential far exceeding that of shales. Their TOC ranges from 0.05 to 29.78%, with an average of 6.75%, gradually decreasing from QT1 to LT3 (Fig. 2a). Calcareous mudstones are mainly distributed in the northern Tarim region, and through oil-source correlation and exploration practice, they are predicted to be distributed in the central Tarim, northern Tarim, and western Northern Depression (Fig. 3d), representing a previously unrecognized potential source rock in Є1y.

Notably, the hydrocarbon generation potential of source rocks may be influenced by kerogen type and thermal maturity39. Prior to the Devonian period, higher plants were not proliferative. For these highly thermally evolved ancient source rocks, equivalent vitrinite reflectance (EqRo%) of indigenous bitumen can serve as an effective method for evaluating maturity. Existing equivalent vitrinite reflectance data from exploration wells and outcrop profiles indicate that the EqRo% of Є1y throughout the Tarim Basin and its periphery exceeds 0.9%, placing it in the mature to over-mature stage (Fig. 2b). This suggests that source rocks of various lithologies may have already generated and expelled substantial quantities of hydrocarbons within the basin.

Fig. 2
Fig. 2The alternative text for this image may have been generated using AI.
Full size image

(a) Evaluation of organic matter abundance in Є1y source rocks in different regions of the Tarim Basin. (Data sources: LT1 (Zhu et al.22); LT3 (Ai et al.40); YD2 (Ying et al.41); XH1 (Zhu et al.42); (b) Evaluation of kerogen types in Є1y source rocks in the Tarim Basin. (Data sources: XH1, DEG, SGTBLK, XE(Chen et al.35); YD2 (Ying et al.41); TD2 (Liu et al.43); (c) Evaluation of organic matter thermal evolution in Є1y source rocks in the Tarim Basin. (Data sources: KLX (Yang et al.44); XE (Yu et al.45); KGKT (Ouyang et al.46; Zhang et al.47); SGTBLK (Zhang et al.47); XH1 (Zhu et al.42); QT1 (Zhang et al.21); LT1 (Zhu et al.22); YD2, TD1, TD2 (Liu et al.43).

Furthermore, from northwestern to eastern Tarim, the equivalent vitrinite reflectance of Є1y gradually increases, indicating an enhancement in organic matter thermal evolution. This demonstrates that the major hydrocarbon generation period in the eastern Tarim region occurred earlier than in the northern and northwestern Tarim regions. This thermal evolution phenomenon is further supported by the presence of Silurian bituminous sands with a thickness reaching 152.5 m15. The Pristane/n-C17 versus Phytane/n-C18 cross plot indicates that Є1y primarily generates hydrocarbons from Type II kerogen (Fig. 2c), consistent with kerogen isotope data results22,37,48,49.

Overall, variations in organic matter supply structure and depositional conditions from northwestern to eastern Tarim may lead to significant differences in organic matter abundance and origin. This has been previously demonstrated through microscopic observations49,50: in the northwestern Tarim region, organic-rich samples are dominated by benthic red algae with some green algae and dinoflagellates, while in the eastern Tarim region samples, abundant algal remnants, green algae, and dinoflagellates are observed. This indicates a lack of terrigenous organic matter contribution in these rocks, resulting in the predominance of Type I and Type II kerogen, with Type II being more abundant.

Therefore, among the currently explored hydrocarbon resources, contrary to the earlier recognized potential source rocks such as Cambrian siliceous rocks and shales, calcareous mudstones, due to their high TOC abundance and oil-prone organic matter, may serve as one of the primary hydrocarbon source rocks of Є1y.

Fig. 3
Fig. 3The alternative text for this image may have been generated using AI.
Full size image

Thickness distribution of various lithologic hydrocarbon source rocks in the Tarim Basin (data after Huang et al.5).

Characteristics of stable biomarker compounds

Extensive research has been dedicated to identifying biomarker compounds that reliably characterize the organic geochemical signatures of source rocks or crude oils during secondary alteration processes. Notably, triaromatic steroids (TAS, m/z = 231), triaromatic dinoflagellate steroids (TDS, m/z = 245)51,52, and 1-alkyl-2,3,6-trimethylbenzenes (ATMBs, m/z = 133/134)53,54 demonstrate significant analytical utility in elucidating source rock geochemical characteristics and oil-source correlations, owing to their relative abundance or persistence during secondary transformation processes, including thermal maturation.

TAS and TDS

TAS and TDS in the aromatic fraction are important aromatic biomarkers derived from steroidal compounds, primarily formed through dehydrogenation and aromatization during diagenesis and thermal evolution39,55,56. TDS are considered characteristic of modern marine dinoflagellates or microalgae39,57. Early detection results indicated that Cambrian-Lower Ordovician source rock samples contained relatively high levels of C26 20R + C27 20 S TAS, while C28 20 S TAS, C28 20R TAS, and TDS contents were lower. Ratios such as C26−20 S/C28−20 S, C27−20R/C28−20R TAS and TDSI were proposed to distinguish source rock types and oil-source correlations in the Tarim Paleozoic petroleum systems19,35.

By comparing the TAS characteristics of complete core samples of Є1y from different lithologies at the current stage, it was found that TAS distribution is similar to TDSI, exhibiting significant lithological differences. Calcareous mudstones show C26 20 S/C28 20 S TAS, C27 20R/C28 20R TAS, and (C26 20R + C27 20 S)/C28 20 S TAS values of < 0.3, < 0.35, and < 0.55, respectively, with 89% of samples having TDSI below 0.6 (Table 1). In contrast, 97% of siliceous rocks and shale samples display TAS ratios of > 0.33, > 0.4, and > 0.55, respectively, with TDSI generally exceeding 0.69 (Table 1; Fig. 4a, b, c, d). The presence of high TDSI values indicates that ancestors of dinoflagellates or microalgae experienced periodic flourishing in the Cambrian to Ordovician paleo-ocean of the Tarim Basin, particularly during the deposition of Є1y shales and siliceous rocks.

Table 1 Geochemical parameters of Yuertus formation in Tarim Basin.
Full size table

ATMBs

ATMBs primarily originate from anaerobic photosynthetic bacteria such as green sulfur bacteria and purple sulfur bacteria58,59 and are typical biomarkers indicating anoxic-sulfidic environments. Previous studies have detected ATMBs in crude oils and source rocks from the Tarim Basin with compound-specific carbon isotope values ranging from − 25‰ to −15‰7,24, showing significant13C enrichment, confirming their origin from photosynthesis dominated by green sulfur bacteria.

Fig. 4
Fig. 4The alternative text for this image may have been generated using AI.
Full size image

Distribution characteristics of parameters of stable biomarkers in representative well sections or sections in Tarim Basin(Data sources: Chen et al.35). (a) TDSI = triaromatic dinoflagellate steroids/(triaromatic dinoflagellate steroids + 3-methyl-24-ethyl-triaromatic steroids); (b) C26 20 S/C28 20 S TAS = C26 20 S triaromatic steroids/C28 20 S triaromatic steroids; (c) (C26R + C27S)/C28S TAS= (C26 20R + C27 20 S) triaromatic steroids/C28 20 S triaromatic steroids; (d) C27/C28 20R TAS = C27 triaromatic steroids/C28 20R triaromatic steroids; (e) ATMBs: 1-alkyl-2,3,6-trimethylbenzenes.

Consistent with Chen et al.35’s earlier findings, ATMBs were indeed detected in Cambrian source rocks. However, this series of compounds was only occasionally detected at low abundances in shales, while siliceous rocks showed no presence. Unlike previous analytical results, the current findings indicate that high abundances of ATMBs can be generally detected in calcareous shales, while shales typically exhibit lower abundances, and siliceous rocks show no detection (Fig. 3e). This distribution pattern reflects differences in the aquatic environment during the formation of Є1y source rocks of different lithologies.

Calcareous mudstones likely formed in strongly reducing, anoxic-sulfidic environments within the photic zone, favorable for green sulfur bacteria utilizing reduced sulfur (e.g., H2S) for photosynthesis and subsequent proliferation. The lower abundance of ATMBs in shales may indicate relatively lower H2S content during their formation, suggesting an environment trending toward micro-oxidation. The absence of ATMBs in siliceous rocks reflects poor light penetration in the water column during their deposition, unfavorable for the growth of photosynthetic green sulfur bacteria.

Characteristics of stable carbon isotopes

Carbon isotope composition has “heritability”, meaning that the carbon isotope characteristics of hydrocarbon generating organic matter are determined by its biological source, while the carbon isotope characteristics of crude oil are determined by the hydrocarbon generating organic matter in the source rock. Consequently, carbon isotope values are extensively utilized as oil-source correlation parameters. Traditional oil-oil and source-source correlations consider the Cambrian end-member to be characterized by heavy carbon isotopes, whereas the Ordovician end-member exhibits the opposite trend, with their generated oils displaying similar characteristics7,19.

Previous studies typically employed compound-specific carbon isotopes of n-alkanes to reveal mixed-source characteristics between Cambrian and Ordovician systems. The most 13C-enriched oil (such as oil from the Silurian (S) reservoir in well Tazhong-62) was selected as the Є-O1 source rock end-member, while the most12C-enriched oil (YM2 well oil) was chosen as the O2−3 source rock end-member. This temporal trend of isotopic dissipation from Є to O in the Tarim Basin has been widely accepted19,60.

However, this distribution pattern of n-alkane carbon isotopes may not represent the complete picture of the Cambrian system. Through systematic analysis, it is evident that Є1y is not limited to the heavy carbon isotope end-member found in previously studied Cambrian source rocks from the eastern Tarim region. Both calcareous mudstones of QT1 and siliceous rocks and shales of SARK exhibit δ13C values <−32‰, with no significant isotopic differences among source rocks of various lithologies. Nevertheless, n-alkane’ carbon isotopes from the eastern Tarim region (YD2 and TD2) are noticeably heavier (δ13Cn−alkane >−31‰) than those from the northern (QT1) and northwestern Tarim regions (SARK) (δ13Cn−alkane <−31‰) (Fig. 4).

This isotopic distribution pattern likely reflects regional variations. The eastern Tarim region exhibits significantly higher thermal maturity than the northern and central Tarim regions, potentially resulting in a distribution pattern in highly mature oils and source rocks that contradicts global carbon isotope composition trends. This hypothesis is supported by oil thermal simulation results suggesting that maturity differences may be the controlling factor5,7. Isotopic fractionation of n-alkanes during oil thermal simulation can reach 5‰, while different maturity levels (light oil, normal oil) of oils sharing the same source in the Shuntuo-guole area exhibit fractionation effects of up to 4‰61.

These findings indicate that carbon isotope applications for source-source and oil-source correlations in the Є1y of the Tarim Basin are constrained by the thermal evolution background of the study area. Furthermore, certain oils in the Tarim Basin have undergone thermochemical sulfate reduction (TSR) and biodegradation, which can significantly alter the carbon isotope values of lower carbon number n-alkanes (e.g., those in well ZS1C)5. For instance, n-alkanes below nC21 in ZS1C show significantly heavier isotope values8. Therefore, using n-alkane carbon isotopes as indicators for oil-source correlation requires consideration of a series of possible secondary alteration processes.

Fig. 5
Fig. 5The alternative text for this image may have been generated using AI.
Full size image

Carbon isotope distribution of n-alkanes in Cambrian source rocks in Tarim Basin (Data sources: Li et al.7; Li et al.19; Wang26).

Oil-source correlation

With the advancement of petroleum exploration and development in the Tarim Basin, along with the enrichment of drilling data and systematic sampling analyses, Є1y has revealed three distinct aromatic fraction characteristics of TAS, TDS, and ATMBs. Siliceous rocks and shales typified by YD2, XH1, and SARK represent previously reported Є source rock characteristics, including high TDSI, high C26−27 TAS, low C28 TAS, and absent or low-abundance ATMBs (Figs. 4 and 6a and b). Conversely, GC-MS results from calcareous mudstones from LT1, LT3, and QT1 exhibit geochemical characteristics of low TDSI, low C26−27 TAS, high C28 TAS, and high-abundance ATMBs (Figs. 4 and 6c). Consistent with classical understanding, O3l is characterized by low C26−27 TAS, high C28 TAS, and no ATMBs (Fig. 6d), while O2−3s features high C26−27 TAS, low C28 TAS, and no ATMBs (Fig. 6e). Evidently, the TAS distribution in Є1y calcareous shales resembles that of O3l and cannot be classified into either the Cambrian or Ordovician end-members according to the classical stratigraphic division scheme of the study area. Unlike n-alkane’ carbon isotopes and biomarker distributions, sulfur isotopes display significant stratigraphic differences without lithological variations, with Є1y sulfur isotopes consistently exceeding 10‰ (Fig. 8).

Due to the complexity of petroleum geological conditions in the platform-basin area (biodegradation, thermal alteration, thermochemical sulfate reduction reactions, etc.) and multiple source contributions (Cambrian end-member, Ordovician end-member, etc.), precise oil-source correlation relationships have not been fully elucidated, and optimal oil-source correlation parameters still require systematic selection. Comprehensive analysis of TAS, TDSI, ATMBs, n-alkane’ carbon isotopes, and sulfur isotopes in source rocks and crude oils regarding their resistance to secondary alteration indicates that biomarkers represented by TAS, TDSI, and ATMBs can be detected in severely biodegraded oils and TSR-altered oils, serving as primary oil-source identification criteria1. Sulfur isotopes in crude oils are secondarily reliable, being susceptible to intense TSR effects5,8. N-alkane’ carbon isotopes demonstrate the poorest response in oil-source correlation due to significant influences from thermal evolution, biodegradation, and TSR effects. Consequently, only the mean carbon isotope values of relatively stable nC21-nC23 n-alkanes are utilized as indicators for oil correlation7,21,61.

Through the application of C26 20S/C28 20S TAS, C27 20R/C28 20R TAS, (C26 20R + C27 20S)/C28 20S TAS, and TDSI cross plots, the relationships between mature oils, condensates, and existing source rocks in the eastern, northern, and central Tarim uplifts have been redefined (Fig. 7). The cross plots reveal that crude oils from most oil fields, particularly those from the northern Tarim uplift (Tahe, Halahatang, etc.), exhibit characteristics of low C26−27 TAS, high C28 TAS, and low TDSI (Fig. 7c, d). For instance, the YM2-8 crude oil, with mass-to-charge ratios of 231 and 133 or 134 (m/z = 231, 133/134), shows a TAS distribution pattern comparable to Middle-Upper Ordovician source rocks and Є1y calcareous shales, but contains high-abundance ATMBs similar to calcareous mudstones (Fig. 6c, f). These oils display negative n-alkane’ carbon isotopes (<−32‰), while total sulfur isotopes and compound-specific sulfur isotopes from representative oils show significant positive shifts (> 10‰), indicating weaker correlation with the Ordovician system (Figs. 5 and 8). Therefore, oils in this region are most likely sourced from Є1y calcareous shales.

Fig. 6
Fig. 6The alternative text for this image may have been generated using AI.
Full size image

Comparison of biomarker compounds of representative well sections or profiles in Tarim Basin between source rocks (Є1y, O3l, O2−3s) and Crude Oil.

In contrast, oils previously attributed to Cambrian-Lower Ordovician source rocks, such as those from TD2, feature significant C26 and C27 TAS. Through comparison of TAS homolog parameters, combined with source rock development, these can be further identified as potentially derived from Є1y shale-siliceous rock series (Fig. 7c). This conclusion is strongly supported by their relatively positive (>−30‰) n-alkane’ carbon isotopes and the negative (<−32‰) and positive (> 10‰) shifts in oil and compound-specific sulfur isotopes, respectively (Figs. 5 and 8).

As typical TSR alteration products, the anomalously enriched δ34S values in the central Tarim uplift zone indicate a close genetic relationship between dibenzothiophene (DBT) and TSR alteration, with crude oils exhibiting significant positive shifts in sulfur isotopes (ZS1C) (Fig. 8). TAS analysis reveals two types of source rock contributions to oils in this region: one type characterized by low C26−27 TAS and high C28 TAS (e.g., ZS1), displaying characteristics of Middle-Upper Ordovician and Є1y calcareous mudstones (Fig. 7a), while oils like ZS1C primarily exhibit high C26−27 TAS and low C28 TAS, characteristic of siliceous rocks and shales (Fig. 7a).

Fig. 7
Fig. 7The alternative text for this image may have been generated using AI.
Full size image

Discrimination diagram of typical biomarker parameters for oil source correlation in the Tarim Basin (Data sources Ordovician source rocks and crude oils14,16,35(Chen et al.35; Song et al.16; Xiao et al.14).

Fig. 8
Fig. 8The alternative text for this image may have been generated using AI.
Full size image

Sulfur isotopic fingerprinting for oil-source correlation in the Tarim Basin (Data sources: Li et al.7; Cai et al.8,9,10; Wang26).

Comprehensive oil-source correlation conclusions indicate that crude oils in the platform-basin area generally contain ATMBs and exhibit high C28S TAS characteristics. This differs from both traditional Ordovician source rocks (high C28S TAS, absence of ATMBs) and traditional Cambrian source rocks (low C28S TAS, abundant ATMBs), but shows excellent consistency with the calcareous shales revealed in this study. Additionally, another portion of the so-called Cambrian end-member oils primarily shows high similarity to shales and siliceous shales. This suggests that crude oils in the platform-basin area likely result from contributions of a single lithofacies of Є1y source rocks.

Conclusion

(1) The Є1y comprises three distinct lithofacies with varying petroleum potential. Calcareous mudstones show exceptional TOC values (up to 29.8%) and are concentrated in the northern, central, and transitional zones of the basin. These rocks contain predominantly Type II kerogen at mature to highly mature stages. Shales exhibit moderate TOC contents and are distributed across northwestern and eastern Tarim. Siliceous rocks display the lowest TOC values, are restricted to deep-water basins with hydrothermal activity, and have limited hydrocarbon generation potential.

(2) Biomarker analysis identifies distinct geochemical signatures among the three lithofacies. Calcareous mudstones are characterized by higher C28 TAS values, lower C26−27 TAS and TDS values, and significant ATMB enrichment. In contrast, shales and siliceous rocks display typical high C26−27 and low C28 TAS values with TDSI values > 0.6, though shales contain trace ATMBs while siliceous rocks lack these compounds entirely.

(3) Integrated analysis of aromatic biomarkers, n-alkane’ carbon isotopes (δ13C < −32‰), and sulfur isotopes demonstrates that the calcareous mudstones of Є1y likely serve as the primary source for deep to ultra-deep oils in the lower Paleozoic of the Tarim foreland basin, particularly in the northern and central uplift regions.