Prerpints.org logo
Preprint
Article

The Generation Time and Accumulations of Lower Paleozoic Petroleum in Sichuan and Tarim Basin Determined by Re–Os Isotopic Dating

This version is not peer-reviewed.

Submitted:

19 April 2023

Posted:

19 April 2023

You are already at the latest version

A peer-reviewed article of this preprint also exists.

Abstract
With the targets of petroleum exploration transferred to the deep and ancient strata, abundant oil and gas resources have been found in the Lower Paleozoic and older strata in central and western China. Due to complex evolutionary processes including multiple episodes of hydrocarbon accumulation and ubiquitously accompanied by secondary alterations, significant uncertainties were remained for the generation time and accumulation processes of these revealed petroleum. In this paper, relative pure Re and Os elements existing in the asphaltene fractions of Lower Cambrian solid bitumen collected from the Guangyuan area, western Sichuan Basin, SW China and another Middle–Lower Ordovician heavy oils in the Aiding area of the Tahe oilfield in the Tarim Basin, NW China were successfully obtained by the sample pre-treatments, and Re–Os isotopic analysis was subsequently carried out for the dating of these two petroleum. The Re–Os isotopic composition indicates a generation time of Guangyuan bitumen to locate between 572 Ma and 559 Ma, corresponding to the late Sinian period of Neoproterozoic era. By the means of Re–Os isochron ages, initial 187Os/188Os ratios, and carbon isotopic compositions, the Lower Cambrian bitumen is supposed to be originated from source rocks of the Doushantuo Formation in the Sinian strata and subsequently migrated into the reservoirs of Dengying Formation. These previously reserved petroleum had been transformed to present bitumen by the destruction of reservoirs caused by tectonic uplift. The Re–Os dating results of Middle–Lower Ordovician heavy oil of Tarim Basin supposed that it was formed between 450 Ma to 436 Ma, corresponding to the Late Ordovician–Early Silurian system, and the generated petroleum is likely to migrate into the Middle–Lower Ordovician karst reservoirs to form early oil reservoirs. With tectonic uplift, these oil reservoirs were degraded and reformed to be present heavy oil reservoirs.
Keywords: 
Subject: 
Environmental and Earth Sciences  -   Geochemistry and Petrology

1. Introduction

Abundant oil and gas resources that have been discovered in the Lower Paleozoic and older strata in the past two decades [1,2,3,4,5,6,7], deep and ancient strata become more important for the petroleum exploration in China. The thermal maturity is generally high–over in the Middle–Neoproterozoic and even the Lower Paleozoic [8, 9], which is unfavorable to the petroleum preservation leading to most of them are gas reservoirs maintained [5, 10]. However, a large number of oil seepages or large–scale bitumen veins have been found in some areas indicate that these ancient strata are likely to be potential sources of petroleum [11, 12]. The typical superimposed basins in western China, such as the Sichuan Basin and Tarim Basin, contain abundant ancient petroleum in the Lower Paleozoic and even the Precambrian [2, 3, 7], indicated by the bitumen veins of the Lower Cambrian in the northern section of Longmen Mountain thrust belt in Sichuan Basin [11] and the Middle–Lower Ordovician Tahe oil field [5] in the Tarim Basin. The source correlation and generation time of these petroleum to their potential sources have been widely carried out but uncertainties and controversies are still existed [11, 13–16].
Determining the geological time of hydrocarbon accumulation is relatively difficult to be achieved although it is valuable for the understanding of formation mechanisms of oil and gas reservoirs. In the early stage of reservoir development, hydrocarbon accumulation time is qualitatively inferred by the major stages of hydrocarbon generation and expulsion of the source rock, the formation time of traps, hydrocarbon–water interface tracing, and reservoir saturation pressure/dew–point pressure, these methods are involved in the indirect dating of accumulation [17].Since the 1990s, reservoir geochemistry, fluid inclusion analysis, and other inversion methods have been used to indirectly determine the oil and gas charging time with micro–scaled view[17,18,19,20]. However, these methods do not directly measure the durations of each stage of hydrocarbon reservoir formation, which can be measured by indirect, qualitative, or semi–quantitative methods to determine the relative time of hydrocarbon accumulation. The direct dating of hydrocarbon reservoirs (containing solid bitumen, crude oil, oil sand, etc.) is the inevitable trend of hydrocarbon accumulation geochronology from indirect and qualitative research to direct and quantitative research. With the development of laser micro–scaled purification systems and mass spectrometry detection, improved isotope chemical purification and separation methods, it is now possible for radioactive isotope dating to directly determine the age of hydrocarbon generation including isotopic dating methods of K(39Ar)–40Ar, Re–Os, U–Pb, Rb–Sr, and Sm–Nd. The use of radioisotope dating to determine the formation time of geological bodies and metal deposits has been shown to be effective [21,22,23]. However, the application of radioisotope dating in the geochronology of hydrocarbon accumulation is relatively recent, from the late 1980s, when scholars began to use isotope isochronal methods to determine hydrocarbon generation time [24, 25].
Lee et al. (1985) [24] first used the authigenic illite dating method to determine the formation time of the Rotliegendes sandstone gas reservoirs in the southern part of the North Sea, which revealed the accumulation time of the oil field in the North Sea [25, 26]. Parnell and Swainbank (1990) [23] firstly reported the accurate Pb–Pb age of uranium–bearing bitumen veins in a Wales copper mine and time of hydrocarbon migration into the vein beds has been determined. Mossman et al. (1993) [27] determined the U–Pb isotopic age of early Proterozoic shale in uranium ores in Elliot Lake, Canada. According to the theory and practice of isotopic chronology and geochemistry of mineral deposits, methods for separation and enrichment of samples and solid isotope analysis has been well established previously. The solid bitumen formation and petroleum migration ages in Tarim Basin, Junggar Basin, Southern China, Liaohe Oilfield, and other regions were determined by measuring the isotopic compositions of K–Ar, U–Pb, Pb–Pb, Rb–Sr, and Sm–Nd of authigenic illite, bitumen, crude oil [28,29,30,31]. Wang et al. (1997) [32] and Zhang et al. (2004) [28] first studied authigenic illite K–Ar dating in oil and gas fields in China and obtained good results for the hydrocarbon accumulation age in Tarim, Songliao, Turpan–Hami, and other basins [33]. The 40Ar–39Ar method was recently introduced to study hydrocarbon accumulation, effectively solving the influences of detrital illite on the dating results and strongly promoting the development of hydrocarbon accumulation chronology [34,35,36]. The petroleum and solid bitumen formation time and petroleum migration time in Tarim Basin, Junggar Basin, Southern China, Liaohe Oilfield and other areas were studied with radioisotope systems such as U–Pb, Rb–Sr, and Sm–Nd [37,38,39], which effectively constrained the absolute geological age of hydrocarbon accumulation [40].
Recently, Re–Os isotope dating methods are shown to be an effective method to access hydrocarbon accumulation age [41,42,43]. These methods can directly date hydrocarbon source rock, solid bitumen, crude oil, and oil sands and can acquire the oil and gas generation and migration age related to hydrocarbon accumulation. The Re–Os isotope dating method is based on the variation of the isotopic composition of osmium with time, caused by the β–decay of radioactive 187Re into 187Os. Re and Os have siderophilic, chalcophilic, and organophilic properties. Re and Os can be dissolved in water under oxidative conditions but are not easily dissolved under reductive conditions, often accumulate in sedimentary rocks that generate oil and gas on a large scale under anoxic–reduction conditions, and are also enriched in crude oil, solid bitumen, oil sands, and kerogen. The content of Re and Os in the organic matter system has an obviously positive correlation with the abundance of organic matter. Previous studies showed that Re and Os can also be existed in bitumen, kerogen, crude oil, and other organic matter in the form of organic complexes for a long time (T < 350 ℃) [42, 44] without the interference of radioactive elements in migration pathway rocks or reservoir rocks and without the influence of late modification; they can also maintain a good closed system [20]. This provides an important theoretical premise for the Re and Os isotopic dating method. The geological clock of the Re and Os isotope system in crude oil begins after the source rocks generate oil, and the isotopic composition of Re and Os in solid bitumen and crude oil reflect that of the source rocks when the petroleum is formed; therefore, the Re–Os isotopic dating system determines the hydrocarbon generation time [20, 41, 43]. At the same time, the initial ratios of 187Os/188Os in solid bitumen and crude oil can also effectively trace hydrocarbon source rocks. The aim of present study is to carry out Re–Os isotopic dating method to reveal the petroleum generation time of the Lower Cambrian Guangyuan bitumen of Sichuan Basin and Middle–Lower Ordovician oil of Tarim Basin.

2. Geological settings

2.1. Lower Cambrian bitumen in Guangyuan area, western Sichuan Basin

The bitumen veins and oil seepages in the northern part of Longmen Mountain belt in western Sichuan Basin are widely distributed, mainly in Nianziba and Kuangshanliang anticlinal structures in the Guangyuan area. The Nianziba nose–like structure and Kuangshanliang anticlinal structure are in the southeastern margin of the Longmen Mountain thrust belt in the western part of Sichuan Basin. According to statistics, the bitumen veins on Kuangshanliang and Nianziba structure are well developed (Figure 1); there are 137 veins with 37 developed in the Nianziba structure and 100 in the Kuangshanliang anticline which distributed in the Lower Paleozoic strata and are the oldest bitumen veins in the world [11]. Some bitumen veins are relatively larger, with a width of ~8 m. In the late 1960s, a 15.3 m–thick bitumen vein was discovered at a depth of 149 m to 164.3 m, and 30 L crude oil was produced from a depth of 333 m and 335.5 m in the Lower Cambrian in Tian 1 well in the Nianba anticline structure [11]. In the Nianziba structure, the bitumen veins are mainly distributed in the middle–lower strata of Changjianggou Formation in the Lower Cambrian at the south and north margin and middle parts of the structure. In the Kuangshanliang structure, the bitumen veins are mainly distributed in the upper–middle strata of the Changjianggou Formation in the Lower Cambrian over the whole structure, and controlled by the cracks and faults formed in the structure. The Changjianggou Formation is mainly composed of shales, sandy mudstones, and siltstones of shallow marine facies; the middle and upper parts are mainly sandstones and argillaceous siltstones where asphalt veins are produced (Figure 2). The wide distribution of bitumen veins and the discovery of oil in the Tian 1 well demonstrates the existence of Sinian–Cambrian reservoirs in these structures and indicates that there is a good prospect for finding Sinian and Cambrian reservoirs in the eastern margin of the Northern Longmen Mountain thrust belt.

2.2. Middle–Lower Ordovician heavy oil in Aiding area in Tahe oilfield, Tarim Basin

The Aiding area is located in the downward slope direction of the northwest Akekule uplift in the Tarim Basin (Figure 3); this area had better oil and gas production in early exploratory wells, where some wells produced small amount of heavy oil. The heavy oil was mainly distributed in the fracture–cave reservoir of the Yingshan Formation of the Middle–Lower Ordovician and Yijianfang Formation of Middle Ordovician.

3. Experimental

3.1. Samples

3.1.1. Lower Cambrian bitumen in Guangyuan area, Sichuan Basin

There are two types of solid bitumen in macroscopical characteristics in Guangyuan area. One is along the crack or fracture in the form of vein and is a more pure and soft black bitumen with obvious grease luster and generally developed in the area. The bitumen has a strong smell of oil after tapping and can be ignited, being mostly clastic with pores and joints (Figure 4 Type I). This type of solid bitumen is referred to as Type I in the paper. In this paper, 6 samples of type I solid bitumen were collected in Kuangshanliang structure. The other type of bitumen is similar to early diagenetic mudstone with a dim surface and rough structure (Figure 4 Type II), thin and uneven thickness, mostly massive, and mostly appearing in the upper section of the Changjianggou Formation. This type of solid bitumen is referred to as Type II in this paper. In this paper, 5 samples of type II solid bitumen were collected in Nianziba structure.
Bitumen reflectance (%Rb) of Type I solid bitumen distributed between 0.38% and 0.50% which is highly consistent to those previously introduced by Liu et al. (2003) [14]. According to the vitrinite reflectance (%Ro) conversion formula proposed by Jacob [45], %Ro values vary from 0.6% to 0.7% (Table 1) indicate a low mature degree for the bitumen. The %Rb values of the Type II solid bitumen distributed between 0.40% and 0.41%, with %Ro values being ~0.65% indicating a comparable mature degree to the type I bitumen. The low maturate degree of these two types of solid bitumen indicates that the solid bitumen was derived from the thick oil generated by the Sinian source rocks during the early–low mature stage.

3.1.2. Middle–Lower Ordovician oil in Aiding area in Tahe oilfield, Tarim Basin

The The oil density in Aiding area were between 1.01 and 1.06 g/cm3 indicating super heavy for these oils. The distribution of saturated hydrocarbon fractions of crude oil as a whole shows the dominant characteristics of light hydrocarbons. The odd–even dominance ratio and the carbon dominance index of maturity parameters were 1.32 and 1.26, respectively, indicating that crude oil is in the mature stage with an equivalent vitrinite reflectance of 0.8 to 1.0% [46]. In this paper, three crude oil samples were collected in Aiding area, namely, well Aiding 25(O2yj), Aiding 26(O1-2y) and Aiding 27(O1-2y).

3.2. Pretreatment of bitumen and oil samples

The Re–Os pretreatment of the geological sample was carried out in Sinopec Key Laboratory of Petroleum Accumulation Mechanisms. For both crude oil samples and solid bitumen samples, carbon isotope composition characteristics and biomarkers were used to determine whether they come from the same source rocks and are generated in the same period. If so, the following experimental procedures were followed.
For oil samples, around 10mg oil samples was diluted by mixture solvent of n–pentane in a volume ratio of 1:4 in a 100 mL glass bottle, stirred, and left for approximately 12 hours to ensure it was fully mixed. The mixed solution was transferred to a tube and centrifuged at 2000 rpm for 15 minutes to ensure the insoluble asphaltene and soluble components were completely separated. The separated asphaltene was dried at 60°C in an oven and then subjected to the following analysis. Solid bitumen samples were first milled into 4–5 mm particles in an agate bowl, and then 0.1–0.2 g asphaltene or solid bitumen was weighed into a Carius tube with Inverse Aqua Regia (2 mL 12 mol/L HC1 and 6 mL l6 mol/L HNO3) and 2 mL 30% H2O2 solution, with a certain amount of dilution agent added (30 ng185Re and 300 pg190Os). After the Carius tube was sealed, the mixed solution was dissolved by stage heating up to 120 °C and stabilized for 1 h, then heated to 160 °C and stabilized for 2 h, and finally increased to 200 °C and stabilized for 24 h. The above process reduced the probability of tube explosion during the sample dissolving process and made the sample dissolve better. The Carius tubes were frozen and cut open, and the Os of the solution was separated and purified by in situ direct distillation and micro–distillation. The remaining solution was added to 5 mol/L NaOH and Re was extracted with acetone. The acetone was evaporated at low temperature and nitric acid and hydrogen peroxide were added to break the organic phase for separation of Re.

3.3. Instrumental analysis

The purified Re and Os points in the Pt belt and were determined by negative thermal ion mass spectrometry (N–TIMS). For Re, 185ReO4 and 187ReO4 were simultaneously determined by static Faraday mode. For Os, 186OsO3, 187OsO3, 188OsO3, 190OsO3, 192OsO3 were determined by CDD multi-receiver mode, and 185ReO3 was determined to deduct the influence of 187ReO3 on 187OsO3. 185Re/187Re=0.59738 of common Re was used as the external standard for Re isotopic fractionation correction, and 192Os/188Os=3.0827 was used as the internal standard iterative method for Os isotopic fractionation correction [47].
The blank Re of the whole analysis process was 3 pg/g, the blank Os was 0.2 pg/g, and the blank 187Os was approximately 0.05 pg/g. The content of Re and Os in the background of the whole analysis process is negligible compared with that in the asphaltene. To verify the reliability of the pretreatment method, Re and Os contents of molybdenite (GBW04436) were determined using this pretreatment process, and this indicates that the final data are in accordance with the error requirement. Re and Os isotopic data obtained from mass spectrometry were processed by Isoplot Software and the age was calculated from the slope of the isochronal line; initial values, errors, and the weighted mean variance were also obtained.

4. Results and discussion

4.1. Petroleum generation time and origin of the Lower Cambrian bitumen in the Guangyuan area, western Sichuan Basin

4.1.1. Petroleum generation time of the solid bitumen

Some exploratory studies on the source of solid bitumen in Lower Cambrian have been done by the means of carbon isotope and biomarker analysis, the solid bitumen are supposed to be mainly originated from the Sinian-Lower Cambrian source rocks, especially most likely from black shale of Doushantuo Formation in Sinian[4, 11, 16, 34], whilst it can also be originated from the relatively low mature Permian or Lower Triassic source rocks[14, 48]. However, previous researchers have not yet carried out systematic study on the hydrocarbon-generating time of the solid bitumen veins, the Re-Os isotope dating method is used here to explore the hydrocarbon generation time and indirectly identify the source of the solid bitumen veins of the Lower Cambrian in Guangyuan area, western Sichuan Basin.
The Re–Os isotopic data of two types of solid bitumen in the Guangyuan area are shown in Table 2. The Type I solid bitumen in the Kuangshanliang structure have 187Re/188Os ratios of 232.6 – 355.2, and the 187Os/188Os ratios ranged from 2.82 – 4.04 (Figure 5 Type I). According to the isochron slope, the Re–Os age of the Type I solid bitumen was calculated to be 572 ± 12 Ma in the Kuangshanliang structure. The Type II solid bitumen distributed in the Nianziba structure have 187Re/188Os ratios of 384.4 – 534.3 and 187Os/188Os ratios of 4.15 – 5.52 (Figure 5 Type II), the Re–Os age of the Type II solid bitumen was calculated to be 559 ± 15 Ma in the Nianziba structure. These results comprehensively show that the hydrocarbon generation time of the Lower Cambrian solid bitumen veins in the Guanyuan area vary from 572 Ma to 559 Ma and may originate from the ancient source rocks and correspond to the Late Sinian.

4.1.2. Source rock correlation to the solid bitumen

Previous studies have proposed that the initial 187Os/188Os ratios of solid bitumen and crude oil can be used to effectively trace the source rocks [49, 50], providing a new method for oil–source correlation. Figure 5 shows that two different types of solid bitumen have similar initial 187Os/188Os ratios (0.57 ± 0.29 and 0.52 ± 0.12 for Type I and Type II, respectively) indicating that the two types of solid bitumen have similar source rocks.
The inheritance effect of stable carbon isotope composition provides the theoretical basis for the comparison between source rock, crude oil, and solid bitumen. In general, the carbon isotopic shift of crude oil caused by thermal maturation are 1‰ to 3‰ smaller than that of kerogen from the corresponding source rocks, while the carbon isotopic shift of solid bitumen is 2‰ to 3‰ greater than crude oil and the δ13C values of solid bitumen are 1‰ to 2‰ greater than that of kerogen [51, 52]. Therefore, the carbon isotopic compositions of solid bitumen and source rock can be used to correlate the hydrocarbon sources of the Lower Cambrian bitumen veins in Guangyuan area. The δ13C values of Type I solid bitumen are between −37.3‰ and −35.7‰, while the carbon isotopic values for Type II bitumen are between −38.2‰ and −36.8‰. The similarity of carbon isotopic values of the two types of solid bitumen indicates a common source shared. Based on the carbon isotopic compositions of the Lower Cambrian solid bitumen and potential source rocks, carbon isotopic compositions of Lower Cambrian solid bitumen are significantly different from that of the Lower Cambrian, upper Ordovician Wufeng Formation–lower Silurian Longmaxi Formation, which is consistent with the carbon isotopic compositions of kerogen from the Doushantuo Formation in the Sinian system (Figure 6). Therefore, it can be inferred that the solid bitumen is derived from the source rocks of the Doushantuo Formation.
Wang et al. (2005) [34] found that the distribution of Doushantuo Formation black shale in the Sinian was abundant and stable, the thicknesses are from 30 m to 40 m, and the TOC values varied from 0.2% to 7.0% (generally between 1.8% and 2.5%), and belonged to sapropelic and sapropelic–humic organic matter. Wang and Han (2011) [4] inferred that the thicknesses of the black shale in the Doushantuo Formation ranged from 25 m to 40 m and the TOC varied from 1.8% to 2.5%, belonging to sapropelic organic matter. The solid bitumen veins in the Guangyuan area may be derived from source rocks of the Doushantuo Formation of the Sinian, while the organic matter abundance of the Changjianggou Formation shale was low, making it not possible for it to be the source rock of solid bitumen veins [4]. Xie et al. (2003) [16] also proposed that the organic carbon content of the Sinian in the northern part of the Longmen Mountain was relatively high and found the solid bitumen in the Guangyuan area came from the black shale in the Sinian Doushantuo Formation by comparing steroid and terpenoid biomarkers. Tian (2009) [53] inferred that the solid bitumen of the Lower Cambrian in the Guangyuan area occurred as a high content of norhopanes indicating a source rock in the Doushantuo Formation. The black shales of the Doushantuo Formation are not exposed, and no drilling has revealed the strata in the area, but their high organic matter abundance and good organic matter type can generate a large amount of hydrocarbon based on previous results.
According to the Re–Os isochron ages, the initial 187Os/188Os ratios, carbon isotopes, and biomarkers, the solid bitumen of the Lower Cambrian in the Guangyuan area originated from high–quality source rocks of the Doushantuo Formation. The source rocks with good organic matter type were in low maturity evolution between 572 Ma and 559 Ma, and produced a certain amount of thick oil during the early hydrocarbon generation stage. The upper part of Doushantuo Formation is shale and a good caprock. With the development of the Dengying Formation reservoir and the increase of the burial depth of the stratum, the thick oil produced by the source rocks of the Doushantuo Formation entered into the Dengying Formation reservoir rocks, forming ancient thick oil reservoirs under pressure; this mechanism is supported by the widespread development of solid bitumen in the Dengying Formation dolomite rocks in the upper Sinian in Guangyuan–Wangcang–Micang Mountian area on the eastern side of Longmen Mountain belt [54].
In the western Sichuan Basin, tectonic uplift occurred during the Indosinian period, fractures and faults were developed, Dengying Formation palaeo–reservoir was uplifted, and thick oil migrated up to the Changjianggou Formation along fractures or faults. At this time, the Changjianggou Formation strata was raised to near the surface and the thick oil was modified through water washing, oxidation, and escape during the subsequent stage [55]. Therefore, the Lower Cambrian bitumen vein is the current oxidized bitumen formed by the upwards escape of the Dengying Formation crude oil after the destruction during the Indosinian period [56].

4.2. Generation time of heavy oil in the Middle–Lower Ordovician in the Aiding area, Tahe Oilfield

According to the characteristics of saturated hydrocarbon distribution and carbon isotopic compositions of heavy oil in the Aiding area, three heavy oil samples (AD25, AD26, and AD27) were selected for Re and Os purification, separation, and quantitative analysis, excluding the epigenetic alteration and mixed source. Based on the slope of the isochrone line obtaining by fitting the Re and Os data, the Re–Os ages of the Ordovician heavy oil in the Aiding area of Tahe Oilfield were determined to be approximately 450 Ma to 436 Ma (Figure 7); therefore, the corresponding generation time of the Ordovician heavy oil is from Late Ordovician to Early Silurian. The oil was formed earlier, which is consistent with the lower maturity of crude oil. Some scholars believe that the Ordovician oil reservoir in the Aiding area may have formed before the Silurian period and demonstrate that the oil filling time is from the Late Caledonian to the Early Hercynian period because of the reservoir fluid inclusion of the Aiding 4 well [46]. These results show that the oil generation time determined by Re–Os dating is correct.
In the Late Caledonian, the Cambrian source rocks in the Manjiaer depression and its slope area entered the peak of oil generation, and the Aiding area is in the high position of the structure with a favorable direction for oil and gas migration and accumulation. At the same time, as a result of the overall uplift of the first episode in the Middle Caledonian stage, the Yijianfang Formation strata of the Middle Ordovician was exposed, and consequent karstification developed widely in the Aiding, which provided sufficient space for oil and gas charging and formation of early oil and gas reservoirs. Since the Aiding area is located in the low part of the structure and the shielding effect of the Tahe axis, oil and gas accumulation conditions were poor during the period from the Early Hercynian to the Late Himalayan. In the early stage of the Hercynian period, the early oil reservoir was severely destroyed by water washing and oxidation with strong uplift and denudation, which formed the present heavy oil reservoir.

5. Conclusions

Based on the pre-treatment technology of the Re-Os isotope dating method of minerals, asphaltene extraction, dissolution, Re-Os purification, enrichment and separation of pre-treatment technology were established. The Re–Os isotopic dating and oil source rock of two types of solid bitumen veins were indicated in the Lower Cambrian in the Guangyuan area, western Sichuan. The hydrocarbon–generating time of the Lower Cambrian solid bitumen in the Guangyuan area varied from 572 Ma to 559 Ma, indicating the oil may have originated from the source rocks of the Doushantuo Formation. This source rocks were in low maturity and began to produce a certain amount of thick oil during 572 Ma and 559 Ma. Subsequently, thick oil entered into Dengying reservoir rocks to form a thick paleo–oil reservoir and formed the present bitumen vein through the late uplift.
Meantime, The Re–Os dating results of Middle–Lower Ordovician heavy oil in the Aiding area in Tarim Basin supposed that it was formed between 450 Ma to 436 Ma, corresponding to the Late Ordovician–Early Silurian system, and the generated petroleum is likely to migrate into the Middle–Lower Ordovician karst reservoirs to form early oil reservoirs. With tectonic uplift, these oil reservoirs were degraded and reformed to be present heavy oil reservoirs.

Author Contributions

Conceptualization, J.W.; methodology, J.W., L.B.M., C.T.; formal analysis, L.B.M., Q.W.D.; data processing, J.W.; writing–review and editing, J.W., W.H.L. All authors have read and agreed to the published version of the manuscript.

Funding

This research received funding from National Natural Science Foundation of China (Grant No. 42072154) and the Major Science and Technology Projects of Sinopec (Grant Nos. P17009–2).

Data Availability Statement

Data are available upon reasonable request from the corresponding author.

Conflicts of Interest

The authors declare no conflict of interest.

References

  1. Kang, Y.Z. Geological characteristics of the formation of the large Tahe oilfield in the Tarim basin and its prospects. Geol. China, 2003, 30, 315–319. [Google Scholar] [CrossRef]
  2. Liu, S.G.; Ma, Y.S.; Sun, W.; Cai, X.Y.; Liu, S.; Huang, W.M.; Xu, G.S.; Yong, Z.Q.; Wang, G.Z.; Wang, H. Studying on the differences of Sinian natural gas pools between Weiyuan gas field and Ziyang gas–brone area, Sichuan Basin. Acta Geol. Sin. 2008, 82, 328–337. [Google Scholar] [CrossRef]
  3. Jiao, F.Z. Significance and prospect of ultra–deep carbonate fault–karst reservoirs in Shunbei area, Tarim Basin. Oil Gas Geol. 2018, 39, 207–216. [Google Scholar] [CrossRef]
  4. Wang, T.G.; Han, K.Y. On Meso–Neoproterozoic primary petroleum resources. Acta Pet. Sin. 2011, 32, 1–7. [Google Scholar] [CrossRef]
  5. Qi, L.X. Exploration practice and prospects of giant carbonate field in the Lower Paleozoic of Tarim Basin. Oil Gas Geol. 2014, 35, 771–779. [Google Scholar] [CrossRef]
  6. Ma, Y.S.; Cai, X.Y.; Yun, L.; Li, Z.J.; Li, H.L.; Deng, S.; Zhao, P.R. Practice and theoretical and technical progress in exploration and development of Shunbei ultra-deep carbonate oil and gas field, Tarim Basin, NW China. Pet. Explor. Dev. 2022, 49, 1–17. [Google Scholar] [CrossRef]
  7. Li, J.; Yang, C.L.; Xie, W.R.; Rui, Y.R.; Wang, X.B.; Zhang, L.; Xie, Z.Y.; Guo, Z.Q. Differences of natural gas accumulation and play fairways in the marginal zone and interior of Sinian platform in Anyue gas field, Sichuan Basin. Oil Gas Geol. 2023, 44, 34–45. [Google Scholar] [CrossRef]
  8. Zhang, L.; Wei, G.Q.; Li, X.Z.; Wang, Z.C; Xiao, X.M. The thermal history of Sinian-Lower Paleozoic high-over mature source rock in Sichuan basin. Nat. Gas Geosci. 2007, 18, 4–9. [Google Scholar] [CrossRef]
  9. Wu, Y.Q.; Wang, Y.L.; Lei, T.Z. Ma S. P.; Wang Y.X.; Wen Q.B.; Xia Y.Q. Study on pristane isomerization index, a possible thermal maturity index for highly and overly mature source rocks of the Lower Paleozoic. J. Chin. Mass Spectrom. Soc. 2014, 35, 317–323. [Google Scholar] [CrossRef]
  10. Ma, X.H.; Yang, Y.; Wen, L.; Luo, B. Distribution and exploration direction of medium-large sized marine carbonate gas fields in Sichuan Basin, SW China. Pet. Explor. Dev. 2019, 46, 1–13. [Google Scholar] [CrossRef]
  11. Huang, D.F.; Wang, L.S. Geochemical characteristics of bituminous dike in Kuangshanliang area of the Northwestern Sichuan Basin and its significance. Acta Petrol. Sin. 2008, 29, 23–28. [Google Scholar] [CrossRef]
  12. Xiang, C.F.; Tang, L.J.; Li, R.F.; Pang, X.Q. Episodic fluid movements in superimposed basin: Combined evidence from outcrop and fluid inclusions of the Majiang ancient oil reservoir, Guizhou Province. Sci. China, Ser. D: Earth Sci. 2008, 51, 78–87. [Google Scholar] [CrossRef]
  13. Li, M.W.; Snowdon, L.; Lin, R.Z.; Wang, P.R.; Hou, D.J.; Zhang, L.Y.; Zhang, S.C.; Liang, D.G.; Xiao, Z.Y. Migrated hydrocarbons in outcrop samples: revised petroleum exploration directions in the Tarim basin. Org.Geochem. 2000, 31, 599–603. [Google Scholar] [CrossRef]
  14. Liu, G.X.; Wang, S.D.; Pan, W.L.; Lv, J.X. Characteristics of Tiannjingshan destroyed oil reservoir in Guangyuan Area, Sichuan. Mar. Orig. Pet. Geol. 2003, 8, 103–107. [Google Scholar] [CrossRef]
  15. Ma, A.L.; Zhang, S.C.; Zhang, D.J. ajiang, et al. Oil and source correlation in Lunnan and Tahe heavy oil fields. Oil Gas Geol. 2004, 25, 31–38. [Google Scholar] [CrossRef]
  16. Xie, B.H.; Wang, L.S.; Zhang, J.; Chen, S.J. Vertical distribution and geochemical behaviours of the hydrocarbon source rocks in the North section of Longmen Mountains. Nat. Gas Ind. 2003, 25, 21–23. [Google Scholar] [CrossRef]
  17. Zhao, J.Z. Geochronology of petroleum accumulation: new advances and the future trend. Adv. Earth Sci. 2002, 17, 378–383. [Google Scholar] [CrossRef]
  18. Saigal, G. , Bjorlykke K., Later S. The effects of oil emplacement on diagenetic process: Examples from the Fulmar reservoir sandstones, Central North Sea. AAPG Bull. 1992, 76, 1024–1033. [Google Scholar] [CrossRef]
  19. Thiery, R. , Pironon J., Walgenwitz F., Montel F. Individual characterization of petroleum fluid inclusions (composition and p-t trapping conditions) by microthermometry and confocal laser scanning microscopy: inferences from applied thermodynamics of oils. Mar. Pet. Geol. 2002, 19, 1365–1375. [Google Scholar] [CrossRef]
  20. Liu, W.H.; Wang, J.; Tao, C.; Hu, G.; Lu, L.F.; Wang, P. The geochronology of petroleum accumulation of China marine sequence. Nat. Gas Geosci. 2013, 24, 199–209. [Google Scholar] [CrossRef]
  21. Shepherd, T.J. Fluid inclusion Rb–Sr isochrons for dating mineral deposits. Nature, 1981, 290, 578–579. [Google Scholar] [CrossRef]
  22. Luck, J.M.; Allegre, C.J. The study of molybdenites through the 187Re–187Os chronometer. Earth Planet. Sci. Lett. 1982, 61, 291–296. [Google Scholar] [CrossRef]
  23. Parnell, J.; Swainbank, I. Pb–Pb dating of hydrocarbon migration into a bitumen–bearing ore deposit, North Wales. Geology, 1990, 18, 1028–1030. [Google Scholar] [CrossRef]
  24. Lee, M.C.; Aronson, J.L.; Savin, S.M. K/Ar dating of time of gas emplacement in Rotliegendes Sandstone, Netherlands. AAPG Bull. 1985, 69, 1381–1385. [Google Scholar] [CrossRef]
  25. Hamilton, P.J.; Kelly, S.; Fallick, A.E. K–Ar dating of illite in hydrocarbon reservoirs. Clay Miner. 1989, 24, 215–231. [Google Scholar] [CrossRef]
  26. Liewig, N.; Clauer, N.; Sommer, F. Rb–Sr and K–Ar dating of clay diagenesis in Jurassic sandstone oil reservoir, North Sea. AAPG Bull. 1987, 71, 1467–1474. [Google Scholar] [CrossRef]
  27. Mossman, D.J.; Nagy, B.; Davis, D.W. Hydrothermal alteration of organic matter in uranium ores, Elliot Lade, Canada: implication for selected organic–rich deposits. Geochim. Cosmochim. Acta, 1993, 57, 3251–3259. [Google Scholar] [CrossRef]
  28. Zhang, Y.Y.; Zwingmann, H.; Todd, A.; Liu, K.Y.; Luo, X.Q. K–Ar dating of authigenic illite and its applications to study of oil–gas charging histories of typical sandstone reservoirs, Tarim Basin, Northwest China. Earth Sci. Front. 2004, 11, 637–648. [Google Scholar] [CrossRef]
  29. Wang, L.Z.; Dai, T.M.; Peng, P.A. 40Ar/39Ar dating of diagenetic illites and its application in timing gas emplacement in gas reservoirs. Earth Science, 2005, 30, 78–82. [Google Scholar] [CrossRef]
  30. Chen, J.X.; Wang, B.; Guo, X.W.; Cao, Z.C.; Liu, Y.L.; Geng, F.; Zhang, X.Y.; Xu, H.; Zhao, J.X. Application of laser in-situ U-Pb dating of calcite to determination of the absolute time of hydrocarbon accumulation in polycyclic superimposed basins: a case study on Tahe oilfield Tarim basin. Oil Gas Geol. 2021, 42, 1365–1375. [Google Scholar] [CrossRef]
  31. Cong, F.Y.; Tian, J.Q.; Hao, F.; Andrew, R.C.; Kylander, C.; Pan, W.Q.; Zhang, B.S. Calcite U-Pb ages constrain petroleum migration pathways in tectonic complex basins. Geology, 2022, 50, 644–649. [Google Scholar] [CrossRef]
  32. Wang, F.Y.; He, P.; Zhang, S.C. Zhao M.J.; Lei J.J. The K–Ar isotope dating of authigenic illites and timing of hydrocarbon fluid emplacement in sandstone reservoirs. Geol. Rev. 1997, 43, 540–546. [Google Scholar] [CrossRef]
  33. Jiang, Z.X.; Pang, X.Q.; Huang, Z.L. A method for studying the oil and gas migration stages in superposed basin and its application. Petrol. Explor. Dev. 2000, 27, 22–25. [Google Scholar] [CrossRef]
  34. Wang, L.Z.; Han, K.Y.; Xie, B.H.; Zhang, J.; Du, M.; Wan, M.X.; Li, D. Reservoiring conditions of the oil and gas fields in the north section of Longmen Mountain nappe structural belts. Nat. Gas Ind. 2005, 27 (Supple. A), 1–5, DOI: CNKI: SUN: TRQG.0.2005-S1-000. [Google Scholar]
  35. Qiu, H.N.; Wu, H.Y.; Feng, Z.H.; Shi, H.S.; Yun, J.B.; Wang, Q.; Zhao, L.H. The puzzledom and feasibility in determining emplacement ages of oil/gas reservoirs by 40Ar/39Ar techniques. Geochimica, 2009, 38, 405–411. [Google Scholar] [CrossRef]
  36. Shi, H.S.; Zhu, J.Z.; Qiu, H.N.; Shu, Y.; Wu, J.Y.; Long, Z.L. Timing of hydrocarbon fluid emplacement in sandstone reservoirs in Neogene in Huizhou Sag, Southern China Sea, by authigenic illite 40Ar/39Ar laser stepwise heating. Earth Sci. Front. 2009, 16, 290–295. [Google Scholar] [CrossRef]
  37. Tu, X.L.; Zhu, B.Q.; Zhang, J.L.; Liu, Y.; Liu, J.Y.; Shi, Z.E. Pb–Sr–Nd isotope application in geochronology and origin of petroleum. Geochimica, 1997, 26, 57–67. [Google Scholar] [CrossRef]
  38. Zhang, J.L; Zhang, N.; Zhu, B.Q.; Tu, X.L.; Liu, J.Y.; Liu, Y.; Shi, E.Z.; Zhang, P.Z. Pb–Sr–Nd isotope geochemistry of the bitumen veins in Urho, Karamay. Sci. China, Ser. D: Earth Sci. 1997, 27, 325–330. [Google Scholar] [CrossRef]
  39. Zhu, B.Q.; Zhang, J.L.; Tu, X.L.; Chang, X.Y.; Fan, C.Y.; Liu, Y.; Liu, J.Y. Pb, Sr and Nd isotopic features in organic matter from China and their implications for petroleum generation and migration. Geochim. Cosmochim. Acta, 2001, 65, 2555–2570. [Google Scholar] [CrossRef]
  40. Wang, H.J.; Zhang, S.C.; Wang, X.M. How to achieve the precise dating of hydrocarbon accumulation. Nat. Gas Geosci. 2013, 24, 210–217. [Google Scholar] [CrossRef]
  41. Selby, D.; Creaser, R.A. Direct radiometric dating of hydrocarbon deposits using rhenium–osmium isotopes. Science, 2005, 308, 1293–1295. [Google Scholar] [CrossRef] [PubMed]
  42. Selby, D.; Creaser, R.A.; Fowler, M.G. Re–Os elemental and isotopic systematics in crude oils. Geochim. Cosmochim. Acta, 2007, 71, 378–386. [Google Scholar] [CrossRef]
  43. Rooney, A.D.; Selby, D.; Lewan, M.D.; Lillis, P.G.; Houzay, J.P. Evaluating Re–Os systematics in organic–rich sedimentary rocks in response to petroleum generation using hydrous pyrolysis experiments. Geochim. Cosmochim. Acta, 2012, 77, 275–291. [Google Scholar] [CrossRef]
  44. Yamashita, Y.; Takahashi, Y.; Haba, H.; Enomoto, S.; Shimizu, H. Composition of reductive accumulation of Re and Os in seawater–sediment system. Geochim. Cosmochim. Acta, 2007, 71, 3458–3475. [Google Scholar] [CrossRef]
  45. Jacob, H. Classification, structure, genesis and practical importance of natural solid oil bitumen (“migrabitumen”). Int. J. Coal Geol. 1989, 11, 65–79. [Google Scholar] [CrossRef]
  46. Ding, Y.; Peng, S.T.; Xia, D.L. The reservoir characteristics and hydrocarbon accumulation stages of Ordovician in Aiding area of Tahe Oilfield, Tarim Basin. Xinjiang Petrol. Geol. 2013, 34, 262–264, DOI: CNKI:SUN:XJSD.0.2013-03-007. [Google Scholar]
  47. Geboy, N.J.; Kaufman A., J.; Walker, R.J.; Misi, A.; Oliviera, T.F.; Miller K., E.; Azmy, K.; Kendall, B.; Poulton, S.W. Re-Os age constraints and new observations of Proterozoic glacial deposits in the Vazante Group, Brazil. Precambrian Res. 2013, 238, 199–213. [Google Scholar] [CrossRef]
  48. Liang, X.; Liu S., G.; Mo, Q.W.; Sun, W.; Deng, B.; Xia, G.D.; Xiong, L.P.; Li, Z.Q. The characteristics of marine hydrocarbon accumulation and its exploration prospects in the northern section of Western Sichuan Depression, China. J. Chengdu Univ. Technol. 2018, 45, 53–67. [Google Scholar]
  49. Creaser, R.A.; Sannigrahi, P.; Chacko, T.; Selby, D. Further evaluation of the Re–Os geochronometer in organic rich sedimentary rocks: A test of hydrocarbon maturation effects in the Exshaw Formation, Western Canada Sedimentary Basin. Geochim. Cosmochim. Acta, 2002, 66, 3441–3452. [Google Scholar] [CrossRef]
  50. Finlay, A.J.; Selby, D.; Osborne, M.J. Re–Os geochronology and fingerprinting of United Kingdom Atlantic margin oil: Temporal implications for regional petroleum systems. Geology, 2011, 39, 475–478. [Google Scholar] [CrossRef]
  51. Liu, W.H.; Wang, J.; Tenger; Zhang D. W.; Rao D.; Tao C. New knowledge of gas source rocks in the marine sequences of South China and relevant index system for tracing. Oil Gas Geol. 2010, 31, 819–824, DOI: CNKI: SUN: SYYT.0.2010-06-01. [Google Scholar]
  52. Wang, J.; Liu, W.H.; Tenger; Qin J. Z.; Zheng L.J. Thermal pyrolysis of hydrocarbon generation for marine hydrocarbon sources in marine sequence of South China and stable carbon isotopes of gas products. Nat. Gas Geosci. 2011, 22, 684–691. [Google Scholar] [CrossRef]
  53. Tian, X.B. Structural characteristics and petroleum prospect in the North section of Longmen Mountain. Beijing: National Library of China, 2009.
  54. Han, K.Y. Origin of the overthrust zone in Longmen Mountains and its oil and gas prospect. Nat. Gas Ind. 1984, 4, 1–9, DOI: CNKI: SUN: TRQG.0.1984-04-001. [Google Scholar]
  55. Wang, G.L.; Wang, T.G.; Han, K.Y.; Wang, L.S.; Shi, S.B. Organic geochemical characteristics and origin of solid bitumen and oil sands in northwestern Sichuan. Pet. Geol. Exp. 2014, 36, 731–735. [Google Scholar] [CrossRef]
  56. Dai, H.S.; Liu, S.G.; Sun, W.; Han, K.Y.; Luo, Z.L.; Xie, Z.L.; Huang, Y.Z. Study on characteristics of Sinian–Silurian bitumen outcrops in the Longmen–Micang shan area, Southwest China. J. Chengdu Univ. Technol. 2009, 36, 687–696. [Google Scholar] [CrossRef]
Preprints 71349 g001
Figure 1. Strata outcrop of Kuangshanliang and Nianziba structure in Guangyuan in the Western.
Figure 1. Strata outcrop of Kuangshanliang and Nianziba structure in Guangyuan in the Western.
Preprints 71349 g001
Preprints 71349 g002
Figure 2. Stratigraphic column in north part of Longmen Mountain, western Sichuan Basin.
Figure 2. Stratigraphic column in north part of Longmen Mountain, western Sichuan Basin.
Preprints 71349 g002
Preprints 71349 g003
Figure 3. The structural location of Aiding area in Tahe Oilfield.
Figure 3. The structural location of Aiding area in Tahe Oilfield.
Preprints 71349 g003
Preprints 71349 g004
Figure 4. Two types of solid bitumen veins in Guangyuan area in the Western Sichuan Basin.
Figure 4. Two types of solid bitumen veins in Guangyuan area in the Western Sichuan Basin.
Preprints 71349 g004
Preprints 71349 g005
Figure 5. The correlation of 187Re/188Os and 187Os/188Os of Lower Cambrian bitumen in Guangyuan area.
Figure 5. The correlation of 187Re/188Os and 187Os/188Os of Lower Cambrian bitumen in Guangyuan area.
Preprints 71349 g005
Preprints 71349 g006
Figure 6. The carbon isotope relation between solid bitumen in Guangyuan and kerogen of source rocks in Sichuan Basin.
Figure 6. The carbon isotope relation between solid bitumen in Guangyuan and kerogen of source rocks in Sichuan Basin.
Preprints 71349 g006
Preprints 71349 g007
Figure 7. The relationship between 187Re/188Os and 187Os/188Os of the Ordovician heavy oil in the Aiding area of Tahe Oilfield in Tarim Basin.
Figure 7. The relationship between 187Re/188Os and 187Os/188Os of the Ordovician heavy oil in the Aiding area of Tahe Oilfield in Tarim Basin.
Preprints 71349 g007
Table 1. Thermal maturity of solid bitumen in Guangyuan area in the Western Sichuan Basin.
Table 1. Thermal maturity of solid bitumen in Guangyuan area in the Western Sichuan Basin.
No. Sample No. Sample type Section Formation Rb(%) Ro(%)
1 GY–1 Type I bitumen Bitumen pit in Kuangshanliang structure ∈1ch 0.50 0.71
2 GY–3 Type I bitumen Bitumen pit in Kuangshanliang structure ∈1ch 0.48 0.70
3 GY–5 Type I bitumen Bitumen pit in Kuangshanliang structure ∈1ch 0.38 0.63
4 GY–6 Type I bitumen Bitumen pit in Kuangshanliang structure ∈1ch 0.45 0.68
5 JF–1 Type II bitumen Bitumen pit in Nianziba structure ∈1ch 0.40 0.65
6 JF–4 Type II bitumen Bitumen pit in Nianziba structure ∈1ch 0.41 0.65
Table 2. The Re–Os data of solid bitumen from Lower Cambrian in Guangyuan area in the Western Sichuan Basin.
Table 2. The Re–Os data of solid bitumen from Lower Cambrian in Guangyuan area in the Western Sichuan Basin.
Sample No. Structure ω (Re)
/ (ng.g−1)		 ω (Os)
/ (ng.g−1)		 ω (187Os)
/ (ng.g−1)		 187Re/188Os 187Os/188Os
Data 2σ Data 2σ Data 2σ Data 2σ Data 2σ
GY–1 Kuangshanliang 298.9 0.9 4.571 0.015 2.124 0.009 314.9 1.4 3.559 0.019
GY–2 Kuangshanliang 345.9 1 5.24 0.016 2.475 0.01 317.8 1.3 3.619 0.018
GY–3 Kuangshanliang 510 1.8 10.556 0.048 3.893 0.019 232.6 1.3 2.825 0.019
GY–4 Kuangshanliang 534.5 1.6 10.841 0.035 4.014 0.016 237.4 1 2.836 0.014
GY–5 Kuangshanliang 358.7 1.1 5.476 0.019 2.542 0.011 315.3 1.4 3.556 0.02
GY–6 Kuangshanliang 277.8 0.8 3.765 0.044 1.988 0.019 355.2 4.2 3.985 0.02
JF–1 Nianziba 592.9 1.8 5.349 0.017 3.858 0.015 533.6 2.3 5.525 0.028
JF–2 Nianziba 545.1 1.6 5.014 0.016 3.539 0.014 523.4 2.3 5.407 0.027
JF–3 Nianziba 477.7 1.4 4.467 0.033 3.114 0.023 514.9 4.1 5.34 0.056
JF–4 Nianziba 497.6 2.9 6.232 0.053 3.374 0.027 384.4 3.9 4.147 0.048
JF–5 Nianziba 539.62 2.36 6.68 0.024 3.622 0.015 388.9 2.2 4.154 0.023
Note: The uncertainty of Re and Os content in the data include the weighing error of the sample and diluent, the isotopic composition error, the calibration error of the diluent, the fractionation correction error of the mass spectrometry, and the isotope ratio error of the sample. The uncertainty levels are 2σ.
Disclaimer/Publisher’s Note: The statements, opinions and data contained in all publications are solely those of the individual author(s) and contributor(s) and not of MDPI and/or the editor(s). MDPI and/or the editor(s) disclaim responsibility for any injury to people or property resulting from any ideas, methods, instructions or products referred to in the content.
Copyright: This open access article is published under a Creative Commons CC BY 4.0 license, which permit the free download, distribution, and reuse, provided that the author and preprint are cited in any reuse.
Alerts
Prerpints.org logo

Preprints.org is a free preprint server supported by MDPI in Basel, Switzerland.

facebook logotwitter logolinkedin logo
MDPI Initiatives
Important Links
Subscribe

Disclaimer

Terms of Use

Privacy Policy

© 2025 MDPI (Basel, Switzerland) unless otherwise stated