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Article

Petrography and Organic Geochemistry Characterizations of Lower Paleozoic Organic-Rich Shale in the Northwestern Upper Yangtze Plate: Niutitang Formation and Longmaxi Formation, Dabashan Foreland Belt

by
Delu Li
1,*,
Rongxi Li
2,
Di Zhao
1 and
Feng Xu
3
1
College of Geology and Environment, Xi’an University of Science and Technology, Xi’an 710054, China
2
School of Earth Sciences and Resources, Chang’an University, Xi’an 710054, China
3
Shaanxi Center of Geological Survey, Xi’an 710068, China
*
Author to whom correspondence should be addressed.
Minerals 2018, 8(10), 439; https://doi.org/10.3390/min8100439
Submission received: 22 August 2018 / Revised: 21 September 2018 / Accepted: 25 September 2018 / Published: 9 October 2018
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Abstract

:
Measurements of total organic carbon, Rock-Eval pyrolysis, X-ray diffraction, scanning electron microscope, maceral examination, gas chromatography, and gas chromatography-mass spectrometry were conducted on the organic-rich shale of Lower Paleozoic Niutitang Formation and Longmaxi Formation in Dabashan foreland belt to discuss the organic matter characteristic, organic matter origin, redox condition, and salinity. The results indicate that the Niutiang Formation and Longmaxi Formation organic-rich shale are good and very good source rocks with Type I kerogen. Both of the shales have reached mature stage for generating gas. Biomarker analyses indicate that the organic matter origin of Niutitang Formation and Longmaxi Formation organic-rich shale are all derived from the lower bacteria and algae, and the organic matter are all suffered different biodegradation degrees. During Niutitang Formation and Longmaxi Formation period, the redox conditions are both anoxic with no stratification and the sedimentary water is normal marine water.

1. Introduction

China has vast shale gas exploration prospects. Up to 2012, the Chinese shale gas geological reserves have reached 134 × 1012 m3 with 25 × 1012 m3 recoverable resources [1]. However, due to the differences in exploration degree, the main proven area of shale gas exploration focused on south China, especially Sichuan Basin [2,3,4,5]. Massive studies indicate that the northern Sichuan Basin, Dabashan belt, develops numerous organic-rich shale formations [6,7,8,9,10]. The significant formations are mainly Niutitang Formation and Longmaxi Formation of Lower Paleozoic. The deposition thicknesses of these two formations are relatively large [11,12,13,14,15], and are affected by later tectonic movement, their burial depth is rather shallow, displaying good prospect of shale gas exploration [16,17]. Whereas, the current research of both formations have primarily focused on tectonic evolution history, element geochemistry, and organic matter enrichment [18,19,20,21,22,23,24]. Their petrography and organic geochemistry characterizations were poorly researched. In this contribution, four profiles were measured, and each of the two of them were Niutitang Formation and Longmaxi Formation. Based on total organic carbon (TOC), Rock-Eval pyrolysis, X-ray diffraction, scanning electron microscope, maceral examination, gas chromatography, and gas chromatography-mass spectrometry, their petrography and organic geochemistry characteristics will be discussed. The first aim of the study is to provide a comprehensive description of the geochemical characteristics of organic-rich shale from the Lower Paleozoic Niutitang Formation and Longmaxi Formation. The second aim is to characterize their organic matter origin, redox, and salinity environment.

2. Geological Setting

Located between Yangtze block and Qinling orogenic belt, Dabashan belt is divided into three secondary tectonic belts: Dabashan thrust nappe belt; Dabashan foreland belt; and Dabashan foreland depression [25] (Figure 1). Since the Sinian Period, the Dabashan foreland belt mainly underwent two periods (marine carbonate platform and foreland lacustrine basin) [26]. In Cambrian, Dabashan foreland belt were epeiric sea environment and developed neritic facies [6,27,28,29,30]. Till the late Silurian, affected by Caledonian movement, the Dabashan foreland belt uplifted comprehensively and stayed in a long-term rising state [27,28,29,30]. This orogeny movement lasts for 120 million years and leads to the absence of Upper Silurian-Carboniferous stratum [27,28,29,30]. Later, a massive transgression event happened in Late Carboniferous—Early Permian [27,28,29,30]. In Middle-Late Triassic, Indosinian movement caused the collision of the North China Plate and the South China Plate, resulting in the fold uplift in Dabashan foreland belt [27,28,29,30]. After the Late Cretaceous, the plate underwent extensional tectonics [31,32]. In the Lower Paleozoic, the Upper Yangtze Plate was a marine sedimentary facies and the Dabashan foreland belt developed into a deep water shelf environment [33]. The main organic-rich shale in the Lower Paleozoic develops in Niutitang Formation (Є1–2n) and Longmaxi Formation (O3S1l).
The Dabashan foreland belt develops the strata of Ediacaran to Jurassic. The Lower Paleozoic develops Cambrian, Ordovician, and Silurian stratum. Niutitang Formation is at the basal of Cambrian, and Longmaxi Formation is at the uppermost of Ordovician and the basal of Silurian. Both formations have the integrated contact relationship with the upper and the lower strata. The thickness of Niutitang Formation is almost 120 m with siliceous shale, carbonaceous shale, shale, and silty mudstone. While, Longmaxi Formation mainly develops siliceous shale (graptolite fossil), carbonaceous shale, and mudstone with almost 20 m thickness (Figure 2).

3. Sampling and Methods

Ten siliceous shale samples were obtained from Niutitang Formation and Longmaxi Formation in the Dabashan foreland belt. Each formation was measured with two sections. The sections’ positions, rock assemblages, and sampling locations are shown in Figure 2. All samples were collected in Kraft bags till they were used in experiments with minimal contamination and oxidation. Ten samples were measured for total organic carbon (TOC), Rock-Eval pyrolysis, X-ray diffraction (XRD), scanning electron microscope (SEM), and maceral examination. On four samples, gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS) were performed.
For TOC, analysis samples were crushed to powder under 200 meshes and the inorganic carbon was removed by diluted hydrochloric acid. After being combusted at 1200 °C in oxygen flow, organic carbon could be transformed to CO2 using a Multi EA2000 (Analytik Jena AG, Thuringia, Germany). The samples were analyzed in the LECO CS-400 analyzer (LECO Corporation, St. Joseph, MI, USA).
For Rock-Eval pyrolysis, the instrument was first warmed-up. Then pyrolysis analysis was conducted on powder samples using Rock-Eval equipment (LECO Corporation, Chicago, IL, USA). Samples of mass 30 mg were heated to 600 °C in a helium atmosphere and S1, S2, S3, S4, and Tmax were measured.
For mineral content analysis, XRD was performed with a D8 ADVANCE powder diffractometer with Cu Kα radiation from 5° to 60°, a step increment of 0.02°, and a counting time of two seconds per step. The minerals were identified from the diffractograms by referencing to the ICDD Powder Diffraction File. The analytical uncertainty is less than 1% precision.
SEM was conducted in Hitachi S-4800 (Hitachi High-Technologies Corporation, Tokyo, Japan). The electronic image resolution is 3.5 nm (30 KV), and the sensitivity is 0.1 Z with the 0.5–30 kV acceleration voltage. Amplification factor is in range of ×20–×500.
For maceral examination, oil immersion lenses were used with an optical microscope fitted with a microphotometer, to measure vitrinite reflectance. The samples were crushed and sieved through 20 mesh and dissolved using HCl and HF. The dry fractions were polished. The percentage compositions of macerals were counted in the eyepiece cross hairs with an area of (0.1 mm × 0.2 mm). Reflectance values were used to generate a histogram, and vitrinite reflectance could be confirmed by standard data under 20 °C and 35% humidity.
GC and GC–MS analyses were conducted on a SHIMADZU GC-2010 (SHIMADZU, Kyoto, Japan), equipped with a 30 m × 0.25 mm × 0.25 mm HP-5 fused silica capillary column, and an Agilent 6890GC/5975i MS (Agilent Technologies Inc., Santa Clara, CA, USA) with a 60 m × 0.25 mm × 0.25 mm HP-5MS fused silica capillary column, respectively. He is the carrier gas. The gas was boosted at a rate of 1.0 mL/min. The mass spectrometer was conducted in the electron ionization mode, and the data of the saturated fraction, terpane, and sterane were acquired.

4. Results

4.1. Mineralogical Characteristics

The results of XRD analysis are listed in Table 1. Quartz dominates in samples of both in Niutitang Formation and Longmaxi Formation, with an average concentration of 49.92 wt % (45.50–55.80 wt %) and 50.74 wt % (41.00–59.50 wt %). Illite takes the second largest portion with the average of 30.78 wt % (24.4–39.50 wt %) and 34.48 wt % (33.10–35.30 wt %). Besides, chlorite, plagioclase, K-feldspar, pyrite, dolomite, and calcite are all in a small portion. In Niutitang Formation, pyrite mould hole can be seen in the coexistence with organic matter (Figure 3A). Affected by oxidation, some pyrite obviously went through limonitization (Figure 3B). Some corrosion holes in feldspar can also be observed and are beneficial to hydrocarbon occurrence (Figure 3C). In Longmaxi Formation, pyrite framboids with the particle diameter of less than 1 μm exist mostly with organic matter (Figure 3D). Illite is mostly in the form of thin sheet (Figure 3E), and calcite has obvious fracture (Figure 3F).

4.2. Organic Petrography

The results of maceral examination are listed in Table 2. Sapropelinite takes the most portions in both Niutitang Formation and Longmaxi Formation. Besides, a small number of vitrinite-like and inertinite are also detected (Table 2). The amorphous can be perceived under microscope in both formations, and the solid bitumen is normally associated with pyrite (Figure 4).

4.3. TOC and Rock-Eval

The results of TOC and Rock-Eval are listed in Table 3. The TOC of siliceous shale samples of Niutitang Formation and Longmaxi Formation ranges from 1.15 wt % to 3.66 wt %, and from 3.14 wt % to 4.42 wt % (Table 3). Tmax of the samples of Niutitang Formation and Longmaxi Formation ranges in 486–511 °C and 517–580 °C, respectively. S2 of the samples of both formations is very low with the range of 0.03–0.08 mg/g and 0.03–0.06 mg/g (Table 3). High Tmax with low S2 is probably caused by relatively high maturity. Additionally, the potential yield (S1 + S2) of the samples also shows very low value with the range of 0.10–11 and 0.10–0.13 mg/g (Table 3). S3 and S4 of the samples of Niutitang Formation are in the range of 1.60–2.267 mg/g and 14.61–66.67 mg/g, while S3 and S4 of Longmaxi Formation are in the range of 1.35–1.78 mg/g and 13.52–31.39 mg/g (Table 3). Furthermore, HI of Niutitang Formation and Longmaxi Formation vary in the range of 0.9–5.29 mg/g TOC and 0.96–2.40 mg/g TOC (Table 3). OI of Niutitang Formation and Longmaxi Formation vary in the range 40.01–151.31 mg/g TOC and 42.95–132.81 mg/g TOC (Table 3).

4.4. N-Alkanes Characteristic and Isoprenoid

Saturated hydrocarbon chromatogram of Niutitang Formation and Longmaxi Formation both show almost bimodal type with relatively wide range of main peak (Figure 5). The peak assignments are listed in Appendix A. The main peak of shale samples of Niutitang Formation are C24 and C18. The carbon preference index (CPI) is 1.23 and 1.45 with the odd-even predominance of 1.06 and 1.03 (Table 4). The C21+/C22+ is 0.21 and 1.05 and (nC21 + nC22)/(nC28 + nC29) is 1.69 and 2.36 (Table 4). Pr/nC17 and Ph/nC18 of the samples are 0.59 and 0.57, and 0.74 and 0.75. The Pr/Ph is 0.58 and 0.76, respectively (Table 4). The main peak of shale samples of Longmaxi Formation are C17 and C18 (Table 4). The carbon preference index (CPI) is 1.24 and 1.26 with the odd-even predominance of 1.04 and 0.93 (Table 4). The C21+/C22+ is 0.73 and 1.00 and (nC21 + nC22)/(nC28 + nC29) is 2.57 and 1.58. Pr/nC17 and Ph/nC18 of the samples are 0.66 and 0.58, and 0.82 and 0.85 (Table 4). The Pr/Ph is 0.7 and 0.8 (Table 4). As can be seen, the samples of Niutitang Formation and Longmaxi Formation all show no odd-carbon number predominance (Figure 5). N-alkanes without odd-carbon number predominance normally reflect two organic matter origin types [34,35]. One stems from bacteria and other microbial wax, and the other comes from high plant wax remolded by bacteria [34,35]. In Cambrian and Silurian, the higher plants did not appear. Thus, high carbon number does not indicate the source of parent material of terrestrial higher plants. Considering the biodegradation of N-alkanes (especially under C21), the samples of Niutitang Formation and Longmaxi Formation all underwent different degrees of biodegradation.

4.5. Terpenes

The shale samples of Niutitang Formation and Longmaxi Formation are detected with high abundant of tricyclic terpane (Figure 6). Normally, tricyclic terpane stem from algae and bacteria, and its thermal stability is stronger than pentacyclic triterpane, especially for C19–C45 of tricyclic terpane [36,37,38]. As discussed before, the samples of Niutitang Formation and Longmaxi Formation suffered biodegradation. That is the reason why the samples contain high tricyclic terpane content.
The Ts/(Ts + Tm) of the samples of Niutitang Formation is 0.49,with 0.95 and 0.98 of Ts/Tm, respectively (Table 5). The C3122S/(22S + 22R) and C21/C23 tricyclic terpane are 0.59 and 0.57, and 0.71 and 0.79. The C26/C25 tricyclic terpane is 0.99 and 0.95 (Table 5). The Ts/(Ts + Tm) of the samples of Longmaxi Formation is 0.57 and 0.58, with 0.95 and 0.97 of Ts/Tm, respectively (Table 5). The C3122S/(22S + 22R) and C21/C23 tricyclic terpane are 0.59 and 0.57, and 0.96 and 0.87. The C26/C25tricyclic terpane is 0.92 and 0.98 (Table 5).
In saturated hydrocarbon fractions of the samples, hopane compounds are also detected with the most high abundance of C30 hopane.The βα-moretane/αβ-hopance of the samples of Niutitang Formation is 0.14 and 0.17, While the βα-moretane/αβ-hopance of Longmaxi Formation is 0.17 and 0.14 (Table 5). Moreover, low concentrations of gammacerane has been detected with the gammacerane/αβC30 hopane of 0.17 and 0.14 in Niutitang Formation and Longmaxi Formation, respectively (Table 5). Additional relevant parameters are shown in Table 5.

4.6. Steroid

According to the M/z217 mass fragmentograms of saturated hydrocarbon fractions, steroid is dominated by C27–C29 regular sterane (Figure 7). The content of pregnane and homopregnane are relatively high with some rearranged sterane abundance. The ααα20R regular sterane is dominated by C27, C28, and C29, showing the “V” distribution shape and high C27 abundance (Figure 7).
The (Pregnane + homopregnane)/C27 regular sterane of Niutitang Formation is 1.45 and 0.95, with 0.40 and 1.00 of regular sterane/hopance (Table 5). The (Pregnane + homopregnane)/C27 regular sterane of Longmaxi Formation is 1.06 and 0.90, with 0.47 and 0.37 of regular sterane/hopance (Table 5). The abundance of pregnane and homopregnane can reflect the degree of biodegradation, and the high content of them also indicates that the samples underwent strong biodegradation.

5. Discussion

5.1. Organic Matter Characteristic

5.1.1. Organic Matter Abundance

Directly associated with paleoproductivity and producing hydrocarbons content, organic matter abundance is one of the most important indexes of source rock evaluation [39]. The TOC analyses results indicate that the TOC of the shale samples of Niutitang Formation and Longmaxi Formation ranges in 1.15–3.66 wt % and 3.14–4.42 wt % (Table 3). Previous studies classified 0.4–0.6, 0.6–1.0, 1.0–2.0, and >2.0 as poor, fair, good and very good when applying this standard in Paleozoic source rocks [40,41]. Therefore, the shale from Niutitang Formation is regarded as the good type and Longmaxi Formation is the very good type. Furthermore, the diagrams of TOC-S1 + S2 and TOC-S2 can also illustrate organic matter abundance. In Figure 8A,B, the samples of Niutitang Formation mainly plot in good area while those of Longmaxi Formation are largely in very good areas, which shows the same recognition with TOC classification. It is noteworthy that, in Figure 8B, all the samples plot in gas prone area, probably suggesting that the source rocks of both formations have reached maturity.

5.1.2. Organic Matter Type

For Paleozoic source rocks, conventional methods such as Rock-Eval, don not work anymore [43]. Relatively accurate and efficient methods are maceral examination and organic carbon isotope [43]. In this study, maceral examination was adopted to ascertain organic matter type. From the results of maceral examination, the sapropelinite of the samples all show high abundance, while vitrinite and inertinite show less. No exinite is examined in all samples (Table 2). The Type Index (TI) can be calculated by using the equation: TI = [A × 100 + B × 50 + C × (−75) + D × (−100)]/100. The A, B, C, and D represent sapropelitic, exinite, vitrinite, and inertinite, respectively [39]. The TI ranges of >80, 80–40, 40–0 and <0 indicate Type I, Type II1, Type II2, and Type III [44]. After calculating the maceral concentration, the TI of the samples of both Niutitang Formation and Longmaxi Formation are over 80 (Table 2), implying that the organic matter types of the shale of both formations are Type I.

5.1.3. Organic Matter Maturity

The maturity of organic matter can reflect the degree of organic matter evolution. Its common indicators are Tmax, Ro, biomarkers, etc. [45,46,47]. Usually, Tmax with the range of <437, 437–450, >450 is classified as immaturity, low-maturity, and maturity [45,46,47]. As discussed in Section 4.3, the Tmax of Niutitang Formation and Longmaxi Formation vary in the range of 486–511 °C and 517–580 °C (Table 3). All the Tmax analyses show that the siliceous shale of Niutitang Formation and Longmaxi Formation has reached maturity. TS/(Tm + Ts) ratio increases with the rising maturity and stays around 0.5 in the late hydrocarbon generation peroid [42,48]. The ratios of both Niutitang Formation and Longmaxi Formation samples are all 0.49 (Table 5), futher implying that the shales of Niutitang Formation and Longmaxi Formation have entered maturity.
Besides, the diagrams of OEP-CPI and C29steraneββ/(ββ + αα) − αααC29sterane20S/(20S + 20R) also show that the samples of both Niutitang Formation and Longmaxi Formation have entered maturity and stay in the gas prone stage right now (Figure 9).

5.2. Sedimentary Paleo-Environment

5.2.1. Organic Matter Origin

Biomarkers can provide organic matter information comprehensively, expecially organic matter origin.(nC21 + nC22)/(nC28 + nC29) ratio is the most common proxy to identify hydrocarbon precursor types of marine and lacustrine. The ratio ranging in 0.6–1.2 and 1.5–2.0 menifest lacustrine and marine organic matter input, respectively [35]. As can be seen from the Table 4, the ratios of both Niutitang Formation and Longmaxi Formation are all over 1.5, illustrating that organic matter stems from marine envrionment.
The distribution pattern of tricyclic terpane C21, C23 and C24 can illustrate organic matter input, to some extent [46,48]. Researchers found that the “V” shape of C21, C23, and C24 in tricyclic terpane is usually associated with a salt-water environment and can reflect lower biological input of bacteria and algae [36]. As can be seen in Figure 6, all the samples show the obvious “V” shape of C21, C23, and C24, suggesting the organic matter origins of Niutitang Formation and Longmaxi Formation are both bacteria and algae.
Normally, C27 and C28 regular sterane origin from lower aquatic algae, while, C29 regular sterane could stem from both lower aquatic algae and higher terrestrial plants [49,50]. After the source rock studies from Ediacaran and Cambrian, Zhang et al. [51] found about 20–26% C28 regular sterane and reckoned that C28 regular sterane comes from diatoms. The C28 regular steranes of the shale samples from Niutitang Formation and Longmaxi Formation are all over 30% (Table 3), further suggesting that the organic materials are from lower aquatic organisms and algae.
Pregnane and homopregnane are all detected in the samples of both Niutitang Formation and Longmaxi Formation. Relatively high pregnane series abundance reflect not only salinization degree of sedimentary water and biodegradation intensity, but also their affiliation of algae source [52]. The (Pregnane + homopregnane)/C27 regular sterane of the samples of Niutitang Formation and Longmaxi Formation vary in small range with relatively low values (Table 3), showing that on the one hand, the salinity of the water is not high, on the other hand, the samples underwent biodegradation, resulting in relatively low sterane concentration.
The diagrams of C21/C23 tricyclic terpane-C26/C25 tricyclic terpane and Ts/Tm-Gammacerane/C30 hopane also indicates that the organic matter origin of the siliceous shale of Niutitang Formation and Longmaxi Formation is aquatic organic matter in normal marine water without stratification (Figure 10).

5.2.2. Redox Condition

The formation mechanism of pyrite under anoxic and oxidizing environment is different and the diameter of pyrite particle can be used to distinguish the sedimentary redox condition [53]. In anoxic condition, the diameter of pyrite particle is relatively small, varying in the range of 1–18 μm with the average value of 5 μm. While in the oxidizing condition, the diameter mostly becomes bigger than 20 μm [54]. In maceral examination, a great amount of pyrite develop with solid bitumen, and pyrite framboids and pyrite mould hole can be clearly seen in both Niutitang Formation and Longmaxi Formation. The diameters of them are mostly under 1 μm (Figure 3A,D), showing that the shale of both Longmaxi Formation and Niutitang Formation deposited under anoxic condition.
Pristane (Pr) and phytane (Ph) all stem from phytol, and their abundance proportions change with the variation of redox condition [39]. In anoxic and oxidizing condition, phytol would transform to phytane and pristine, respectively. Usually, when Pr/Ph ratio is over one, it means the source rocks deposits in oxidizing condition with relatively shallow water (e.g., marsh and wetland). Especially, when the ratio is over three, it reflects the terrestrial organic matter input under weak oxidation-oxidation conditions [55]. When Pr/Ph ratio is below one, it demonstrates that the source rocks form in anoxic with relatively deep water (e.g., lacustrine fresh water lakes), and the ratio <0.6 indicates the super salt environment [56,57]. The ratios of the samples of Niutitang Formation and Longmaxi Formation are all below 1.0 (Table 4), implying that they all deposited in anoxic environment. The Pr/Ph of the sample PMZ001 is 0.58, suggesting strong salt anoxic environment.
Pr/nC17 and Ph/nC18 can well reflect the degradation of organic matter. Generally, after being affected by strong degradation, the abundance of pristane and phytane of the sample would show higher than adjacent normal alkanes [39]. The Pr/nC17 and Ph/nC18 of the samples of Niutitang Formation and Longmaxi Formation are all relatively low with a small range (Table 4), manifesting the biodegradation is not strong.

5.2.3. Salinity

Gammacerane is a kind of C30 triterpane, reduced from tetrahymanal [58]. Generally, gammacerane is in trace abundance in crude oil and chloroform extract [59]. However, its high abundance has closed relationship with a strong salinity environment. Therefore, gammacerane index (Gammacerane/C30-hopance) can well interpret salinity. The gammacerane index of the Longmaxi samples in northern Guizhou range from 0.97–1.35. Compared with the Cambrian source rocks (gammacerane index > 0.8) from Tarim Basin, the Longmaxi samples in northern Guizhou showing high salinity environment [51]. The gammacerane index of the shale samples in this study all show relatively low value with a small range (all below 0.2) (Table 5), reflecting their salinities are normal marine water, which is in accordance with the diagram of Ts/Tm-Gammacerane/C30 hopane (Figure 10B). In addition, the gammacerane/0.5C31αβ(22R + 22S) ratio can also interpret salinity. The ratios of <0.3, 0.3–0.5, and >0.5 can be regarded as fresh water, brackish water, and salt water, respectively [39]. The gammacerane/0.5C31αβ(22R + 22S) of the shale samples of Niutitang Formation and Longmaxi Formation are all in the range of >0.5 (Table 5), further showing salt water environment.

6. Conclusions

The organic-rich shale of Niutitang Formation and Longmaxi Formation of Lower Paleozoic are the major source rocks in Dabashan foreland belt. The assessment results of maceral examination, TOC, and Rock-Eval show that the shale from Niutitang Formation and Longmaxi Formation are good and very good with Type I kerogen. Both of the shales have reached mature stage for generating gas. The organic matter input of organic-rich shale from Niutitang Formation and Longmaxi Formation are all derived from the lower bacteria and algae. The redox condition of them is all anoxic with no stratification and the sedimentary water is normal marine water.

Author Contributions

D.L. performed the experiments, analyzed the data and wrote the drafts of the paper, submitted the paper; R.L. conceived and designed the experiments, corrected the draft intensively; D.Z. and F.X. helped in the preparation of the paper and in checking the drafts of the paper.

Funding

This research was funded by the National Natural Science Foundation of China (No. 41173055; No. 41772118) and the Fundamental Research Funds for the Central Universities (No. 310827172101).

Conflicts of Interest

The authors declare no conflict of interest.

Appendix A

Table
Table A1. Peak assignments for M/z191(I) and M/z217(II) mass fragmentograms of saturated hydrocarbon fractions.
Table A1. Peak assignments for M/z191(I) and M/z217(II) mass fragmentograms of saturated hydrocarbon fractions.
Peak No.Compound Name
(I)
Ts18α(H),22,29,30-trisnorneophane
Tm17α(H),22,29,30-trisnorphane
2917α,21β(H)-nor-hopane
29M17β(H),21α(H)-hopane(moretane)
3017α,21β(H)-hopane
30M17β,21α(H)-Moretane
31R17α,21β(H)-homohopane(22R)
32S17α,21β(H)-homohopane(22S)
32R17α,21β(H)-homohopane(22R)
33S17α,21β(H)-homohopane(22S)
33R17α,21β(H)-homohopane(22R)
34S17α,21β(H)-homohopane(22S)
34R17α,21β(H)-homohopane(22R)
35S17α,21β(H)-homohopane(22S)
35R17α,21β(H)-homohopane(22R)
(II)
21a5α(H),14β(H)-pregnane
22b5α(H),14β(H)-homopregnane
27c13β(H),17α(H)-diacholestanes 20S
27d13β(H),17α(H)-diacholestanes 20R
27e5α(H),14α(H),17α(H)-cholestanes 20S
27f5α(H),14β(H),17β(H)-cholestanes 20R
27g5α(H),14β(H),17β(H)-cholestanes 20S
27h5α(H),14α(H),17α(H)-cholestanes 20R
29i24-ethyl-13β(H),17α(H)-diacholestanes 20R
29j24-ethyl-13β(H),17α(H)-diacholestanes 20S
28k24-methyl-5α(H),14α(H),17α(H)-cholestanes 20S
28l24-methyl-5α(H),14β(H),17β(H)-cholestanes 20R
28m24-methyl-5α(H),14β(H),17β(H)-cholestanes 20S
28n24-methyl-5α(H),14α(H),17α(H)-cholestanes 20R
29o24-ethyl-5α(H),14α(H),17α(H)-cholestanes 20S
29p24-ethyl-5α(H),14β(H),17β(H)-cholestanes 20R
29q24-ethyl-5α(H),14β(H),17β(H)-cholestanes 20S
29r24-ethyl-5α(H),14α(H),17α(H)-cholestanes 20R

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Minerals 08 00439 g001 550
Figure 1. Tectonic setting map of the Dabashan belt in the northwestern Upper Yangtze Plate (modified from [31]).
Figure 1. Tectonic setting map of the Dabashan belt in the northwestern Upper Yangtze Plate (modified from [31]).
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Minerals 08 00439 g002 550
Figure 2. The sampling locations of Niutitang Formation and Longmaxi Formation.
Figure 2. The sampling locations of Niutitang Formation and Longmaxi Formation.
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Figure 3. SEM of minerals characteristics. (A) PMZ001; (B) PMH008; (C) PMH024; (D) PMD010; (E) PML003; and (F) PML007. (A–C) Niutitang Formation; and (D–F) Longmaxi Formation.
Figure 3. SEM of minerals characteristics. (A) PMZ001; (B) PMH008; (C) PMH024; (D) PMD010; (E) PML003; and (F) PML007. (A–C) Niutitang Formation; and (D–F) Longmaxi Formation.
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Figure 4. Photos of maceral examination. (A) PMZ001; (B) PMH008; (C) PMD005; and (D) PML003. (A,B) Niutitang Formation; and (C,D) Longmaxi Formation.
Figure 4. Photos of maceral examination. (A) PMZ001; (B) PMH008; (C) PMD005; and (D) PML003. (A,B) Niutitang Formation; and (C,D) Longmaxi Formation.
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Figure 5. M/z85 mass fragment grams of saturated hydrocarbon fractions.
Figure 5. M/z85 mass fragment grams of saturated hydrocarbon fractions.
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Figure 6. M/z191 mass fragment grams of saturated hydrocarbon fractions.
Figure 6. M/z191 mass fragment grams of saturated hydrocarbon fractions.
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Figure 7. M/z217 mass fragment grams of saturated hydrocarbon fractions.
Figure 7. M/z217 mass fragment grams of saturated hydrocarbon fractions.
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Figure 8. Cross diagrams of TOC versus S1 + S2 (A), and S2 (B). (A,B) Base map is from Gao et al. [42].
Figure 8. Cross diagrams of TOC versus S1 + S2 (A), and S2 (B). (A,B) Base map is from Gao et al. [42].
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Figure 9. Cross diagrams of OEP versus CPI (A), and the C29steraneββ/(ββ + αα) versus αααC29sterane 20S/(20S + 20R) (B). (A,B) Base map is from Li et al. [31].
Figure 9. Cross diagrams of OEP versus CPI (A), and the C29steraneββ/(ββ + αα) versus αααC29sterane 20S/(20S + 20R) (B). (A,B) Base map is from Li et al. [31].
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Figure 10. Cross diagrams of C21/C23 tricyclic terpane versus C26/C25 tricyclic terpane (A), and the Ts/Tm versus C30hopane (B). (A,B) Base map is from Gao et al. [42].
Figure 10. Cross diagrams of C21/C23 tricyclic terpane versus C26/C25 tricyclic terpane (A), and the Ts/Tm versus C30hopane (B). (A,B) Base map is from Gao et al. [42].
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Table
Table 1. The mineral content of the shale samples.
Table 1. The mineral content of the shale samples.
Minerals (wt %)Niutitang FormationLongmaxi Formation
PMZ001PMZ009PMH003PMH008PMH024Avg.PMD005PMD010PML003PML007PML010Avg.
Quartz45.5053.8055.8047.7046.8049.9241.0046.3059.5058.9048.0050.74
Illite24.4032.4021.9039.5035.7030.7835.3034.9034.4033.1034.7034.48
Chlorite0.000.300.000.000.000.066.805.100.000.003.703.12
Plagioclase25.4013.5019.8012.8017.5017.8011.905.806.108.0013.609.08
K-feldspar4.700.002.500.000.001.440.000.000.000.000.000.00
Pyrite0.000.000.000.000.000.005.002.500.000.000.001.50
Dolomite0.000.000.000.000.000.000.005.100.000.000.001.02
Calcite0.000.000.000.000.000.000.000.300.000.000.000.06
Table
Table 2. The microscopic constituents of organic matter of the shale samples.
Table 2. The microscopic constituents of organic matter of the shale samples.
FormationSample IDSapropelinite (%)Exinite (%)Vitrinite–Like (%)Inertinite (%)TI
Niutitang FormationPMZ00198.0001.410.5996.35
PMH00396.2502.810.9493.20
PMH00896.0002.401.6092.60
Longmaxi FormationPMD00596.4801.871.6593.42
PMD01097.1800.802.0194.57
PML00392.9502.544.5186.53
Table
Table 3. Results of TOC and pyrolysis data of samples from Niutitang Formation and Longmaxi Formation.
Table 3. Results of TOC and pyrolysis data of samples from Niutitang Formation and Longmaxi Formation.
FormationsSamples IDTOC (wt %)Tmax (°C)S2 (mg/g)S1 + S2 (mg/g)S3 (mg/g)S4 (mg/g)HI (mg/g TOC)OI (mg/g TOC)
Niutitang FormationPMZ0011.624930.08 0.111.9615.065.29129.5
PMZ0091.785110.05 0.102.2514.823.36151.31
PMH0033.665110.03 0.102.2128.42.1177.64
PMH0081.745100.08 0.111.614.613.41109.08
PMH0241.154860.03 0.102.6766.670.940.01
Longmaxi FormationPMD0053.145170.06 0.101.3828.791.0447.88
PMD0103.215780.05 0.111.3531.391.2742.95
PML0034.425410.06 0.101.813.522.21132.81
PML0073.975770.03 0.131.6633.22.449.89
PML0103.455800.04 0.101.7831.330.9656.75
TOC: Total organic carbon. Tmax: maximum peak temperature of Rock-Eval pyrolysis S2. S1: Volatile hydrocarbon content. S2: Remaining HC generative potential. S1 + S2: Potential of generating hydrocarbon. S3: CO2 content. S4: 10 × residual organic carbon. HI: Hydrogen Index = S2 × 100/TOC. OI: Oxygen Index = S3 × 100/TOC.
Table
Table 4. Parameters of n-alkanes and is oprenoid.
Table 4. Parameters of n-alkanes and is oprenoid.
FormationsSamples IDCPIOEPC21+/C22+(nC21 + nC22)/(nC28 + nC29)Pr/nC17Ph/nC18Pr/PhPeak Number
Niutitang FormationPMZ0011.231.060.211.690.590.740.58C24
PMH0031.451.031.052.360.570.750.76C18
Longmaxi FormationPML0031.241.040.732.570.660.820.7C18
PMD0101.260.931.001.580.580.850.8C17
Note: OEP: odd-even predominance = (C23 + 6 × C25 + C27)/(4 × C24 + 4 × C26); 8: CPI: carbon preference index = [(C25 + C27 + C29 + C31 + C33)/(C24 + C26 + C28 + C30 + C32) + (C25 + C27 + C29 + C31 + C33)/(C26 + C28 + C30 + C32 + C34)]/2.
Table
Table 5. Parameters of terpanes and steranes.
Table 5. Parameters of terpanes and steranes.
FormationsSamples ID1234567891011121314151617
C27C28C29
Niutitang FormationPMZ0010.490.950.590.590.510.440.140.170.247.330.170.77 0.710.991.450.4035.3330.8233.86
PMH0030.490.980.570.580.440.430.170.170.275.870.170.71 0.790.950.951.0031.5231.7336.74
Longmaxi FormationPML0030.490.950.570.600.440.460.170.140.285.780.140.61 0.960.921.060.4731.4731.7636.77
PMD0100.490.970.580.590.400.490.140.140.287.110.140.61 0.870.980.900.3728.9832.8738.14
Note: 1: Ts/(Ts + Tm); 2: Ts/Tm; 3: C3122S/(22S + 22R); 4: C32αβ22S/(22S + 22R); 5: C29ααα20S/(20S + 20R); 6: C29αββ/(ααα + αββ); 7: βα-moretane/αβ-hopance; 8: Gammacerane/αβ-hopance; 9: 4-Methyl sterane/Regular sterane; 10: C30αβ-hopance/C29Sterane; 11: Gammacerane/C30-hopance; 12: Gammacerane/0.5C31αβ(22R + 22S); 13: C21/C23tricyclic terpane; 14: C26/C25tricyclic terpane; 15: (Pregnane + homopregnane)/C27 regular sterane; 16: Regular sterane/Hopance; 17: Regular steranes.

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Li, D.; Li, R.; Zhao, D.; Xu, F. Petrography and Organic Geochemistry Characterizations of Lower Paleozoic Organic-Rich Shale in the Northwestern Upper Yangtze Plate: Niutitang Formation and Longmaxi Formation, Dabashan Foreland Belt. Minerals 2018, 8, 439. https://doi.org/10.3390/min8100439

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Li D, Li R, Zhao D, Xu F. Petrography and Organic Geochemistry Characterizations of Lower Paleozoic Organic-Rich Shale in the Northwestern Upper Yangtze Plate: Niutitang Formation and Longmaxi Formation, Dabashan Foreland Belt. Minerals. 2018; 8(10):439. https://doi.org/10.3390/min8100439

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Li, Delu, Rongxi Li, Di Zhao, and Feng Xu. 2018. "Petrography and Organic Geochemistry Characterizations of Lower Paleozoic Organic-Rich Shale in the Northwestern Upper Yangtze Plate: Niutitang Formation and Longmaxi Formation, Dabashan Foreland Belt" Minerals 8, no. 10: 439. https://doi.org/10.3390/min8100439

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