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Article

Geochemical Features of Lacustrine Shales in the Upper Cretaceous Qingshankou Formation of Changling Sag, Songliao Basin, Northeast China

by
Zhongcheng Li
1,2,3,
Zhidong Bao
2,3,
Zhaosheng Wei
1,
Lei Li
2,3 and
Hailong Wang
1,*
1
Research Institute of Exploration and Development, PetroChina Jilin Oilfield Company, Songyuan 138000, China
2
College of Geosciences, China University of Petroleum-Beijng, Beijing 102249, China
3
State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum-Beijng, Beijing 102249, China
*
Author to whom correspondence should be addressed.
Energies 2022, 15(19), 6983; https://doi.org/10.3390/en15196983
Submission received: 23 June 2022 / Revised: 23 August 2022 / Accepted: 28 August 2022 / Published: 23 September 2022
(This article belongs to the Special Issue Sedimentary Organic Matter in Shale Oil/Gas Systems)
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Abstract

:
The organic-rich shale of the Upper Cretaceous Qingshankou Formation is an important hydrocarbon source rock in Northeast China. In this study, taking the lacustrine shale in the Qingshankou Formation as an example, geochemical analysis, including total organic carbon (TOC), Rock-Eval pyrolysis, maceral compositions, X-ray diffraction (XRD), and biomarker analyses, were carried out on twenty-four shale samples to evaluate the geochemistry and environmental features of this shales. The Qingshankou lacustrine shales contains mainly Type I/II1 organic matter and is oil prone, with a good to excellent source rock. Vitrinite reflectance and Rock-Eval pyrolysis parameters show that the Qingshankou lacustrine shales is mainly in the mature stage and within the oil window. Biomarker composition of the shales provide evidence that the Qingshankou lacustrine shales was formed in a reductive sedimentary environment with relatively high salinity water. The organic matter came from a mixture of plankton, bacterial and land plants.

1. Introduction

With the constant increase in energy demand and exhaustion of conventional oil and gas resources, unconventional energy resources have drawn wide attention. Due to very low production, shale oil was not taken seriously in the past. Nevertheless, following the successful commercial development of shale gas in North America, shale oil exploration developed rapidly worldwide [1].
Shale oil refers to oil accumulating in shale layers or interlayers (sandstone, dolomite, limestone, and tuff) associated with shale [2]. It forms a type of self-sourcing reservoir and exists in an adsorption state or in a free state, existing in micro- and nano-scaled pores and fractures [3]. This leads to common issues such as low production and fast decline during the development of shale oil, making it difficult to develop and be economically viable on a large scale. Natural or artificial fracture is a main factor controlling the high production of shale oil.
Shale oil resources are widespread throughout China, such as the Middle Permian Lucaogou Formation in Santanghu Basin in northwest China, the Paleogene Shahejie Formation in various depressions in the Bohai Bay Basin, the Upper Cretaceous Qingshankou and Nenjiang formations in Songliao Basin in northeast China, the Eocene Hetaoyuan Formation in Biyang Depression Nanxiang Basin in the middle eastern part of China, and the Cenozoic Qianjiang Formation of the Jianghan Basin [2,4,5,6,7,8].
As a source rock, organic-rich shale plays a vital role in the process of hydrocarbon generation [9,10]. Hydrocarbon generation potentials are affected by the quality of source rock to a large extent. Sedimentary environment and preservation conditions control the abundance, type, and thermal evolution of organic matter. Organic matter maceral, vitrinite reflectance, total organic matter (TOC), rock pyrolysis parameters, element contents, and molecular geochemical parameters are often used to evaluate the hydrocarbon generation potential of shale.
Different from marine shale, lacustrine shale layers are often strongly heterogeneous, as continental faulted lake basins often have gone through complex tectonic evolution during geologic history and have large scale fault systems [11,12]. To evaluate oil and gas resource potentials accurately, it is necessary to examine the geochemical and sedimentary environment features of the region of interest in detail.
Numerous studies have focused on the organic–inorganic characteristics, origin, and accumulation of organic matter within Cretaceous black shales [13,14,15,16]. However, these studies are mainly concentrated in the northern region of the basin, lacking systematic research in the southern region of the basin. Therefore, based on a series of geochemical and biomarker analysis experiments, the goal of this study was to present a more comprehensive understanding of the chemistry of the region in addition to sedimentary environment information in order to provide useful information for the prediction of shale oil’s “sweet spot”.

2. Geologic Setting

Located in northeastern China, Songliao Basin is a continental sedimentary basin formed in the Mesozoic–Cenozoic era. Structurally, it consists of six first order structural units: central depression, west slope, southwest uplift, southeast uplift, northeast uplift, and north subduction zone (Figure 1).
The tectonic evolution of the basin can be divided into three stages: fault depression, depression, and structural inversion. The depositional period of the Lower Cretaceous Huoshiling, Shahezi, and Yingcheng formations was the fault depression stage of the lake basin. The depositional period of the Lower Cretaceous Denglouku Formation is the transition stage between fault depression and depression. The depositional period of the Lower Cretaceous Quantou Formation and Upper Cretaceous Qingshankou, Yaojia, Nengjiang, Sifangtai, and Mingshui formations is the depression stage of the lake basin. In the initial depositional stage of the Upper Cretaceous Qingshankou Formation, the climate was warm and humid, the lake water was deep, and the lake basin expanded rapidly. Consequently, a succession of black/gray mudstone interbedded with gray siltstone and ostracoda-bearing limestone developed. The Qingshankou Formation is divided into three members, Qing 1, Qing 2, and Qing 3, from the bottom up. The depositional period of Qing 1 was the largest lake transgression period, when a set of deep-lake black shale with Type I and II 1 organic matter and good hydrocarbon generation potential deposited [17]. The study area, Jilin oilfield, is located in the southern part of Songliao Basin next to the Daqing oilfield to the north, where the target layer series, Cretaceous Qingshankou Formation, has massive lacustrine shale development.

3. Samples and Experiments Methods

3.1. Samples

A total of twenty-four shale samples for experiments were taken from the Upper Cretaceous Qingshankou Formation in Changling sag, southern Songliao Basin (Figure 1).

3.2. Experimental Methods

The device for the TOC test was a C-744 carbon sulfur analyzer, and the experiment process follows GB/T 19145-2003 “Test of TOC in sedimentary rocks”. Before the experiment, the samples were ground into a hundred mesh in agate mortar, and diluted hydrochloric acid was then added to react with the sample to remove inorganic carbonates. The remaining sample was washed with water and dried, and then calcined to obtain CO2 and SO2; finally, the TOC and total sulfur content were tested using a thermal conductivity detector. The device for the pyrolysis experiment was a French Rock-Eval-6plus source rock analyzer, and the experimental process was followed by GB/T 18602-2012 “Rock Pyrolysis Analysis”. The XRD experimental instrument was a D8 discovery X-ray diffractometer, and the experiment process was followed by SY/T 5163-2010. The saturated hydrocarbon chromatography-mass spectrometry experiment adopted extraction under room temperature methods. The shale sample was soaked in dichloromethane solution and then set aside for 12 h, after which the extraction fluid was analyzed by an HP7890 chromatograph. The experiment process abided by SY/T 5779-2008: “Analytical method of hydrocarbons in petroleum and sediment by chromatography”.

4. Results and Discussion

4.1. Mineral Compositions and Lithofacies Classification

The mineral composition determined by XRD of lacustrine shale in Qingshankou Formation comprised mainly quartz, feldspar, and clay (Figure 2, Table 1). The content of quartz was between 23.6 and 41.0%, with an average of 31.9%. The feldspar content was between 12.4 and 30.2%, with an average of 19.3%. The clay mineral content was the highest, ranging from 23.3 to 42.4%, with an average of 35.8%. Clay minerals were mainly illite, with a relative average content of 76.0%, followed by a mixed layer of illite–smectite (with a relative average content of 16.3%) and a small amount of chlorite (with a relative average content of 7.7%). The average content of other minerals was less than 10%. According to the average content, they are calcite (5.8%), pyrite (3.9%), iron dolomite (2.5%), and siderite (0.8%).
Based on the ternary graph of the content of the siliceous minerals (quartz and feldspar), carbonate minerals, and clay minerals [19,20,21], it was demonstrated that Qingshankou shales can mainly be classified into two types: argillaceous/siliceous mixed shale lithofacies (M-2) and clay-rich siliceous shale lithofacies (S-3) (Figure 3, Table 1).

4.2. Organic Geochemical Characteristics

4.2.1. Organic Matter Abundance

Parameters commonly used to evaluate the abundance of organic matter in source rocks include TOC and (S1 + S2) [22,23].
According to a TOC of less than 0.5%, 0.5–1%, 1–2% and greater than 2%, and (S1 + S2) of less than 3 mg/g, 3–6 mg/g, 6–20 mg/g, and greater than 20 mg/g, shale can be classified into four grades: poor, average, good, and excellent [24,25]. As shown in Table 2, TOC range from 1.40% to 2.78% (2.01% on average), S1 range from 1.22 mg/g to 2.85 mg/g (2.06 mg/g on average), S2 range from 5.56 mg/g to 13.42 mg/g (10.25 mg/g on average), and S1 + S2 range from 7.11 mg/g to 15.79 mg/g (12.30 mg/g on average). Figure 4 shows the cross-plot of TOC vs. (S1 + S2). It can be seen from Figure 4 that all shale samples fall in the zones of “good” and “excellent”.

4.2.2. Types of Organic Matter

The type of organic matter determines the oil prone or gas prone of source rock [23]. Rock-Eval pyrolysis parameters can be used to evaluate the types of organic matter in shale. Nevertheless, Rock-Eval pyrolysis parameters may be affected in some cases due to mineralogical compositions and certain kerogens [26,27,28,29,30,31,32]. Therefore, it is necessary to use a variety of experimental parameters to study the types of organic matter.
The HI vs. Tmax diagram shows that the organic matter in the Qingshankou lacustrine shales is types I and II1, suggesting an oil prone of organic matter (Figure 5).
The S2 vs. TOC diagram can also be used to identify organic matter types [33]. The slope of the S2-TOC curve denotes the hydrogen index HI (HI = S2/TOC). An HI of less than 50 mg/g, 50–200 mg/g, 200–300 mg/g, 300–600 mg/g, and greater than 600 mg/g denotes Type I (continental, oil prone), II (marine, oil prone), II/III (oil and gas prone), III (gas prone), and IV (dry gas prone) [34]. According to the above standard, the shale samples from the Qingshankou Formation mainly comprise Type II and partial Type I kerogen, indicating that they have oil-generation potentials (Figure 6).
The maceral composition of the shale samples can also be applied to the determination of kerogen types [35,36]. The compositions of the organic macerals of the Qingshankou lacustrine shales are shown in Figure 7 and Table 3. The ternary diagram of maceral groups indicates that the sapropelinite is the dominant component, which is favorable for oil generation, with the range from 80.6 to 88.9 vol %, and averaged 85.4 vol %, followed by vitrinite (5.0–12.4 vol %; average: 7.5 vol %) and inertinite (3.1–11.2 vol %; average: 5.9 vol %), the abundance of the liptinite is very low (1.0–1.7 vol %, average: 1.2 vol %). The type index of organic matter (TI) can be used to distinguish organic matter type. All samples fall into the type I (two samples) and II1 (seventeen samples) category.

4.2.3. Maturity

Ro and Tmax are extensively used to characterize the maturity of organic matter [23]. Ro values were measured for all twenty-four shale samples(Table 2). The shale samples from the Qingshankou Formation had an Ro between 1.01 and 1.12 (on average 1.07), suggesting that organic matter in Qingshankou lacustrine shales samples was in a mature stage (Table 2). Tmax values range from 435 °C and 459 °C, and averaged 449 °C (Table 2, Figure 5), indicating the thermal evolution of the Qingshankou shale samples fall in oil window.

4.3. Paleoenvironment

4.3.1. Sources of Organic Matter

Organic matter in source rock comes from a variety of sources, including endogenous lower organisms and allochthonous continental organic matter, which can be reflected by biomarker combinations of hydrocarbons generated by them [23,37,38,39,40]. Specific biomarker parameters and their combinations can be used to quantitatively reflect relative contributions of specific types of organisms.
Distribution features of chain alkanes can characterize the organic source and maturity of organic matter [23,37]. Ratios of some normal alkanes can reflect the variations of relative abundances of continental and aquatic organisms. Immature source rocks with organic matter dominated by continental plants generate hydrocarbons with more molecules with odd numbers that are particularly carbon rich in n-C27, n-C29, and n-C31. These n-alkanes from epidermal keratinine wax were compounded by higher plants directly or from alcohol or ester compounds with even carbon numbers losing functional groups, while n-C24 to n-C25 originated coming from marine organic matter.
Generally, the values of carbon preference index(CPI) decrease with a growth in maturity, and this is attributed to the mixing of n-alkanes generated by kerogen composed of different organism precursors and normal alkanes generated by hydrocarbon cracking in the early diagenetic stage. Hence, a high CPI generally implies low maturity and input from continental plants, while source rock with a CPI of around 1 have dominant marine input and high maturity [41,42]. The shale samples have a CPI between 1.01 and 1.20 (1.11 on average, Table 2), indicating Qingshankou lacustrine shales has relatively high organic matter maturity.
Organic matter input and sedimentary conditions have a strong impact on biomarkers in extractions from the source rock. Since C27 sterols derive mainly from plankton, C28 sterols from phytoplankton, and C29 sterols are abundant in land plants, the relative abundance of C27ααα(20R), C28ααα(20R) and C29ααα(20R) regular steranes is often used to determine the dominant source of OM [38,43,44]. The Qingshankou lacustrine shale samples have relative contents of C27, C28, and C29 regular sterane of 26.52–35.17% (30.54% on average), 19.88–28.13% (22.88% on average), and 41.69–52.34% (46.58% on average), respectively (Table 2). Figure 8 shows that all the shale samples fall in the plankton/bacterial and plankton/land plant fields. Thus, the organic matter in the Qingshankou shale samples is mainly from a mixture of plankton, bacterial and land plants.

4.3.2. Redox Environment

Water salinity affects the flourishment of aquatic organisms such as algae and, in turn, the input of organic matter. The water redox condition determines if the organic matter can be preserved effectively [45,46,47]. Suitable water salinity is conducive to the growth and reproduction of algae, which in turn affects the lake’s productivity. In some cases, increased nutrient inputs and optimal redox conditions could cause algal bloom in freshwater environments [48,49,50].
Under a certain salinity range, with the increase in salinity, algae growth gradually flourished, forming higher productivity and good preservation condition. However, over a certain salinity range, the algae are inhibited in growth and even do not develop at all [46]. An oxidizing water body can promote the reproduction of bacteria, leading to the massive consumption of organic matter in the sediment; on the other hand, in a reducing environment with suitable salinity, the reproduction of bacteria is inhibited, so the organic matter deposited can be preserved well.
Gammacerane/C30 hopane (G/C30H) is a parameter commonly used to characterize the salinity of a sedimentary environment [37,51]. It is generally believed that G/C30H > 0.11 indicates a reducing water environment [52]. As shown in Table 2, the shale samples from the Qingshankou Formation have G/C30H values between 0.31 and 0.65 (0.42 on average), suggesting that Qingshankou’s lacustrine shales formed in reducing saline water (Figure 9).
Pristane/phytane (Pr/Ph) is a classic parameter for identifying redox conditions [53,54]. A Pr/Ph of less than 1, 1–3, and more than 3 indicates reducing, weakly reducing, and oxidizing conditions, respectively. However, some researchers hold that organic matter maturity affects Pr/Ph, which should be kept in mind when judging the sedimentary environment of organic matter by Pr/Ph [55,56,57]. It can be seen from the diagram of Pr/Ph vs. Tmax (Figure 10) that they have no significant correlation, which means that Pr/Ph is not affected by the thermal evolution degrees of organic matter, thus Pr/Ph can be used to identify the sedimentary environment. As shown in Table 2, the shale samples from the Qingshankou Formation have Pr/Ph values between 0.71 and 1.32 (1.03 on average), indicating that the organic matter in shale samples was formed in a reducing–weakly reducing sedimentary environment. The Ph/n-C18 and Pr/n-C17 ratio of the saturated hydrocarbon vary from 0.10 to 0.21 (average: 0.15) and 0.01 and 0.26 (average: 0.16), respectively. Figure 11 shows that the Qingshankou lacustrine shales samples were from a mixture of organic matter and formed in a semi-oxidation and semi-reduction environment (Figure 11).

5. Conclusions

(1) Lacustrine shale samples from the Qingshankou Formation of southern Songliao Basin have high organic matter abundances, reaching the standard of a “good” and “excellent” source rock, types I and II kerogen, with oil-generation potential, and in a mature stage of organic matter.
(2) The origin of the organic matter in Qingshankou shale samples were mainly from a mixture of plankton, bacterial and land plants.
(3) The shale samples were formed in a semi-oxidation and semi-reduction environment, which is conducive to the preservation of organic matter.

Author Contributions

Data curation, Z.L., Z.B. and Z.W.; Formal analysis, Z.L.; Funding acquisition, Z.L., Z.B. and H.W.; Methodology, Z.L. and H.W.; Software, L.L.; Visualization, H.W. All authors have read and agreed to the published version of the manuscript.

Funding

The authors thank the support from PETROCHINA (Grant Nos. 2021DJ0203, 2021DJ0205, and 2021DJ2207).

Institutional Review Board Statement

Not applicable.

Informed Consent Statement

Not applicable.

Data Availability Statement

Data are available from the authors upon request.

Acknowledgments

The authors would like to express their gratitude to the PetroChina Jilin Oilfield Company for providing the resources required to collect the samples used in this study. We also acknowledge the precious advice of the editors and reviewers.

Conflicts of Interest

The authors declare no conflict of interest.

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Figure 1. (a) Location of Songliao Basin in China; (b) six tectonic units of Songliao Basin; (c) location of the study area in Songliao Basin; (d) stratigraphic column and lithology of the Qingshankou Formation in Songliao Basin (Adapted from Refs. [6,18]).
Figure 1. (a) Location of Songliao Basin in China; (b) six tectonic units of Songliao Basin; (c) location of the study area in Songliao Basin; (d) stratigraphic column and lithology of the Qingshankou Formation in Songliao Basin (Adapted from Refs. [6,18]).
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Figure 2. Histograms of the mineral composition of Qingshankou lacustrine shale samples. (a) Whole rock mineral compositions; (b) Clay mineral compositions.
Figure 2. Histograms of the mineral composition of Qingshankou lacustrine shale samples. (a) Whole rock mineral compositions; (b) Clay mineral compositions.
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Figure 3. Classification of shale lithofacies in the study area (Adapted from Refs. [19,20,21]). S: Siliceous shale lithofacies; S-1: Carbonate-rich siliceous shale lithofacies; S-2: Mixed siliceous shale lithofacies; S-3: Clay-rich siliceous shale lithofacies; M: Mixed shale lithofacies; M-1: Calcareous/siliceous mixed shale lithofacies; M-2: Argillaceous/siliceous mixed shale lithofacies; M-3: Argillaceous/calcareous mixed shale lithofacies; CM: Argillaceous shale lithofacies; CM-1: Silica-rich argillaceous shale lithofacies; CM-2: Mixed argillaceous shale lithofacies; CM-3: Carbonate-rich argillaceous shale lithofacies.
Figure 3. Classification of shale lithofacies in the study area (Adapted from Refs. [19,20,21]). S: Siliceous shale lithofacies; S-1: Carbonate-rich siliceous shale lithofacies; S-2: Mixed siliceous shale lithofacies; S-3: Clay-rich siliceous shale lithofacies; M: Mixed shale lithofacies; M-1: Calcareous/siliceous mixed shale lithofacies; M-2: Argillaceous/siliceous mixed shale lithofacies; M-3: Argillaceous/calcareous mixed shale lithofacies; CM: Argillaceous shale lithofacies; CM-1: Silica-rich argillaceous shale lithofacies; CM-2: Mixed argillaceous shale lithofacies; CM-3: Carbonate-rich argillaceous shale lithofacies.
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Figure 4. Diagram of TOC vs. (S1 + S2) (Adapted from Ref. [24]).
Figure 4. Diagram of TOC vs. (S1 + S2) (Adapted from Ref. [24]).
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Figure 5. Diagram of HI vs. Tmax, indicating types I and II1 organic matter of the Qingshankou lacustrine shales.
Figure 5. Diagram of HI vs. Tmax, indicating types I and II1 organic matter of the Qingshankou lacustrine shales.
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Figure 6. Diagram of S2 vs. TOC, indicating types I and II organic matter of the Qingshankou lacustrine shales.
Figure 6. Diagram of S2 vs. TOC, indicating types I and II organic matter of the Qingshankou lacustrine shales.
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Figure 7. Ternary diagram of maceral composition for kerogen-type identification showing the dominance of sapropelinite and Type I and II1 kerogen.
Figure 7. Ternary diagram of maceral composition for kerogen-type identification showing the dominance of sapropelinite and Type I and II1 kerogen.
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Figure 8. Ternary diagram of C27, C28, and C29 regular steranes showing the relationship.
Figure 8. Ternary diagram of C27, C28, and C29 regular steranes showing the relationship.
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Figure 9. Diagram of G/C30H vs. Pr/Ph.
Figure 9. Diagram of G/C30H vs. Pr/Ph.
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Figure 10. Diagram of Pr/Ph and Tmax.
Figure 10. Diagram of Pr/Ph and Tmax.
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Figure 11. Diagram of Pr/n-C17 vs. Ph/n-C18 of the shale samples, showing redox conditions and organic matter sources (Adapted from Refs. [58,59]), OM = Organic matter.
Figure 11. Diagram of Pr/n-C17 vs. Ph/n-C18 of the shale samples, showing redox conditions and organic matter sources (Adapted from Refs. [58,59]), OM = Organic matter.
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Table
Table 1. Mineralogical compositions and lithofacies of Qingshankou Formation shales.
Table 1. Mineralogical compositions and lithofacies of Qingshankou Formation shales.
Sample IDDepthQuartzFeldsparCalciteIron DolomiteSideritePyriteClayIlliteChloriteMixted Layer (I/S)Lithology
11971.227.7189.7 3.35.535.874719M-2
21976.932.9173.14.42.15.235.385213M-2
31979.630.619.32.42.52.36.236.780713M-2
41982.227.916.54.72.72.65.340.281613M-2
51984.330.419.21.21.54.75.237.970921M-2
62001.831.3255.75.1 5.427.567726S-3
72003.723.623.50.320.7 3.128.8611227M-2
82009.726.925.32.716.51.24.123.375817S-2
92011.933.520.17.7 4.73486311S-3
102014.633.421.74.5 535.4611524S-3
112016.234.128.52.9 3.830.777716S-3
122017.833.7162.9 542.4661222M-2
132025.53030.27.3 1.1328.4721018S-3
142030.532.318.33.7 14.340.4701119S-3
152033.330.918.513.7 0.42.134.479714M-2
162035.63014.210.95.8 1.737.574917M-2
172038.030.919.79 3.137.277518S-3
182042.834.515.75 3.641.38848S-3
192044.334.213.618.2 2.931.183611M-2
202046.534.320.72.4 0.23.738.777716S-3
212048.23512.49.6 1.941.18749M-2
222051.333.520.14.5 3.738.276816S-3
232055.032.817.42.6 5.341.99028S-3
242062.64112.94.5 0.641681616S-3
Table
Table 2. Statistics of geochemical biomarker parameters of the Qingshankou lacustrine shales.
Table 2. Statistics of geochemical biomarker parameters of the Qingshankou lacustrine shales.
Sample IDDepthTOCS₁S₂S₁ + S₂S1/(S₁ + S₂)HIOITmaxRoCPIC27st%C28st%C29st%(G/C30H)(Pr/Ph)Ph/nC18Pr/nC17
11971.21.941.5713.4214.990.106930.644461.011.1427.7819.8852.340.340.890.100.10
21976.91.401.438.179.600.155840.574471.031.1028.5421.2050.260.370.960.100.10
31979.61.781.9612.7614.720.137180.694481.051.0930.7121.4847.810.340.990.100.11
41982.21.821.8210.5412.360.155800.574471.081.0926.5228.1345.340.560.770.100.01
51984.31.791.769.7911.550.155470.544451.071.0929.7223.9746.320.500.880.120.10
62001.81.462.137.429.550.225100.544401.041.1130.3125.0144.680.451.150.140.18
72003.72.661.8312.6714.500.134760.454531.071.1131.6123.9044.490.490.940.140.15
82009.71.482.277.089.350.244780.534451.011.1029.9523.4246.620.510.710.200.16
92011.91.661.555.567.110.223350.364511.081.1229.9423.3246.740.431.320.210.26
102014.62.062.1811.6613.840.165660.564471.071.1232.5222.2645.220.481.210.150.19
112016.22.782.1412.0814.220.154350.434541.081.1129.6923.2647.050.481.070.190.21
122017.81.992.0710.3612.430.175220.524431.081.1229.8722.8547.280.371.130.190.21
132025.52.052.419.1011.510.214440.474461.071.1728.5825.4345.980.381.050.200.22
142030.52.022.1410.4912.630.175190.524491.101.1232.1021.7446.160.310.780.180.16
152033.32.332.429.6412.060.204140.434501.071.1029.4821.7148.800.391.090.180.20
162035.62.032.829.0611.880.244460.494351.091.1130.6722.1647.170.371.220.200.24
172038.02.382.1610.4612.620.174400.444531.051.1029.8922.4447.670.351.280.140.17
182042.82.202.8511.7114.560.205330.554521.071.0835.1723.1441.690.390.970.170.16
192044.31.661.708.4110.110.175080.514521.111.0931.2322.1346.650.341.130.110.13
202046.52.001.8311.0712.900.145540.544511.121.1027.5424.1148.350.371.140.140.17
212048.22.112.1112.4814.590.145930.574521.051.1432.7121.8745.420.360.910.120.11
222051.32.382.5211.7914.310.184960.504521.101.2033.2321.9944.790.331.110.120.14
232055.01.551.226.908.120.154450.434511.071.1732.0121.5646.430.341.130.110.13
242062.62.682.4413.3515.790.154980.494591.061.1733.2022.2444.560.431.050.120.12
Tmax = temperature at which maximum hydrocarbon generation (°C); TOC = total organic carbon (weight percent wt% of the whole rock); S1 = volatile hydrocarbon content (mg hydrocarbon/g rock); S2 = remaining hydrocarbon content (mg hydrocarbon/g rock); HI = hydrogen index (mg S2/g TOC); OI = oxygen index (mg S3/g TOC).
Table
Table 3. Composition of organic macerals of the Qingshankou lacustrine shales.
Table 3. Composition of organic macerals of the Qingshankou lacustrine shales.
Sample IDDepth
(m)		Sapropelinite
(%)		Liptinite
(%)		Vitrinite
(%)		Inertinite
(%)		TIType
11971.1881.31.39.38.067.0II1
21976.8681.41.410.07.167.5II1
31979.5587.11.16.55.477.4II1
41982.2184.81.07.17.173.0II1
51984.2586.51.08.34.276.6II1
62001.8387.91.15.55.578.8II1
72003.7383.51.012.43.171.6II1
82009.6786.41.76.85.177.1II1
92011.987.51.36.35.078.4II1
102014.6186.21.76.95.276.7II1
112016.1987.21.16.45.377.7II1
122017.7988.81.35.05.080.6I
152033.2688.91.16.73.381.1I
162035.5586.71.16.75.676.7II1
172038.0388.21.25.94.779.7II1
182042.7881.61.39.27.967.4II1
202046.5480.61.07.111.264.5II1
222051.2983.71.17.67.670.9II1
242062.5585.11.18.55.373.9II1
The type index of organic matter (TI) = (sapropelinite × 100 + liptinite × 50-vitrinite × 75-inertinite × 100)/100.
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Li, Z.; Bao, Z.; Wei, Z.; Li, L.; Wang, H. Geochemical Features of Lacustrine Shales in the Upper Cretaceous Qingshankou Formation of Changling Sag, Songliao Basin, Northeast China. Energies 2022, 15, 6983. https://doi.org/10.3390/en15196983

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Li Z, Bao Z, Wei Z, Li L, Wang H. Geochemical Features of Lacustrine Shales in the Upper Cretaceous Qingshankou Formation of Changling Sag, Songliao Basin, Northeast China. Energies. 2022; 15(19):6983. https://doi.org/10.3390/en15196983

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Li, Zhongcheng, Zhidong Bao, Zhaosheng Wei, Lei Li, and Hailong Wang. 2022. "Geochemical Features of Lacustrine Shales in the Upper Cretaceous Qingshankou Formation of Changling Sag, Songliao Basin, Northeast China" Energies 15, no. 19: 6983. https://doi.org/10.3390/en15196983

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