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Article

Hydrocarbon Source Rock Evaluation of the Lucaogou Shale in the Periphery of Bogeda Mountain (SE Junggar Basin, China) and Its Implications for Shale Oil Exploration: Insights from Organic Geochemistry, Petrology, and Kinetics Pyrolysis

by
Guanlong Zhang
1,
Yuqiang Yang
2,
Tianjiao Liu
3,*,
Youde Xu
1,
Xiangchun Chang
3,4,
Yansheng Qu
1,
Bingbing Shi
3,
Bo Yang
2 and
Tao Song
2
1
Research Institute of Petroleum Exploration and Development, Shengli Oil Company, Sinopec, Dongying 257001, China
2
Shandong Engineering Research Center of Mine Gas Disaster Prevention, Qingdao 266427, China
3
College of Earth Science and Engineering, Shandong University of Science and Technology, Qingdao 266590, China
4
Laboratory for Marine Mineral Resources, Qingdao National Laboratory for Marine Science and Technology, Qingdao 266071, China
*
Author to whom correspondence should be addressed.
Processes 2024, 12(2), 356; https://doi.org/10.3390/pr12020356
Submission received: 12 November 2023 / Revised: 13 December 2023 / Accepted: 15 December 2023 / Published: 8 February 2024
(This article belongs to the Special Issue Exploration, Exploitation and Utilization of Coal and Gas Resources)
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Versions Notes

Abstract

:
Since the discovery of the vast Jimusaer shale oilfield in the southeastern Junggar Basin in 2012, there has been considerable interest in neighboring areas around Bogeda Mountain that have shale oil potential. The primary productive interval in the basin, the Middle Permian Lucaogou Formation (P2l), is well-developed in the areas of Qitai, Mulei, Shiqiantan, Chaiwopu, and Miquan. In this study, we conducted an assessment of the hydrocarbon generation potential of the P2l in these five areas and compared it with that of the P2l in the Jimusaer oilfield, which were determined by GC-MS, total organic carbon (TOC) and vitrinite reflectance (Ro) measurements, Rock-Eval pyrolysis, and organic petrology to investigate the type, origin, thermal maturity, hydrocarbon potential, and oil/gas proneness of organic matter in the P2l. Additionally, we applied open-system pyrolysis of hydrocarbon generation kinetics to explore differences in hydrocarbon generation and expulsion across various P2l mudstone/shale in the southeastern Junggar Basin. The findings of this study revealed that the P2l shale in Qitai and Miquan areas contains more abundant and lower thermally mature organic matter (early mature–mature stage), characterized by primarily Type II1–I kerogen, similar to that found in the P2l shale of the Jimusaer oilfield. Conversely, the P2l shale in Mulei, Shiqiantan, and Chaiwopu contains less abundant and more thermally mature organic matter (mainly mature–highly mature stage), dominated by Type II2–III kerogen. Consequently, shale in these areas is considerably less desirable for oil exploration compared to the Jimusaer shale. The semi-deep to deep lake facies in Miquan and Qitai exhibit the most promising exploration potential. This study can serve as a guide for shale oil exploration in the southeastern Junggar Basin.

1. Introduction

The southeastern Junggar Basin is an important field of oil and gas exploration [1,2,3,4,5]. Within this basin, the Upper Permian Lucaogou Formation (P2l), with organic-rich source rocks (a TOC content of up to 20 wt.%), is a primary target for shale oil exploration in the Bogeda Piedmont Depression. Significant commercial tight oil reservoirs were discovered in the P2l shale in the Jimusaer and Qitai areas of the Junggar Basin [4,6,7]. In the Jimusaer area, the estimated shale oil resources amount to approximately 370 million tons, while wells Qi 1 and Bocan 1 confirm the presence of the P2l source rock [3,8,9]. It is worth noting that although the P2l mainly comprises laterally extensive lake facies, its source rock qualities vary across different areas of the basin. The development characteristics and lateral facies variation of the P2l source rocks remain unclear. Furthermore, the southeastern Junggar Basin presents the potential for late secondary hydrocarbon generation; however, due to the absence of relevant reports, target evaluation and exploration optimization are hindered.
Due to the influence of the Hercynian Movement, the Yanshan Movement, the Himalayan Movement, and other strong orogenic movements, the degree of thermal evolution is quite different. Differences in tectonic evolution have led to the different hydrocarbon generation and thermal evolution patterns of P2l source rocks in different regions [10]. However, few reports concerning the organic geochemistry and petrology of the P2l shale have been published to date [1,3,8,9]. Therefore, this study aims to investigate the types, origin, maturity, hydrocarbon potential, and oil/gas proneness of the organic matter within P2l source rocks using bulk and organic geochemistry, TOC and vitrinite reflectance measurements, Rock-Eval pyrolysis, and organic petrology. By integrating these analyses with data on source rock development and depositional environment, we can predict the distribution of favorable source rocks in the southeastern Junggar Basin.
The P2l source rocks in the southeastern Junggar Basin are primarily at the low-maturity to maturity stage (Ro < 1.0%) [11]. In order to assess the potential and conditions for secondary hydrocarbon generation in the basin, an open-system pyrolysis approach was employed to analyze the kinetics of hydrocarbon generation. This study has important practical implications for the exploration of the P2l oil shale reservoirs in the vicinity of Bogeda Mountain and the identification of promising hydrocarbon targets.

2. Geological Setting

2.1. Tectono-Sedimentary Characteristics

The Bogeda orogenic belt is located in the southeastern Junggar Basin. It is bordered by the fault belt that forms the northern margin of the Turpan Basin to the south, the Urumqi-Jimusaer Sag to the north, and the Yilinheibiergen tectonic belt to the southwest and connects with the Harrick tectonic belt to the east. Several residual sedimentary basins, namely, the Shiqiantan and Mulei sags in the east, the Qitai Uplift in the center, the Miquan Structure in the west, and the Chaiwopu Sag in the south, are present in the periphery of the Bogeda orogenic belt (Figure 1a).
The Bogeda orogenic belt evolved from a volcanic rift in the Junggar–Turpan microplate. Since the Late Paleozoic, the Bogeda region has experienced rifting, depression, and foreland basin evolution. In the southeastern Junggar Basin, the Upper, Middle, and Lower Permian systems are well-developed but greatly variable. The Lower Permian mainly occurred in the Chaiwopu and Miquan areas. The Middle Permian is very widespread across the entire southeastern Junggar Basin; the Upper Permian is also widespread (Figure 1b).
The Middle Permian deposits include three stratigraphic units of organic-rich mudstones: the Jingjingzigou, Lucaogou (P2l), and Hongyanchi Formations [1]. The P2l has a much higher TOC and hydrogen index (HI) content than the other two Middle Permian formations and hosts good petroleum reservoirs. Based on outcrop evidence from Hongyanchi (HYC), Jingjingzigou (JJZG), Yaomoushan (YMS), Dahuangshan (DHS), Xiaolongkou (XLK), and Guodikeng (GDK), and drilling cores from the Qi-1 and Xinjican-1 wells, the P2l is divided into four members, namely, P2l1, P2l2, P2l3, and P2l4, from bottom to top. In the eastern Junggar Basin, the stratigraphic unit correlative to the P2l is the Pingdiquan Formation (P2p) (Figure 2) [5,11].

2.2. Tectonic Evolution

Due to the influence of the Hercynian Movement, the Yanshan Movement, the Himalayan Movement, and other strong orogenic movements, the degree of thermal evolution is quite different [10]. Differences in tectonic evolution have led to the different hydrocarbon generation and thermal evolution patterns of P2l source rocks in different regions (Figure 3).
According to the regional unconformity surface, the tectonic sedimentary evolution of the SE Junggar Basin during Permian is divided into two periods and three stages: (1) Early Permian–Middle Permian marine–continental transitional compressional basin stage (including Early Permian marine compressional stage and Middle Permian continental compressional basin stage); (2) Late Permian–Paleogene intracontinental compression basin period (Late Permian–Early Triassic intracontinental compression depression stage) (Figure 3).

3. Sampling and Methods

3.1. Sample Selection and Preparation

To investigate the organic geochemistry, hydrocarbon potential, and hydrocarbon generation and expulsion characteristics of the P2l source rocks, 80 rock cores were sampled from six wells across the area of study (Mucan-1, Mulei-1, Qi-1, Xinjican-1, Bocan-1, and Chaican-1), and 176 rock samples were collected from four outcrops in the northeastern Junggar Basin, namely, JJZG and HYC (Miquan area), DHS (Qitai area), and GDK (Chaiwopu area) (Figure 1a). Those samples underwent the following analyses: TOC content, Rock-Eval pyrolysis, vitrinite reflectance, organic petrography, column chromatography, Gas chromatography–mass spectrometry, organic elements, and open-system hydrocarbon generation kinetics pyrolysis (18 samples), and some of the data were collected from published works [3,4,6,7,9,12,13,14,15,16] and new data from Shengli Oil Company, Sinopec, Dongying, China.

3.2. Gas Chromatography–Mass Spectrometry (GC-MS) Analysis

GC-MS was used to study the geochemical characteristics of the source rock samples of the Lucaogou Formation from the southeastern Junggar Basin and to compare the parameters of various biomarkers and analyze the characteristics of the mass chromatogram, so as to provide useful information for the evaluation of the source rock in this area. The GC-MS analysis was performed on 18 source rock samples and two crude oil samples, using an Agilent 7890A GC/5977MSD instrument. Other analytical conditions are the same as in Ref. [17].

3.3. Organic Petrographic Analysis

To measure the vitrinite reflectance (Ro) and analyze the maceral composition, we conducted the organic petrographic examination on 39 samples from five wells, using a Zeiss Axioplan II microscope (Jena, Germany) and following the laboratory methods described by Ref. [18]. Maceral analysis was performed with an LABORLUX 12 POL fluorescence microscope. More than 300 points were counted for each sample [19,20,21].

3.4. Open-System Hydrocarbon Kinetic Pyrolysis

To study the hydrocarbon production efficiency of the source rock, the 18 samples from the JJZG (Miquan), DHS (Qitai), HYC (Miquan), and GDK (Chaiwopu) profiles and Well Qi-1 were treated to generate kerogen. The kinetic pyrolysis of hydrocarbon generation was conducted using the Rock-Eval 6 analyzer. The heating procedure was as follows: The temperature in the analyzer was raised quickly to 300 °C and kept constant for 3 min to remove free hydrocarbons. Then, the temperature was raised to 600 °C at the rate of 10 °C/min, 30 °C/min, 40 °C/min, and 50 °C/min, to acquire the samples’ hydrocarbon production efficiency curves at different heating rates. These curves are necessary for the calculation of the hydrocarbon generation kinetics.
The kinetic parameters of hydrocarbon generation were determined using Kinetics 2000 software. This software was also used to derive the distribution of activation energy from the input data (time, temperature, and transformation rate for the generation of gaseous hydrocarbons) measured in the course of pyrolysis at the four experimental heating rates. The thermal decomposition of kerogen in a source rock sample was approximated by a series of independent and parallel first-order chemical reactions. The temperature dependency of the reaction rate was quantified by applying Arrhenius’ law with a discrete activation energy distribution, as described by many other authors [22,23,24].

4. Results

4.1. Organic Matter Abundance

In this study, the organic matter abundance was determined by the plot of TOC versus the HI (mg HC/g rock) (Figure 4) and the boxplots of TOC, hydrocarbon potential (S1 + S2), chloroform bitumen “A”, and the hydrocarbon generation potential index (GPI = (S1 + S2)/TOC) (Figure 5). The geochemical evaluation criteria for terrestrial source rocks are given in Table 1.
The boxplots of TOC, S1 + S2, chloroform bitumen “A”, and GPI indicate a gradual increase in the abundance of organic matter from Mulei to Shiqiantan, Chaiwopu, Miquan, and Qitai. The P2l shale in Qitai, Miquan, and the adjacent area of Jimusaer exhibits higher organic matter abundance compared to the corresponding shale in Mulei, Shiqiantan, and Chaiwopu. In each of the last three areas, the average value of chloroform bitumen “A” is 0.0095, 0.0469, and 0.0868%, respectively. These results suggest that the P2l shale in Mulei, Shiqiantan, and Chaiwopu is a poor to fair source rock with low hydrocarbon generation capacity. On the other hand, the average chloroform bitumen “A” value of the P2l shale in Miquan and Qitai is 0.1679 and 0.1751%, respectively, indicating that most of the P2l shale in these two areas is a good to excellent source rock (Figure 5c). The P2l shale in adjacent Jimusaer has the highest organic matter abundance among the studied sites and a chloroform bitumen “A” content from 0.0150 to 4.6550% (average: 0.6225%). Overall, the values of TOC, S1 + S2, chloroform bitumen “A”, and GPI demonstrate that the P2l shale in Miquan and Qitai has an organic matter abundance equivalent to that in Jimusaer, whereas the P2l shales in Chaiwopu, Shiqiantan, and Mulei have an organic matter abundance much lower than that in Jimusaer.

4.2. Kerogen Type

4.2.1. Organic Elemental Analysis

A van Krevelen diagram was employed to analyze the kerogen type in the P2l source rock [25]. As demonstrated by Figure 6 and Table 2, the kerogen in the P2l shale ranges from gas-prone (Type III) to oil-prone (Type I), with Type III–II2 in Chaiwopu, Type II2 in Mulei and Shiqiantan, Type II1–II2 in Miquan, and Type II1–I in Qitai.

4.2.2. Rock Pyrolysis Analysis

The cross-plots of TOC and Tmax versus HI (Figure 4) provide further evidence that in different areas of the southeastern Junggar Basin, the P2l contains different kerogen types. The main types of organic matter in Mulei and Chaiwopu are III and II2–III, which are mainly gas-prone sources. The organic matter in Miquan and Jimusaer is mainly Type II1–III and II1–II2, which are mainly gas- to oil-prone sources, whereas, in Qitai, the organic matter type ranges from I to III (with part of it even being oil shale)—a mixture of gas- and oil-prone sources.

4.2.3. Molecular Biomarker Characteristics

Representative mass chromatograms of n-alkane from core extracts of the studied sites are presented in Figure 7 and Table 2. The n-alkane series observed in Chaiwopu and Mulei exhibit a bimodal distribution, indicating that in these areas, organic compounds in the P2l shale are likely derived from a mixed source of bacteria, algae, and higher plants. The n-alkane series of Qitai and Miquan exhibit an unimodal distribution with a predominance of lower carbon numbers (<C22), suggesting bacterial and algal–detrital sources. β-Carotene is a completely saturated, C40 dicyclic alkane whose presence is commonly associated with algae in anoxic saline lake environments [26,27,28,29]. The P2l shales in Mulei, Chaiwopu, and Jimusaer are rich in β-carotene, suggesting a greater contribution of algae to the generation of oil in these areas (Figure 7a,e,f). In addition, the strong odd–even predominance implies that the source rocks in the Shiqiantan area are still in the low-maturity stage (Figure 7b).
The Pr/n-C17 versus Ph/n-C18 cross-plot provides valuable insights into the organic matter sources and paleoenvironmental conditions [30,31,32]. This relationship indicates that in Qitai, Chaiwopu, Jimusaer, and Mulei, the P2l received a predominantly mixed input of organic matter (Type II–III). Most samples from Miquan fell within the saliferous (Type II) organic matter zone (Figure 8), indicating that in the southeastern Junggar Basin, the P2l source rocks originated from a saliferous terrigenous environment [33]. Reference [11] found that the δ13C values of the P2p in the eastern Junggar Basin and P2l in the southern Junggar Basin were mainly lower than −26.0‰. This indicates the organic matter in the P2l shale had a predominately aquatic origin, with only minor input from terrestrial organisms.

4.2.4. Organic Petrology

Based on analysis of optical properties and genetic characteristics conducted through organic petrological analysis, the maceral composition is distinguished into several types (liptinite, vitrinite, inertinite, matrix-bituminite), each corresponding to a distinct kerogen typology [34,35].
The ternary maceral plot and the boxplot of the kerogen type index (TI) demonstrate that the kerogen type in the P2l shale varies across the southern Junggar Basin, from gas-prone Type III to oil-prone Type I; the P2l shale is characterized by Type III–II2 kerogen in Chaiwopu, Type II2 kerogen in Mulei and Shiqiantan, Type II1–II2 kerogen in Miquan, and Type II1–I kerogen in Qitai (Figure 9 and Table 2).
As illustrated in Table 2 and Figure 9a,b, vitrinite and inertinite are the dominant maceral compositions in the P2l shale of Shiqiantan, Mulei, and Chaiwopu. The average kerogen TI values for these areas are −1.13, 1.13, and 7.28, respectively, indicating mainly Type III (TI < 0.0) and Type II2 kerogen (TI < 40.0). In Miquan and Qitai, the dominant maceral composition of the P2l shale is liptinite, with average kerogen TI values of 28.58 and 50.23, respectively, belonging to Type II1 (40.0 < TI < 80.0) and a small amount of Type I kerogen (TI > 80.0), which are equivalent to the that of Jimusaer Sag (average on 77.25).
Representative photomicrographs show that in Mulei, Shiqiantan, and Chaiwopu, the maceral composition of the P2l shale is characterized by massive-detrital, grey, homogeneous vitrinite with no fluorescence (Figure 10a–c). Some alginite and lamalginite with yellow fluorescence can be observed in Chaiwopu. In Qitai and Miquan, the maceral composition is primarily comprised of liptinite, including filamentous algae, sporophyte, and lamalginite with yellow fluorescence, fusinite with white fluorescence, and matrix-bituminite with orange fluorescence (Figure 10d,e). These observations demonstrate that the P2l in the Qitai and Miquan areas contains kerogen of a type more advantageous than that of the P2l in Mulei, Shiqiantan, and Chaiwopu.
Previous studies found that the maceral composition of the P2l shale in Jimusaer comprises mainly amorphous saprolite, fungus sporophyte, sporopollen, and suberinite, with a lower content of vitrinite and inertinite. The main kerogen types are I and II1 (Figure 10f; [6,7]). Our analysis further confirms that the kerogen type of the Miquan and Qitai P2l shale is equivalent to that of the Jimusaer P2l shale, whereas the kerogen type of the Chaiwopu and Mulei P2l shale is of much lower quality.

4.3. Thermal Maturity

The boxplots of vitrinite reflectance (Ro, %) and maximum pyrolysis peak temperature (Tmax) reveal that in the sampled areas, the thermal maturity of the organic matter is distributed as follows (in ascending order): Qitai (Ro = 0.46–1.24%; average: 0.78%), Miquan (Ro = 0.40–1.38%; average: 0.68%), Shiqiantan (Ro = 0.55–1.19%; average: 0.96%), Mulei (Ro = 0.60–1.06%; average: 0.86%), and Chaiwopu (Ro = 0.60–1.71%; average: 1.082%) (Figure 11a, Table 2). Additionally, Tmax values indicate that in Chaiwopu and Mulei, the P2l shale has reached the mature–highly mature stage, whereas in Shiqiantan, Miquan, and Qitai (Figure 11b, Table 2), it is in the early mature–mature stage (very low Tmax values). The Ro and Tmax boxplots demonstrate that the thermal maturity of the P2l shale is equivalent to that in Jimusaer (Ro = 0.52–1.24%; average: 0.74%) in Miquan and Qitai; whereas that in Chaiwopu and Mulei, it is much higher.
It is widely accepted that the ratio of isomers effectively reflects the thermal maturity of the organic matter [36,37,38]. In this study, the cross-plots of C29 RS ββ/(αα + ββ) versus C29 RS 20S/(20S + 20R) were used to characterize the thermal maturity (Figure 12). The analysis reveals that the majority of P2l samples from Miquan, Shiqiantan, Jimusaer, and Qitai fall within the early mature–mature zone, whereas those from Mulei and Chaiwopu show abnormal post-maturity, potentially due to weathering and oxidation.

4.4. Kinetics of Petroleum Generation

As mentioned above, the vitrinite reflectance and Tmax (430–445 °C) indicate that the majority of the samples were in a range from thermally immature to mature. Therefore, these samples were deemed suitable for investigating petroleum generation kinetics [7,39]. The bulk kinetic parameters (activation energy, Ea, and frequency factor, A) for the kerogen-to-hydrocarbon conversion were calculated from a mathematical routine [7,24,39,40,41,42]. Assuming parallel first-order reactions with the same frequency factor and activation energy, different heating rates were employed to achieve optimal conversion. The optimal results were the ones that presented the best fit between the calculated and experimental curves. Eighteen samples of P2l mudstone and shale of different maturity and from different southeastern Junggar Basin sites were chosen for this analysis (Table 3).
Figure 13 shows the values obtained from the parallel first-order reaction model, with a heating rate of 30 °C. The model fit curves for all the data are given in Table 3. The maximum yield of hydrocarbon generation ranged from 10 to 40 mg/g and varied between different types of organic source rock and across the sampled sites. As seen in Figure 13, the order of maximum hydrocarbon generation yield was as follows: Type I > Type II1 > Type II2 > Type III (Table 3).
The activation energy of different types of P2l source rock also differed across the different sampled sites. Type I and II1 organic matter exhibited a lower activation energy with a more concentrated distribution, suggesting that in Type I and II1 organic matter, the hydrocarbon-generating components are relatively single, and hydrocarbon generation occurs earlier. The kinetic parameters of the parallel first-order reaction model show that the activation energy distribution in each sample was characterized by dominant activation energies (Figure 14): from 32 to 50 kJ/cal and from 50 to 68 kJ/cal in the upper and lower part of the P2l stratigraphy, respectively. This observation implies that the chemical bonds in lacustrine Type I kerogen remain unchanged during the hydrocarbon generation process.

5. Discussion

Mechanism of Organic Matter Enrichment in the P2l Mudstone/Shale: Implications for Shale Oil Exploration

The method of quantifying hydrocarbon generation and expulsion, known as the hydrocarbon generation potential method based on the material balance principle, has proven to be an effective approach [43,44,45,46].
Typically, the TOC value that corresponds to the turning point of the S1/TOC trendline (the onset of S1/TOC value reduction) is considered as the base limit for high-quality hydrocarbon source rocks [43,47]. In Figure 15a,b, it can be observed that the TOC base limit in the P2l is about 0.80 wt.%. The cross-plot of TOC versus S1 + S2 reveals that in the P2l, the S1 + S2 base limit is about 1.97 mg/g (Figure 15c). Due to the lack of vitrinite in the P2l mudstone/shale intervals, we combined the measured and calculated Ro (based on the Tmax, and derived from artificial neural networks) to determine the hydrocarbon expulsion threshold. Based on the pyrolysis and basin modeling results (Figure 15d), we established a hydrocarbon generation and expulsion model for the P2l shale in the southeastern Junggar Basin (Figure 15d). According to this model, the hydrocarbon expulsion threshold in the P2l shale is reached at Ro~0.75%.
The cross-section of P2l TOC distribution around Bogeda Mountain is shown in Figure 16. In Miquan and Qitai, the primary maceral components of the Member P2l1–2 source rock consisted mainly of terrigenous organic clastics with more vitrinite and inertite and a weaker fluorescence than the other P2l members. In member P2l2, the sapropelic components had a higher alginite content and a stronger fluorescence than those in P2l1. In members P2l3–4, the relative abundance of sapropelic and exinite groups increased further, and fluorescence was the strongest among the sampled members. Moreover, based on the geochemical profiles of the 10 wells and outcrops analyzed in this study (Figure 16), it is suggested that the hydrocarbon generation potential of the lower P2l members (P2l1–2: light gray silty mudstone) is lower than that of the upper P2l members (P2l3–4: dark mudstone and shale). A large set of shale with abundant organic matter in these P2l3–4 members makes them a promising target interval.
In this study, a principal component (PC) was extracted based on the evaluation parameters of thermal maturity, organic matter abundance, and kerogen type as follows: PC = −0.172 × C29ββ/(ββ + αα) − 0.030 × C2920S/(20S + 20R) − 0.146 × Roave + 0.179 × Sapropelic + 0.026 × Exinite + 0.170 × TI + 0.186 × TOC + 0.180 × (S1 + S2) + 0.124 × Bitumen “A”. The extracted PC value was positively proportional to the organic matter abundance and kerogen-type indicators and negatively correlated to the maturity parameters, indicating that the higher the PC value, the better the hydrocarbon generation potential of the source rock. As shown in Figure 17, from Mulei, Shiqiantan, Chaiwopu, to Miquan, Jimusaer, and then to the Qitai area, the hydrocarbon generation potential of the source rocks gradually improved. In addition, the contour distribution of (Figure 18a) P2l3–4 sedimentary facies, (Figure 18b) mudstone thickness, and (Figure 18c) TOC around Bogeda Mountain reveals that the semi-deep to deep lake facies of the Miquan area, with a maximum mudstone thickness of 900 m and a maximum TOC content of 8.0%, have the highest exploration potential. Moreover, the contour map of Ro values (Figure 18d) demonstrates that the P2l source rock in the Miquan area has entered the mature stage (Ro > 0.7%). Notably, both the Miquan and Qitai areas, characterized by semi-deep to deep lake facies, have the most promising exploration potential. The results of this study provide valuable guidance for shale oil exploration in the southeastern Junggar Basin.

6. Conclusions

In the six areas of study, the organic matter abundance increases in the following order: Mulei, Shiqiantan, Chaiwopu, Miquan, Jimusaer, and Qitai. The distribution of organic matter kerogen type, in order of decreasing quality, is as follows: Chaiwopu, Mulei, Shiqiantan, Miquan, Jimusaer, and Qitai. In order of increasing thermal maturity of the organic matter, the sites are ranked as follows: Qitai, Jimusaer, Miquan, Shiqiantan, Mulei, and Chaiwopu.
In Miquan and Qitai, the P2l shale exhibits an organic matter abundance and kerogen type equivalent to those in the P2l shale in the Jimusaer oilfield; however, in Chaiwopu, Shiqiantan, and Mulei, the organic matter abundance is much lower and the kerogen type much less advantageous than those of the Jimusaer shale.
From a vertical perspective, the P2l3–4 members of the P2l shale formation present a promising target interval due to their abundant organic matter. Horizontally, the semi-deep to deep lake facies of the Miquan and Qitai areas show the highest shale oil exploration potential in the southeastern Junggar Basin.
The comprehensive analysis indicates that, in the six areas of the southeastern Junggar Basin, the Qitai area holds the highest potential for shale oil exploration, even surpassing that of the Jimusaer area, followed by the Miquan and Chaiwopu areas, and the resource potential of shale oil in the Shiqiantan and Mulei areas is the worst.

Author Contributions

Conceptualization, T.L. and G.Z.; methodology, Y.Y.; software, X.C.; validation, Y.X.; formal analysis, Y.Q.; investigation, B.S.; resources, B.Y.; data curation, T.S.; writing—original draft preparation, B.S.; writing—review and editing, T.L.; visualization, B.S.; supervision, G.Z.; funding acquisition, X.C. All authors have read and agreed to the published version of the manuscript.

Funding

This study was co-funded by the National Natural Science Foundation of China (No. 42072172, 41772120, 42372160), the Shandong Natural Science Foundation Youth Program (ZR2023QD043), and the Research Fund of Shandong Coalfield Geological Bureau (2022-003). We thank the Shengli Oil Company of Sinopec for approving the publication.

Data Availability Statement

All data, models, and code generated or used during the study appear in the submitted article.

Conflicts of Interest

We declare that we do not have any commercial or associative interest that represents a conflict of interest in connection with the work submitted.

References

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Figure 1. (a) Geological map outlining the regional tectonic elements of the southeastern Junggar Basin and the (b) EW−trending profile through Bogeda Mountain showing the stratigraphic framework of Junggar Basin (Mulei area: Wells Mulei−1, Mulei−2, and Mucan−1; Shiqiantan area: Well Qian−1; Qitai area: Wells Xinjican−1, Qi-1, Bocan−1, XLK, SXG, XDLK, DHS, XG, and BYG outcrops; Miquan area: SGH, MEG, YMS, JJZG, HYC, QJG, and CFG outcrops, Well Miquan−1; Chaiwopu area: Wells Chai1−HF, Chai−2, Chai−3, Bancan−1, Da−1, GDK, BCG, XPCG, and AWE outcrops).
Figure 1. (a) Geological map outlining the regional tectonic elements of the southeastern Junggar Basin and the (b) EW−trending profile through Bogeda Mountain showing the stratigraphic framework of Junggar Basin (Mulei area: Wells Mulei−1, Mulei−2, and Mucan−1; Shiqiantan area: Well Qian−1; Qitai area: Wells Xinjican−1, Qi-1, Bocan−1, XLK, SXG, XDLK, DHS, XG, and BYG outcrops; Miquan area: SGH, MEG, YMS, JJZG, HYC, QJG, and CFG outcrops, Well Miquan−1; Chaiwopu area: Wells Chai1−HF, Chai−2, Chai−3, Bancan−1, Da−1, GDK, BCG, XPCG, and AWE outcrops).
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Figure 2. Chronostratigraphic chart showing the stratigraphic correlation between the areas of Miquan, Chaiwopu, Qitai, and Mulei in the southeastern Junggar Basin.
Figure 2. Chronostratigraphic chart showing the stratigraphic correlation between the areas of Miquan, Chaiwopu, Qitai, and Mulei in the southeastern Junggar Basin.
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Figure 3. The NS-trending cross-sections of the Chaiwopu, Miquan, and Jimusaer areas show stratigraphic development of the studied area.
Figure 3. The NS-trending cross-sections of the Chaiwopu, Miquan, and Jimusaer areas show stratigraphic development of the studied area.
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Figure 4. The cross-plots of TOC versus HI and Tmax versus HI show the differences in kerogen type between different regions of (a) Mulei, (b) Chaiwopu, (c) Miquan, (d) Jimusae, and (e) Qitai.
Figure 4. The cross-plots of TOC versus HI and Tmax versus HI show the differences in kerogen type between different regions of (a) Mulei, (b) Chaiwopu, (c) Miquan, (d) Jimusae, and (e) Qitai.
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Figure 5. Boxplots of (a) TOC, (b) S1 + S2, (c) chloroform bitumen “A”, and (d) GPI values show the differences in hydrocarbon generation potential between different regions.
Figure 5. Boxplots of (a) TOC, (b) S1 + S2, (c) chloroform bitumen “A”, and (d) GPI values show the differences in hydrocarbon generation potential between different regions.
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Figure 6. The cross-plot of O/C versus H/C by elemental analysis shows the differences in kerogen types in different regions.
Figure 6. The cross-plot of O/C versus H/C by elemental analysis shows the differences in kerogen types in different regions.
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Figure 7. Mass chromatograms (m/z 85) show the distributions of n-alkanes of different regions of (a) Chaiwopu, (b) Shiqiantan, (c) Qitai, (d) Miquan (e) Mulei and (f) Jimusaer.
Figure 7. Mass chromatograms (m/z 85) show the distributions of n-alkanes of different regions of (a) Chaiwopu, (b) Shiqiantan, (c) Qitai, (d) Miquan (e) Mulei and (f) Jimusaer.
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Figure 8. The cross−plot of Ph/n-C18 versus Pr/n-C17 shows the differences in paleo−environmental and source interpretation between different regions.
Figure 8. The cross−plot of Ph/n-C18 versus Pr/n-C17 shows the differences in paleo−environmental and source interpretation between different regions.
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Figure 9. (a) The ternary plot of the organic maceral and (b) the boxplot of kerogen type index (TI) show the differences in kerogen type between different regions (some data cited from Reference [3]; TI (%) = (Sapropelic (%) × 100 + Exinite (%) ×50 − Vitrinite (%) × 75 − Inertinite (%) × 100)/100). The * in the box-plot represents outlier.
Figure 9. (a) The ternary plot of the organic maceral and (b) the boxplot of kerogen type index (TI) show the differences in kerogen type between different regions (some data cited from Reference [3]; TI (%) = (Sapropelic (%) × 100 + Exinite (%) ×50 − Vitrinite (%) × 75 − Inertinite (%) × 100)/100). The * in the box-plot represents outlier.
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Figure 10. Representative photomicrographs show the maceral composition of the P2l Formation in different regions using transmitted light, reflected white light, and fluorescence blue light. Conditions: polished thin section, immersion oil objective, 500× (Notes: V: vitrinite; Alg: alginite; Exi: exinite). (a) Mulei, (b) Chaiwopu, (c) Shiqiantan, (d) Miquan, (e) Qitai, and (f) Jimusae.
Figure 10. Representative photomicrographs show the maceral composition of the P2l Formation in different regions using transmitted light, reflected white light, and fluorescence blue light. Conditions: polished thin section, immersion oil objective, 500× (Notes: V: vitrinite; Alg: alginite; Exi: exinite). (a) Mulei, (b) Chaiwopu, (c) Shiqiantan, (d) Miquan, (e) Qitai, and (f) Jimusae.
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Figure 11. Boxplots of (a) vitrinite reflectance (Ro) and (b) maximum pyrolysis peak temperature (Tmax) show the differences in thermal maturity between different regions.
Figure 11. Boxplots of (a) vitrinite reflectance (Ro) and (b) maximum pyrolysis peak temperature (Tmax) show the differences in thermal maturity between different regions.
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Figure 12. Selected biomarkers for determining the thermal maturity of different regions in the southeastern Junggar Basin.
Figure 12. Selected biomarkers for determining the thermal maturity of different regions in the southeastern Junggar Basin.
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Figure 13. Experimental data of the calculated best-fit curve based on kinetic parameters for the hydrocarbon generation at the heating rate of 30 °C from this study.
Figure 13. Experimental data of the calculated best-fit curve based on kinetic parameters for the hydrocarbon generation at the heating rate of 30 °C from this study.
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Figure 14. Activation energy distributions of bulk petroleum generation for selected samples. A = frequency factor (s−1).
Figure 14. Activation energy distributions of bulk petroleum generation for selected samples. A = frequency factor (s−1).
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Figure 15. Determination of hydrocarbon expulsion threshold for (a–c) abundance and (d) thermal maturity of source rocks by hydrocarbon generation potential method (ANN: artificial neural networks).
Figure 15. Determination of hydrocarbon expulsion threshold for (a–c) abundance and (d) thermal maturity of source rocks by hydrocarbon generation potential method (ANN: artificial neural networks).
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Figure 16. The geochemical profiles of well-tie show the differences in the hydrocarbon generation potential between the lower and upper sections of P2l Formation.
Figure 16. The geochemical profiles of well-tie show the differences in the hydrocarbon generation potential between the lower and upper sections of P2l Formation.
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Figure 17. The extracted principal component shows the differential hydrocarbon generation potential of the source rocks of P2l in different areas.
Figure 17. The extracted principal component shows the differential hydrocarbon generation potential of the source rocks of P2l in different areas.
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Figure 18. Contour map of (a) the sedimentary facies of HST of P2l Formation, (b) thickness of mudstone, (c) TOC distribution characteristics, and (d) Ro values of source rocks around Bogeda Mountain in southeastern Junggar Basin.
Figure 18. Contour map of (a) the sedimentary facies of HST of P2l Formation, (b) thickness of mudstone, (c) TOC distribution characteristics, and (d) Ro values of source rocks around Bogeda Mountain in southeastern Junggar Basin.
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Table 1. Geochemical evaluation criteria for terrestrial source rocks (SY/T 5735-2019).
Table 1. Geochemical evaluation criteria for terrestrial source rocks (SY/T 5735-2019).
Organic matter abundanceSource Rock TypeEvaluation IndexNon-Source RockSource Rocks
PoorModerateGoodBest
Siliceous mudstoneTOC/%Immature–matureI–II1<0.30.3–0.50.5–1.01.0–2.0>2.0
II2–III<0.50.5–1.01.0–2.52.5–4.0>4.0
Mature–Post-matureI–II1<0.20.2–0.40.4–0.80.8–1.2>1.2
II2–III<0.350.35–0.60.6–1.51.5–3.0>3.0
Chloroform bitumen “A”/%<0.0150.015–0.050.05–0.10.1–0.2>0.2
HC/10−6<100.0100.0–200.0200.0–500.0500.0–1000.0>1000.0
S1 + S2/(mg/g)<0.50.5–2.02.0–6.06.0–20.0>20.0
Thermal maturityStageRo/%TTITmax (°C)C29 RS 20S/(20S + 20R)C29 RS ββ/(ββ + αα)
Immature0.5<15<435<0.2<0.2
Low mature0.5–0.715–75435–4400.2–0.40.20–0.45
Mature0.7–1.375–160>440–450>0.4>0.45
High mature1.3–2.0160–1500>450–580Equilibrium (0.52–0.55)Equilibrium (0.67–0.71)
Post-mature>2.0>1500>580
Type of kerogenTypeMaceral examinationRock pyrolysis
Exinite (%)Vitrinite (%)TIH/CO/CHI
Type I>70–90<10>80>1.5<0.1>700
Type II170–5010–2080–401.2–1.50.1–0.2700–350
Type II2<50–10>20–7040–00.8–1.20.2–0.3350–150
Type III<10>70–90<0<0.8>0.2<150
TypeBulk compositionMolecular biomarkers
Sat (%)Ash + Res (%)Sat/AroC27 RS/C29 RSMain peak carbon
Type I40–6020–40>3>2.0Front-high unimodal (C17–C19)
Type II130–4040–603.0–1.62.0–1.2Front-high bimodal (C17–C19, C21–C23)
Type II220–3060–701.6–1.0<1.2–0.8Post-high bimodal (C17–C19, C27–C29)
Type III<2070–80<1.0<0.8Post-high unimodal (C25, C27, C29)
Table 2. Comprehensively statistical table of organic element analysis, maceral compositions, vitrinite reflectance, and selected biomarkers of Lucaogou Formation (P2l) in southeastern Junggar Basin to determine the thermal maturity, organic matter (organic matter) abundance, and kerogen type of source rocks. (min~max/avg.(no.)); PI = S1/(S1 + S2); TI (%) = (Sapropelic (%) × 100 + Exinite (%) × 50 − Vitrinite (%) × 75 − Inertinite (%) × 100)/100); GPI = (S1 + S2)/TOC.
Table 2. Comprehensively statistical table of organic element analysis, maceral compositions, vitrinite reflectance, and selected biomarkers of Lucaogou Formation (P2l) in southeastern Junggar Basin to determine the thermal maturity, organic matter (organic matter) abundance, and kerogen type of source rocks. (min~max/avg.(no.)); PI = S1/(S1 + S2); TI (%) = (Sapropelic (%) × 100 + Exinite (%) × 50 − Vitrinite (%) × 75 − Inertinite (%) × 100)/100); GPI = (S1 + S2)/TOC.
AreaC29ββ/(ββ + αα)C2920S/(20S + 20R)Ts/(Ts + Tm)Roave (%)Tmax (°C)PIThermal Maturity Stage
Chaiwopu0.22~0.53/0.375 (58)0.06~0.60/0.3880.15~0.62/0.3950.60~1.71/1.082 (45)300~591/452.271 (124)0.000~0.600/0.1531 (129)Mature–post-mature
Miquan0.19~0.53/0.277 (26)0.13~0.75/0.3350.04~0.76/0.3720.40~1.38/0.679 (52)389~538/442.621 (233)0.000~0.377/0.0621 (295)Early mature–mature
Mulei0.33~0.53/0.449 (10)0.25~0.55/0.3890.05~0.72/0.3490.60~1.06/0.860 (26)434~506/461.081 (62)0.000~0.250/0.146 (62)Mature–post-mature
Qitai0.16~0.54/0.279 (45)0.06~0.49/0.2300.11~0.61/0.2360.46~1.24/0.777 (67)300~538/439.492 (429)0.001~0.601/0.0592 (509)Immature–early mature
Shiqiantan0.30~0.33/0.315 (2)0.04~0.26/0.1500.23~0.35/0.2900.55~1.19/0.957 (3)//Early mature–mature
Jimusaer0.19~0.48/0.297 (66)0.25~0.51/0.418/0.52~1.24/0.740 (49)374~454/436.975 (40)0.027~0.728/0.289 (40)Early mature–mature
AreaH/CO/CVitrinite (avg. %)Inertinite (avg. %)LiptiniteTI (%)HI (mg HC/g TOC)Kerogen type
Sapropelic (avg. %)Exinite (avg. %)
Chaiwopu0.638~1.996/0.984 (36)0.120~1.494/0.35141.061 15.501 16.687 26.751 7.279 (50)10.296~903.784/213.571 (117)Type III–II2
Miquan0.723~1.276/1.0825 (37)0.107~0.290/0.16410.405 17.583 50.737 21.275 28.581 (26)3.175~2690.910/404.785 (290)Type II1–II2
Mulei0.749~1.247/0.983 (7)0.149~0.296/0.21351.104 6.640 20.600 21.656 1.134 (25)23.810~64.257/44.224 (9)Type II2
Qitai0.908~1.621/1.031 (32)0.087~0.168/0.13421.003 5.811 67.438 5.748 50.234 (64)18.452~1437.396/515.579 (497)Type II1–I
Shiqiantan0.794~1.236/0.977 (3)0.136~0.346/0.254100.000 0.000 0.000 0.000 −1.125 (3)/Type II2
Jimusaer//4.000 0.500 66.000 29.500 77.250 (28)110.119~621.984/398.250 (20)Type II1–I
AreaPr/PhTOC (wt.%)S1 + S2 (mg HC/g Rock)GPIHC (mg/g)DBT/(DBT + DBF + Fl)Chloroform Bitumen “A”Organic matter abundance
Chaiwopu0.16~1.75/0.767 (58)0.012~10.31/1.801 (121)0.0328~83.810/5.502 (129)0.154~10.986/2.562 (117)0.497~868.000/68.930 (107)0.003~0.92/0.404 (14)0.0025~0.5777/0.0868 (42)Poor to fair
Miquan0.44~1.23/0.990 (26)0.0026~14.45/3.148 (308)0.027~72.545/12.257 (306)0.037~27.454/4.317 (290)0.623~503.846/47.477 (188)0.04~0.97/0.597 (23)0.0030~0.6600/0.1679 (81)Fair to good
Mulei0.13~1.37/0.804 (10)0.310~1.58/0.707 (26)0.05~1.930/0.319 (62)0.270~0.803/0.516 (9)5.358~16.064/11.410 (5)0.27~0.36/0.315 (2)0.0011~0.0306/0.0095 (16)Poor to fair
Qitai0.28~2.67/0.920 (45)0.017~39.72/4.529 (543)0.16~312.348/27.339 (509)0.202~14.654/5.367 (497)2.296~597.360/33.235 (338)0.07~0.88/0.520 (19)0.0076~1.2449/0.1751 (182)Good to excellent
Shiqiantan0.55~0.73/0.640 (2)////0.20~0.33/0.265 (2)0.0153~0.0786/0.0469 (2)Poor to fair
Jimusaer0.56~1.36/0.907 (66)0.840~8.49/3.744 (20)0.07~40.690/12.029 (40)1.363~7.571/4.455 (20)//0.0150~4.6550/0.6225 (53)Good to excellent
Table 3. Eighteen mudstone and shale samples with different maturities and regions were chosen for kinetics of petroleum generation analysis of P2l in the southeastern Junggar Basin.
Table 3. Eighteen mudstone and shale samples with different maturities and regions were chosen for kinetics of petroleum generation analysis of P2l in the southeastern Junggar Basin.
Sample No.S1 (mg/g)S2 (mg/g)Tmax (°C)PITOC (%)Kerogen TypeS1 + S2 (mg HC/g Rock)HI (mg HC/g TOC)
GDK-270.020.064440.080.42III0.0814
GDK-190.040.294380.330.4III0.3372
HYC-480.050.864370.911.17III0.9173
GDK-70.080.25910.280.45III0.2844
JJZG-20.235.174435.42.72II25.4190
HYC-Y110.236.884427.113.27II27.11210
HYC-170.2510.443810.653.53II110.65295
JJZG-360.58.574489.073.21II29.07267
JJZG-90.5517.2344617.783.72II117.78463
DHS-100.9432.2244033.168.36II133.16385
JJZG-430.961.694472.651.45III2.65117
HYC-Y131.1625.9143627.076.37II127.07406
JJZG-371.3857.0244658.413.96II158.4408
DHS-511.4634.6843036.1411.51II136.14301
DHS-571.743.134654.876.33II24.8749
DHS-312.5123.7644026.274.07I26.27585
DHS-203.3530.8243034.177.57II134.17407
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Zhang, G.; Yang, Y.; Liu, T.; Xu, Y.; Chang, X.; Qu, Y.; Shi, B.; Yang, B.; Song, T. Hydrocarbon Source Rock Evaluation of the Lucaogou Shale in the Periphery of Bogeda Mountain (SE Junggar Basin, China) and Its Implications for Shale Oil Exploration: Insights from Organic Geochemistry, Petrology, and Kinetics Pyrolysis. Processes 2024, 12, 356. https://doi.org/10.3390/pr12020356

AMA Style

Zhang G, Yang Y, Liu T, Xu Y, Chang X, Qu Y, Shi B, Yang B, Song T. Hydrocarbon Source Rock Evaluation of the Lucaogou Shale in the Periphery of Bogeda Mountain (SE Junggar Basin, China) and Its Implications for Shale Oil Exploration: Insights from Organic Geochemistry, Petrology, and Kinetics Pyrolysis. Processes. 2024; 12(2):356. https://doi.org/10.3390/pr12020356

Chicago/Turabian Style

Zhang, Guanlong, Yuqiang Yang, Tianjiao Liu, Youde Xu, Xiangchun Chang, Yansheng Qu, Bingbing Shi, Bo Yang, and Tao Song. 2024. "Hydrocarbon Source Rock Evaluation of the Lucaogou Shale in the Periphery of Bogeda Mountain (SE Junggar Basin, China) and Its Implications for Shale Oil Exploration: Insights from Organic Geochemistry, Petrology, and Kinetics Pyrolysis" Processes 12, no. 2: 356. https://doi.org/10.3390/pr12020356

APA Style

Zhang, G., Yang, Y., Liu, T., Xu, Y., Chang, X., Qu, Y., Shi, B., Yang, B., & Song, T. (2024). Hydrocarbon Source Rock Evaluation of the Lucaogou Shale in the Periphery of Bogeda Mountain (SE Junggar Basin, China) and Its Implications for Shale Oil Exploration: Insights from Organic Geochemistry, Petrology, and Kinetics Pyrolysis. Processes, 12(2), 356. https://doi.org/10.3390/pr12020356

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