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Fossil Fuels
Lake level controls on oil shale distribution in the Lucaogou Formation, Wujiawan area, Junggar Basin, northwest China yuanji li, Pingchang Sun, Zhaojun Liu, junxian wang, yue li, and meiqi zhang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b01884 • Publication Date (Web): 18 Aug 2019 Downloaded from pubs.acs.org on August 19, 2019
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Lake level controls on oil shale distribution in the Lucaogou
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Formation, Wujiawan area, Junggar Basin, northwest China
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Yuanji Li1,2, Pingchang Sun1, 2*, Zhaojun Liu1,2*, Junxian Wang1,2, Yue Li1, Meiqi Zhang1,2 1. College of Earth Sciences, Jilin University, Changchun, Jilin 130061, China 2. Key-Lab for Oil Shale and Paragenetic Minerals of Jilin Province, Changchun, Jilin 130061, China
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*Corresponding author: College of Earth Sciences, Jilin University, Jianshe str. 2199,
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Changchun 130061, China.
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Tel.: 0086 13674313295
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Fax: 0086 43188502603
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E-mail addresses:
[email protected] and
[email protected] 33
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Abstract: A thick section of upper Permian, high-quality oil shale is present in the Lucaogou Formation on the northern flanks of Bogda Mountain, which is located in the southern Junggar Basin, northwest China. However, the distribution of these oil shales has yet to be studied. Based on 56 boreholes and associated oil yield analytical data in the area of Wujiawan in the south Junggar Basin, we investigated the distribution and formation of these oil shales. The oil shales in the Lucaogou Formation have an average oil yield of 6.09 wt.%, and the maximum is 22.27 wt.%. According to the borehole and oil yield data, the oil shale formed in a third-order sequence and was deposited mainly in transgressive system (TST) and high stand tracts (HST). The oil shale has an average TOC content of 12.12 wt.%, and the average petroleum potential is 66.54 mg/g. The TST oil shale mainly contains type II kerogen, which was derived from terrestrial sources and lake algae. The oil shale deposited during the early stages of the TST occurs locally distributed and occurs as lens-shaped bodies. As the lake level rose, the area over which the oil shale was deposited gradually increased, along with the thickness, extent, and oil yield. The oil shale layers increase in average thickness from 6.69 to 11.36 m, from the base to top of the TST, and the average oil yield increases from 5.66 to 6.90 wt.%. In the HST, the oil shale has an average TOC content of 20.56 wt.%, the average petroleum generation potential (S1+S2) is up to 130.41 mg/g, the organic matter type is largely type I kerogen and dominantly lake algae. The HST oil shale is thick (up to 130 m), layered, and continuously and widely distributed. Several parasequences can be identified in a single layer of oil shale, and the average thickness and oil yield of each parasequence is 10.13–12.47 m and 5.27–7.07 wt.%, respectively. The curve change trends of V/(V-Ni), Ni/Co and Cu/Zn are divided into three stages: Phase I, Rise (TST); Phase II, High-Value Zone (HST); and Phase III, Stable Zone (HST). A similar trend of change was found in comparisons between the central and eastern regions, which showed that with the rise of a lake’s plane, the lake changes from an oxygen-poor to an oxygen-deficient condition, which increases the space and is conducive to the formation of oil shale. Keywords: Junggar Basin; upper Permian; Lucaogou Formation; oil shale characteristics; lake level; oil shale distribution
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1. Introduction
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Oil shale in China is an organic-rich and combustible rock with a high ash content (>40 wt.%) that upon low-temperature heating generally produces >3.5 wt.% of oil. The organic matter content (i.e., sapropel, humosapropel, or sapropel–humus) of oil shale is high and the calorific value is >4.18 kJ/g. The lower limit of industrial usefulness (i.e., oil yield and calorific value) can vary as the economic conditions and technology for oil shale development change.1 Given the global shortage of energy and the recovery of international oil prices since entered 21st century, the large oil shale resources available worldwide have become an important supplementary source of oil and gas.
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The Junggar Basin is located in western China and is a large oil-bearing basin. Thick, good quality, oil shales are present on the northern flanks of Bogda Mountain along the southern margin of the Junggar Basin (Fig. 1a).2,3 A large number of studies have discussed the factors controlling oil shale deposits, including base level changes, tectonics, climate, global anoxic events, transgression and hydrothermal events.4–8 Within the framework of a stratospheric formation, high-quality oil shale develops mainly near the largest lake, meaning the transgressive system (TST) and the high stand tracts (HST).9–12 Therefore, a higher lake plane will lead to the formation of hypoxic conditions in the lake basin, which is conducive to the preservation of organic matter because the lake settlement rate is low, thus avoiding the dilution of organic matter.13– 16 The pattern of organic material accumulation in parasequence is strongly dependent on the source of organic matter and lake plane changes.16–17
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Previous studies have focused on a series of oil-bearing shale outcrops or boreholes through single oil shales along the northern flanks of Bogda Mountain, which have revealed the lateral and vertical distribution of the oil shales.16-23 The oil shale distribution has not been studied in detail from a sequence stratigraphic framework. In this study, 56 boreholes were examined from the Wujiawan area of south Jungar Basin (Fig. 1b). Data from these boreholes allow the lateral and vertical distribution of the oil shales to be linked to a sequence stratigraphic framework, enabling identification of the key factors controlling oil shale accumulation. In combination with previous research results in other areas of the northern foot of the Bogda Mountains, we studied the relationship between the distribution and quality of oil shale and lake levels in the middle and eastern part of the northern foot of the Bogda Mountains, and revealed the key factors controlling the temporal and spatial distribution of oil shale in that area.
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2. Geological setting
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Bogda Mountain is located in the eastern Tianshan along the southern edge of the Junggar Basin. This basin is a large foreland basin containing organic-rich sediments.2,24,25 A thick sequence of organic-rich oil shales deposited in a lacustrine setting is present at this location.22 Carroll et al identified three formations that contain organic-rich oil shales: the Jingjingzigou, Lucaogou, and Hongyanchi formations (from oldest to youngest).18 The Lucaogou Formation contains organic-rich oil shales that are 3
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oil-prone (Fig. 1a).
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Since the late Hercynian, the region has undergone 4 stages and 3 stages of tectonic evolution. Late Hercynian tectonic movement played a crucial role in the formation of the basin’s tectonic framework. There are late Paleozoic middle Permian, Mesozoic Triassic, Mesozoic Lower Jurassic and Cenozoic tectonic layers in the study area. It consists mainly of the Upper Permian Lucaogou Formation, the Hongyanchi Formation, the Quanzijie Formation, the Wutonggou Formation, the Guodikeng Formation, the Lower Triassic Jiucaiyuanzi Formation, the Shaofanggou Formation, the Middle-Upper Triassic Karamay Formation, the Upper Triassic Huangshanjie Formation, the Lower Jurassic Badaowan Formation and the Sangonghe Formation (Fig. 1c).21,26,27 The oil shale is mostly deposited in the Lucaogou Formation of the Middle Permian. The Lucaogou Formation primarily develops black oil shale deposits; gray-black, blackbrown and black medium-fine sandstone; sandy shale; and mudstone interbedded deposits. According to lithological assemblage, it can be divided into four lithologic segments, where oil shale occurs mainly in the second, third and fourth members of the Lucaogou Formation.28
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3. Samples and methods
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Oil yield analysis was performed on multiple samples that represent a 1-m-thick interval, based on 2121 samples in 56 boreholes. These analyses were carried out by Xingjiang Baoming Mining Company following the Chinese standard SH/T0508-92. In addition, 26 oil shale samples were collected from depths of 280–600 m in the 23-4 borehole. All the samples were black oil shales and mudstones.
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Rock-Eval pyrolysis, total organic carbon (TOC; in wt.%) analyses, organic microscopy, and Ro determinations were undertaken on these 26 samples (Fig. 3). TOC contents were measured with a LECO CS-400 instrument and Rock-Eval pyrolysis was undertaken with a Rock-Eval 6 instrument using conventional procedures. Kerogen was extracted according to the GB/T 19144-2010 standard. Kerogen was examined in thinsections with a Zeiss Axio Scope A1 under transmitted and fluorescent light, with ≥300 maceral points being counted in each sample. The dominant particle size of the maceral group (50 vol.%) was used to estimate the contents of amorphinite, alginate, liptinite, vitrinite, and inertinite, according to Chinese Petroleum and Natural Gas Industry Standards SY/T 5125-1996. The vitrinite reflectance (Ro) of 6 samples was measured with a MSP 200 micro-spectrophotometer, and at least 20 points were examined in each sample ， Subsequently, muffle furnace (Xl-2000), blast dryer (101A-2E) and calorimeter were used to analyze and test these samples in accordance with the standard of GB/T 212-2008. All analyses were conducted at the Key Laboratory of Oil Shale and Symbiotic Energy Minerals of Jilin Province, China. High-resolution inductively coupled plasma–mass spectrometry (ICP–MS) was used to determine trace-element . Trace elements were measured following the procedures specified in Chinese standard GB/T 14506.28-93. Tests were completed at the Beijing Institute of Geology of the Nuclear Industry, Beijing, China. 4
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Stratigraphic sequence analysis, based on the thicknesses and yields of oil shales in the 56 boreholes (Fig. 1b), was undertaken to reconstruct the lateral and vertical distribution of oil shale.
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4. Results
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4.1 Oil yield
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Based on the oil yield (ω), the oil shales were divided into three types: low quality (3.5 wt.% < ω ≤ 5.0 wt.%), medium quality (5 wt.% < ω ≤ 10 wt.%), and high quality (ω > 10 wt.%).28 From the 2121 oil yield analyses of the 56 borehole cores, 1973 samples have ω > 3.5 wt.% (i.e., are defined as oil shales). The percentage of oil shale samples is 93.02% and the average oil yield is 6.41 wt.%. High-quality oil shales comprise 9% of the samples (the maximum oil yield 22.27 wt.%; average = 12.10 wt.%), medium-quality oil shales comprise 54% of the samples (average oil yield = 6.72 wt.%), and low-quality oil shales comprise 30% of the samples (average oil yield = 4.27 wt.%) (Fig. 2).
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4.2 Total organic carbon content
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The 26 oil shales from the 23-4 borehole yield TOC contents of 3.48–16.91 wt.% (Table 1). TOC shows a significant positive correlation with oil yield (R2 = 0.95), with TOC = 1.19ω + 1.17 (Fig. 3a). As such, when the abundance of organic matter is >5.34 wt.%, the oil shale boundary is reached. The boundaries of the medium- and high-quality oil shale occur at organic matter abundances of 7.17 and 13.07 wt.%, respectively.
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4.3 Rock-Eval pyrolysis
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Rock-Eval pyrolysis of 12 samples (Table 1) showed that the hydrocarbon shale petroleum potential (S1+S2) (PP) is 12.62–145.84 mg/g and the hydrogen index (HI) is 215–858 mg/g. The oil yield of the oil shale has a significant positive correlation with the petroleum potential (S1+S2) (R2 = 0.85), with PP = 10.11ω-13.60 (Fig. 3b). The petroleum potential boundaries of the low-, medium-, and high-quality oil shales are 21.79, 36.95, and 87.50 mg/g, respectively. TOC and S2 also show a positive correlation (R2 = 0.82), with S2 = 8.11TOC – 20.75 (Fig. 3c). The Tmax value varies between 416 and 459°C.
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4.4 Industrial analysis
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The volatile contents in the oil shale vary between 12.15 and 21.54 wt.% (average = 14.72 wt.%) and the calorific values are 1681–6522 KJ/g (average = 3389 KJ/g) (Fig. 4a, b). The oil yield correlates positively with the volatile content and calorific value, with correlation coefficients of 0.89 and 0.98, respectively. The ash yield varies between 76.51 and 84.38 wt.% (average = 80.61 wt.%), and the water yield between 0.93 and 1.86 wt.% (average = 1.38 wt.%). The oil yield correlates negatively with the ash and water contents, with correlation coefficients of 0.85 and 0.81, respectively (Fig. 5
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4c, d). In general, the samples are high-ash, low-calorific oil shales.
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4.5 Organic petrography and vitrinite reflectance (Ro) data
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The oil shales contain organic macerals that are mainly lamalginite (Fig. 5a–d), sporinite (Fig. 5c, d), vitrinite (Fig. 5e, g, h), and inertinite (Fig. 5f, h). The content of algae is high, ranging from 63.3 to 80.2 vol.%. The sporinite content varies from 6.1 to 13.8 vol.%, the vitrinite content is 2.8–18.1 vol.%, and the inertinite content is 3.2–14.7 vol.%. Ro values of six samples vary between 0.90% and 0.95% (Table 2).
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4.6 Trace elements
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The contents of V, Ni, Co, Cu and Zn in oil shale in the study area were analyzed. The contents of V ranged from 28 to 140 ppm, Ni ranged from 21.6 to 52.3 ppm, Co, Cu and Zn ranged from 8.3 to 23.1 ppm, 36.7 to 100 ppm and 46.5 to 169.9 ppm, respectively.
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4.7 Sequence stratigraphy and oil shale occurrence
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A systems tract is a combination of sedimentary systems that formed at the same time, broadly equivalent to a parasequence group. A parasequence group can be divided into aggradational, progradational, and retrogradational stages.29,30 Creaney and Pessey studied in detail the TOC contents of marine source rocks as a function of system domain, and found that the maximum TOC content is often related to the maximum sea level.30 Liu et al reported that the oil yield has a positive linear relationship with the TOC content, and a sudden increase in the oil yield occurs above the lower interface of a parasequence.31
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Unconformities and lakeside sediments are rarely observed in the present study area. The drilling data were used to divide the oil shale-bearing layers into three lithological intervals from bottom to top: (1) oil shale and silty mudstone with thicknesses of 5–10 m; (2) oil shale (20–60 m thick) interbedded with thin (1–5 m) silty mudstone; and (3) oil shale (20 m thick) interbedded with silty mudstone. These lithologies were deposited in shallow–deep–shallow water depths, respectively, and represent transgressive system (TST) and high stand (HST) tract deposition of a third-order sequence. The TST resulted in four oil shale layers (T-1 to T-4) and the HST also resulted in four oil shale layers (H-1 to H-4).
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According to the positive linear relationship between oil yield and total organic carbon content, the oil yield at the bottom interface of parasequences suddenly increases. Then, system tracts are divided according to the combination characteristics of low oil-bearing shale series, gradually increasing oil-bearing shale series, high oil-bearing shale series and low oil-bearing shale series, which correspond to LST, TST, HST and RST (Fig. 6 and 7).31 4 parasequences were identified in the TST (Fig. 6), and the bottom of each oil shale is the base of each parasequence. Seven parasequences were identified in the HST, where the H-1 oil shale layer contains two parasequences (H-1a to H-1b), and the H-3 oil shale layer contains three parasequences (H-3a to H-3c) (Fig. 6 and 7). 6
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4.8 Oil shale distribution in the sequence stratigraphic framework
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4.8.1 Vertical distribution
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2 layers of super-thick oil shale and six layers of thin oil shale are developed vertically in oil shale drilling in the study area. The oil shale numbers for the super-thick layers are H-1 and H-3. The oil-bearing curves of the H-1 layers show high oil-bearing values and numerous zigzag shapes. The oil-bearing curves of the H-3 layers show small changes and low-amplitude teeth shapes. These two sets of oil shale layers with differing thicknesses are widely developed in the study area, even in the northern foot of the Bogda Mountains, and are the marker layers for lateral correlation in the region. Thin oil shale is numbered T-1-T-4, H-2 and H-4, with the H-2 and H-4 layers located in the middle of the H-1 and H-3 layers and above the H-3 layers. Those layers are thin lenticular oil shales; the T-1-T-4 layers are all located below H-1 layers, where the thickness of oil shale from the T-4 to T-1 layers decreases gradually, and the change of oil-bearing curve also decreases gradually. According to their vertical division, the oil shale layers in the study area are comparatively analyzed horizontally (Fig. 6). We reconstructed the vertical distribution of the oil shale in the study area. At the beginning of the TST, the oil shale distribution and thickness are small, and the oil shales occur as lens-shaped deposits (T-1 and T-2) (Fig. 6). With rising lake level, the oil shale gradually became laterally more extensive, forming widespread layers of greater thickness (T-3 and T-4) (Fig. 6).
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The HST was dominated by the deposition of two widely distributed oil shale layers of great thickness (single layers with a cumulative thickness of up to 130 m; H-1 and H3) (Fig. 6). Towards the end of the HST setting, thinner oil shales were deposited, and the oil shales again occur as lens-shaped deposits (H-4) (Fig. 6). Notably, H-2 between the H-1 and H-3 layers is thin and lens-shaped (Fig. 6).
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4.8.2 Lateral distribution
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At the beginning of the TST (T-1 and T-2), oil shale was only deposited in the northwestern region of the studied area. With rising lake level (T-3 and T-4), the area of oil shale deposition gradually expanded and the thickness of each oil shale layer increased to 37.62 m, with an weighted oil yield of 5.09–5.94 wt.%. The quality of the ∑n𝑖 = 0ℎ𝑖 × 𝑤𝑖
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oil shale improved at this stage（weighted oil yield=
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Layered test thickness; w: Layered test oil yield; H: Test total thickness.）.
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Oil shale in the HST is distributed across most of the study area (from H-1 to H-3), and is thickest in the southeast, northwest, and central parts of the areas. In general, these two oil shale layers are much thicker than the TST oil shales. In particular, the H-1 layer is thick, with a total maximum thickness of ≤130 m (Fig. 7). The oil yield and quality show no obvious lateral variability, and the weighted oil yield is mainly 5.75–7.52 wt.% (Fig. 7).
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At the end of the HST (H-4), the area of oil shale decreased significantly and was 7
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, n: Number of tests; h:
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concentrated in the central and southeastern regions, with thicknesses of 6.61–18.64 m (Fig. 7). At this time, a localized region with a high oil yield formed in the southeastern part of the studied area (Fig. 7). The H-2 oil shale layer was deposited mainly in the eastern region of the studied area, and contains numerous locations with a high oil yield (Fig. 7).
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In general, in the TST the oil shale distribution gradually increased, indicating a continuous rise in lake level. In the HST, the oil shale had the greatest lateral distribution, formed the thickest deposits, and had the highest quality (oil yields of up to 22.27 wt.%). At the end of the HST, the distribution and thickness of the oil shale decreased (H-4), but the oil yield changed little.
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4.8.3 Distribution of a single parasequence in each large oil shale layer (HST)
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The oil shales of each parasequence in the HST (H-1 and H-3) (Fig. 7), apart from H3c, have a similar thickness and distribution as the other parasequences, with oil shale layers that are mostly 8.37–18.74 m thick. The weighted oil yield is high in the west (5.09–9.73 wt.%) and relatively low in the east (3.46–6.40 wt.%).
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5. Discussion
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5.1 Organic matter type and source
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HI–Tmax and S2–TOC plots and observations of organic macerals can be used to determine the organic matter type in oil shales.32-34 The oil shale HI values that formed during the TST stage are 215–639 mg/g, with Tmax values of 416–454°C, which plot in the upper region of the field for type II kerogen (Fig. 8). In a S2–TOC diagram, the data plot in the field for type II kerogen, with HI = 200–700 mg/g and an organic matter type that is mainly type II1 kerogen (saprolite–sapropel type) (Fig. 8). The alginite content in the TST period varies from 63.6 to 76.1 vol.%, and the proportion of terrestrially derived organic matter is 23.9 to 36.7 vol.%. This shows that organic matter in the TST period originated from terrestrial plants and lake algae (Table 2; Fig. 5).
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The HI values of oil shales deposited in the HST period are 534–858 mg/g, the Tmax values are 441–459°C, and the data plot in the field for type I kerogen in the HI–Tmax graph (Fig. 8). Oil shale in the HST has high S2 and TOC contents (Table 1). Therefore, the HST oil shale is mainly type I (sapropel-type) (Fig. 8). The alginite content in the HST period is 80.2% and the terrestrially derived organic matter content is 19.8%, indicating that the organic matter was dominantly lake algae (Table 2; Fig. 5).
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5.2 Generation potential of oil shale hydrocarbon
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Plots of petroleum potential (PP)–TOC, HI–TOC, and S2–TOC can reveal the potential for oil shale to produce hydrocarbons.35,36 TST samples have TOC contents from 3.48 to 31.17 wt.%, PP values from 5.78–201.4 mg/g, and HI values of 215–639 mg/g. The data are shown in PP–TOC and HI–TOC diagrams in Fig. 9. The oil shale deposited in the TST is a good source rock, indicating that the oil shale deposited during this stage 8
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is prone to generate oil during the low temperature distillation heating process.
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The HST oil shale has TOC contents of 10.32–34.75 wt.%, PP values of 30.03–202.17 mg/g, and HI values of 466.89–858 mg/g (Table 1). This shows that the PP and TOC content of oil shale deposited in the HST are much higher than those in the TST. The PP–TOC and HI–TOC diagrams also indicate that HST oil shale is an ideal source rock (Fig. 9), with a high organic matter content and potential for hydrocarbon generation, indicating it should be the main exploration target.
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5.3 Organic maturity
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The studied oil shale was deposited during the upper Permian. After oil shale deposition, the Junggar Basin experienced long-term tectonic subsidence and sedimentary infilling from the Triassic–Jurassic.2,31,24 Subsequently, thrust faulting exposed oil shale along the northern flanks of Bogda Mountain, which resulted in uplift of 1000 m in the Cenozoic.37 Tmax and Ro values relate to the maturity of organic matter in oil shales.38 Tmax values of 416–459°C (Table 1) and Ro values of 0.90%–0.94% (Table 2) indicate that the oil shale is mature.
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5.5 Paleoclimate
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A paleoclimate can be represented by V/(V + Ni), where V/(V + Ni) is >0.60, indicating an anaerobic sedimentary environment; V/(V + Ni) of 0.45–0.60, indicating an oxygenpoor sedimentary environment; and V/(V + Ni) of
