The analyses were conducted at the China University of Petroleum (Beijing). First, the 146 rock samples were crushed to powder for TOC analysis (Table 1). In addition, the powdered samples were split into 200-mg subsamples and treated using HCl at 60°C to remove the carbonates and then washed using distilled water to remove the HCl. Finally, the washed subsamples were dried overnight at 50°C, and their carbon contents were determined using LECO CS–230 analyzers.

For rock-eval pyrolysis, 100 g of each crushed rock sample was placed in the vessel of an OGE-II instrument. These samples were heated from 300 to 600°C in a helium atmosphere at a heating rate of 50°C/min, and their Rock-Eval parameters (S₁, S₂, and T_max) were measured. In this study, S₁ is the amount of free hydrocarbon that can be volatilized from the rock sample (mg HC/g rock); S₂ is the amount of hydrocarbon produced by the cracking of organic matter (mg HC/g rock). T_max (°C) is the temperature at which the S₂ yield is maximized, which estimates the thermal maturity of the sediment (Peters, 1986).

Optical microscopy analyses were conducted on thin rock sections at the China University of Geoscience (Beijing) (Table 2). Before being embedded in a homogeneous mixture of Buehler’s epoxy resin and hardener (ratio 5:1), 11 core samples from eight wells were sectioned perpendicular to the bedding. The preparations involve drying and polishing, as described by Taylor et al. (1998) and Amijaya and Littke (2006). The thin rock sections were examined at different magnifications and under different light conditions (incident white- and blue-light excitation) to characterize the organic matter features of C₁s^b source rock. The optical instrument was a Nikon LV 100 microscope.

The vitrinite reflectances (R _o) of 46 samples were measured at the China University of Geoscience (Beijing) (Table 1), using a Zeiss Scope A1 incident light microscope at a wavelength (λ) of 546 nm. The reflectances of samples, rich in vitrinite or solid bitumen particles, were measured at least 50 times.

Mass spectrometry (MS) and gas chromatography MS (GC–MS) analyses were performed at the China University of Petroleum (Beijing). Soxhlet apparatus was used to extract 30 samples using CHCl₃ for 72 h. The resulting extracts were fractionated using open silica gel column chromatography with n-hexane. The resulting saturated hydrocarbons were analyzed using GC and GC–MS.

The GC analysis was performed in an Agilent 7890A gas chromatograph fitted with a 60 m × 0.25 mm × 0.25 µm capillary column with nitrogen (99.999%) as the carrier gas. The GC oven temperature was at 40°C for 10 min, and then, it ramped from 40 to 70°C at 4°C/min and 300°C at 8°C/min, and finally held at 300°C for 40 min.

The GC–MS analysis was performed in an Agilent 7890–5975C using the same column type as in the GC analysis but with helium (99.999%) as the carrier gas. During the GC–MS analysis, the GC oven temperature was held at 50°C for 1 min before it ramped to 120°C at 20°C/min, from 120 to 250°C at 4°C/min, and from 250 to 310°C at 3°C/min. Finally, it was held at 310°C for 30 min.

The geochemical analysis of the natural gas was conducted at the Experimental and Testing Institute of PetroChina Xinjiang Oilfield Company and Northwest Institute of Eco-Environment and Resources, Chinese Academy of Sciences. A Hewlett–Packard 6890 II gas chromatograph (GC) analyzed the natural gas components. The hydrocarbon gas component was separated using capillary columns (Plot Al₂O₃ 50 m × 0.53 mm). The furnace temperature of the GC was first set to be 30°C and held for 10 min. Then, the temperature was ramped up to 180°C at a rate of 10°C/min. Stable carbon isotope analysis of alkane gas (C₁–C₄) was conducted using a Finnigan Mat Delta S mass spectrometer interfaced with an HP 6890II gas chromatograph. The alkane gas components (C₁–C₄) and CO₂ were separated using a chromatographic column (Plot Q 30 m × 0.32 mm). The column heating process was as follows: the heating rate was 8°C/min at 35–80°C; the temperature was then increased to 260°C at a heating rate of 5°C/min. The final temperature was held for 10 min. Each sample was analyzed three times with an accuracy of ± 0.3‰ (VPDB).

The burial and thermal histories of the source rocks in the study area were reconstructed using PetroMod software. The current heat flow and thermal conductivity values of the source rocks were adopted from previous studies (Wang et al., 2000a,b; Qiu et al., 2000,2001; Qiu, 2002). The R _o values were calculated using the Easy%Ro model proposed by (Sweeney and Burnham, 1990; Ren et al., 2020). This model can be applied R _o ranging of 0.3–4.6%.

The type of organic matter determines the hydrocarbon-generating capacity and product type in a source rock (Tissot et al., 1984; Bordenave, 1993). Therefore, the organic macerals of source rocks and their assemblage characteristics can be studied to characterize the types of organic types (Tissot et al., 1984; Bordenave, 1993; Taylor et al., 1998; Suárez et al., 2012). In this study, the whole-rock maceral contents of C₁s^b source rocks with three different lithologies (coal, carbonaceous mudstone, and mudstone) in the Jimsar Sag were analyzed based on thin section, oil immersion, and fluorescence observations (Figure 2; Table 1). Organic macerals can be classified into four major groups: sapropelite, exinite, vitrinite, and inertinite (Tissot et al., 1984; Bordenave, 1993; Taylor et al., 1998; Suárez et al., 2012). The hydrocarbon generation capacity of the four macerals decreases sequentially, with their products transiting from liquid hydrocarbons to natural gas. The inert maceral group has almost no hydrocarbon-generating capacity.

The original matrices of the sapropelite maceral are primarily lower organisms (i.e., algal and bacteria) and zooplankton (Taylor et al., 1998; Suárez et al., 2012). This study is characterized by mineral bituminous exhibiting weak fluorescence (Figure 2). In addition, sporadically distributed alginate was found in the mudstone samples (Figures 2G,H). The primitive matrices of the exinite group are mainly the plant’s reproductive organs and the epidermis and secretions of branches, leaves, and roots (Tissot et al., 1984; Bordenave, 1993; Taylor et al., 1998; Suárez et al., 2012). The exinite maceral group in the C₁s^b source rocks of the Jimsar Sag mainly include microsporinite, liptodetrinite, cutinite, and resinite (Figure 2). Some dark striped vertical fractures are filled with sphaltenite (Figures 2D,E). The parent material of both the vitrinite and inertinite groups is the xylem of higher plants. The former formed in a reducing–semi-oxidizing environment and the latter in a semi-oxidizing–oxidizing environment (Tissot et al., 1984; Bordenave, 1993; Taylor et al., 1998; Suárez et al., 2012). In this study, the vitrinite maceral consists of telinite, collinite, semi-fusinite, and fusinite (Figure 2). Fragments of broken fusinite were visible in the center of some semifusinite (Figure 2C). Most of them preserved the woody cell structure, indicating that they underwent different degrees of cell wall swelling (Figure 2C). Various components can be seen in a parallel arrangement under the microscope, reflecting the hydrostatic sedimentary microenvironment (Figure 2B), confirmed by the widespread pyrite observed in C₁s^b source rocks (Figure 2).

The maceral components of the C₁s^b source rocks, with different lithologies in the Jimsar Sag, are dominated by the vitrinite group (>50%), reflecting their gas-prone characteristics (Figure 2; Table 1). The oil-prone maceral content (the sum of the sapropelite and exinite groups) of the mudstone and carbonaceous mudstone reached 22.3 and 16.9%, respectively (Table 1), showing a bit oil-generating potential (Figure 2; Table 1). The “oil stains” identified through fluorescence observation are evidence (Figure 2B).

The Rock-Eval hydrogen index [HI = (100 × S₂)/TOC] is a fast and economical method to distinguish organic matter types of the source rocks (Tissot et al., 1984; Bordenave, 1993). Based on the HI values of 600, 300–600, 200–300, 50–200, and less than 50 mg HC/g TOC, the organic matter can be classified into five types: Type I (extremely oil-prone), Type II (oil-prone), Type II/III (oil-prone/gas-prone), Type III (gas-prone) and Type IV (barren source rock) (Tissot et al., 1984; Bordenave, 1993). Among the C₁s^b source rocks of the Jimsar Sag, the HI values of mudstone, carbonaceous mudstone, and coal ranged from 32 to 216 mg HC/g TOC (average 140 mg HC/g TOC), 97–214 mg HC/g TOC (average 180 mg HC/g TOC), and 87–183 mg HC/g TOC (average 152 mg HC/g TOC), respectively (Figure 3; Table 2). The C₁s^b source rocks were dominated by kerogen type III. Carbonaceous mudstone is more oil-prone than coal, and mudstone has the poorest oil-generating capacity (Figure 3; Table 2). Some of the carbonaceous mudstone samples have high HI values (>200 mg HC/g TOC) and show some oil-generating capacities (Figure 3; Table 2). Among the C₁s^b source rocks in the Kelameili gas field, the average HI ratios for mudstone, carbonaceous mudstone, and coal are 106, 215, and 151 mg HC/g TOC, respectively, and the overall characteristics are close to those of the Jimsar Sag (Figure 3; Table 2).

In this study, R _o data were obtained for three C₁s^b source rock samples from the Jimsar Sag. The R _o value of the sample from well J15 (2860 m) is 0.65%, and the R _o values of the two samples from well J3301 (4,441 and 4,445 m) are 1.38 and 1.41%, respectively. Well J15 is in the eastern margin of the Jimsar Sag (Figure 1B) and has a lower maturity. According to the Ro values of well J3301, the C₁s^b source rocks have recently entered at least the main oil-generating window in the depression area. The Rock-Eval maturity indicators of C₁s^b source rocks in the study area and the Kelameili gas field are similar. Their hydrocarbon production indices [PI = S₁/(S₁+S₂)] and T_max are distributed between 0.8 and 1.0 and 440 and 460°C, respectively, in the main oil-generating window and samples with low PI and T_max values are in the immature stage (Figure 4; Table 2). A few samples with a poor correlation between PI and T_max may have suffered from the contamination of nonindigenous hydrocarbons (Figure 4). Some of the C₁s^b mudstone samples from the Kelameili gas field fall within the “inert carbon” (Figure 4), suggesting that those mudstone samples with low HI in Figure 3 have a poor initial hydrocarbon-generating capacity, in addition to the effect of thermal maturation.

Based on the R _o and T_max data of C₁s^b source rock samples from the Jimsar Sag and previous studies on the R _o-depth relationship in the eastern Junggar Basin (Gong et al., 2021), and combined with the tectonic map of the C₁s^b bottom boundary of the sag, the R _o contour map of the study area was plotted (Figure 5A). The area of the C₁s^b source rocks in the Jimsar Sag entering the main oil-generating window (R _o > 0.7%) and condensate-generating stage (R _o = 1.3–2.0%) reaches 980 and 490 km², respectively (Figure 5A). Considering that the humic source rocks produce large amounts of natural gas at the main oil-generating window (Dai et al., 1992; Petersen, 2002; Petersen and Nytoft, 2006; Petersen et al., 2011), the Jimsar Sag favor large- and medium-gas field formation.

In this study, a two-dimensional seismic profile, running longitudinally through the Jimsar Sag in a nearly north-south direction, was selected to recover the burial and thermal evolution history of the C₁s^b source rocks. At the end of the Carboniferous (∼305 Ma), the C₁s^b source rocks were in the immature–low maturity stage (R _o < 0.7%) and had not reached the main oil-generating window (Figure 6A). After that, the C₁s^b source rocks slowly subsided, and by the end of the Early Jurassic (∼182 Ma), they entered the early stage of the oil-generating window (R _o = 0.7–1.0%) (Figure 6B). Subsequently, the subsidence rate accelerated, and the C₁s^b source rocks entered the late stage of the oil-generating window (R _o = 1.0–1.3%) and the condensate/wet gas-generating window (R _o = 1.3–2.0%) stages in the Cretaceous (∼100 Ma). The R _o of the deepest part of the sag reached 1.7% (Figure 6C). In addition, regional tectonic uplift occurred in the study area, and the hydrocarbon-generating process of C₁s^b source rocks was temporarily stalled (Figure 6D). With further deep burial, the maturity of C₁s^b source rocks continues to increase. Recently, the deep C₁s^b source rocks in the Jimsar Sag have entered the massive condensate generation stage. In contrast, the maturity of source rocks at the edge of the sag is low, and a few of them enter the main oil-generating window (Figure 6E).

Humic source rocks form in fresh marsh-phase environments (oxidizing–semi-oxidizing), whereas lacustrine/marine source rocks form in reducing–semi-reducing environments (Tissot et al., 1984; Bordenave, 1993; Gong et al., 2019). Thus, there are differences in hydrocarbon-generating mechanisms and product types between the two. Their evaluation criteria should be more demanding than those for lacustrine/marine source rocks. The coaly source rocks are rich in aromatic functional groups and poor in lipid functional groups (carbon-rich and hydrogen-poor) and have high inert carbon content (Chen et al., 1997; Petersen, 2002; Petersen and Nytoft, 2006; Petersen et al., 2011). Based on thousands of Rock-Eval data of terrigenous source rocks of different lithologies in the major proliferous basins in northwest China, Chen et al. (1997) proposed a scheme to evaluate the hydrocarbon-generating potential of coaly (humic) source rocks using lithologies (mudstone, carbonaceous mudstone, and coal). This scheme has been well tested in the practice of evaluating terrigenous source rocks in China. This study evaluates the hydrocarbon-generating capacity of C1sb source rocks in Jimsar Sag based on this scheme.

The TOC of C₁s^b mudstone in the study area ranged from 0.57 to 5.89%, with an average of 1.96%; the hydrocarbon-generating potential (S₁+S₂) ranged from 0.88 to 10.37 mg HC/g rock, with an average of 2.87 mg HC/g rock. Thus, the C₁s^b mudstone belonged to medium–good source rocks (Figure 7A; Table 2). Chen et al. (1997) found that for carbonaceous mudstones and coal, the correlation between S₁+S₂ and HI is better than that between S₁+S₂ and TOC, and it is more suitable as an index for evaluating organic matter abundance. The C₁s^b carbonaceous mudstone is dominated by medium source rocks, with their S₁+S₂ and HI ratios being 23.47–55.60 mg HC/g rock (average 45.31 mg HC/g rock) and 97–214 mg HC/g TOC (average 180 mg HC/g TOC), respectively (Figure 7B; Table 2). The average S₁+S₂ and HI values of coal were 77.99 mg HC/g rock and 152 mg HC/g TOC, respectively, indicating a poor source rock (Figure 7C; Table 2). The hydrocarbon-generating capacity of C₁s^b source rocks in the Jimsar Sag and Kelameili gas fields is similar (Figure 7; Table 2).

One gas sample from the Carboniferous reservoir has been obtained in the Jimsar Sag (from well J3301). The methane content of the natural gas is 78.79%, and the drying factor (C₁/∑C_1–4) is 0.89, indicating a wet gas (C₁/∑C_1–4 < 0.95). The methane content of the natural gas from the Kelameili gas field ranged from 84.90 to 93.56%, with an average of 88.80%. The natural gases have their C₁/∑C_1–4 ratios ranging from 0.89 to 0.96 (average 0.92), and wet gas accounted for 85.9% of the total samples. The C₁/∑C_1–4 ratios of the gas from the Kelameili gas field are higher than those of the Jimsar Sag, reflecting a relatively higher thermal maturity.

The stable carbon isotope compositions of methane (δ¹³C-CH₄), ethane (δ¹³C-C₂H₆) and propane (δ¹³C-C₃H₈) in well J3301 are –33.8‰, –28.6‰, and –26.8‰, respectively (Figure 8). The δ¹³C-CH₄, δ¹³C-C₂H₆, and δ¹³C-C₃H₈ of natural gas from Kelameili gas field are –32.3‰ ∼ –29.2‰ (average –30.5‰), –28.9‰ ∼ –25.6‰ (average –27.1‰), and –26.8‰ ∼ –23.1‰ (average –24.7‰), respectively, which are more enriched in ¹³C than those of the gas from well J3301 (Figure 8). Considering similar carbon isotopic compositions of kerogen (δ¹³C_kerogen) in the C₁s^b source rocks of the Jimsar Sag and Kelameili gas field (Gong et al., 2019,2021), the difference in the stable carbon isotopic compositions of the two types of gas reflects the higher maturity of the gas in the Kelameili gas field, consistent with that in C₁/∑C_1–4 ratios. The humic source rocks are characterized by kerogen types III and II₂, composed of aromatic structures relatively enriched in ¹³C isotopes (Barry and Fang., 2014; Dai et al., 2014; Liu et al., 2008; Liu et al., 2019; Yao et al., 2020). In contrast, the sapropelic source rocks are characterized by kerogen types I and II₁, composed of aliphatic structures enriched in ¹²C isotopes (Barry and Fang., 2014; Dai et al., 2014; Liu et al., 2019; Wu et al., 2020). Therefore, when humic and sapropelic source rocks generate natural gas at similar maturity, the former generates natural gas (coal-type gas) with a more enriched ¹³C carbon isotope composition than the latter (oil-type gas).

Previous studies have confirmed that natural gas from the Kelameili gas field is derived from C₁s^b source rocks (Dai et al., 2016; Sun et al., 2016), which exhibit the characteristics of coal-type gas in the δ¹³C-CH₄–δ¹³C-C₂H₆–δ¹³C-C₃H₈ diagram proposed by (Dai et al., 2014) (Figure 8). The natural gas from well J3301 has ¹³C-CH₄, δ¹³C-C₂H₆, and δ¹³C-C₃H₈ values similar to those from the Kelameili gas field (Figure 8), demonstrating the gas was derived from C₁s^b source rocks. Although influenced by maturity, the δ¹³C-C₂H₆ values are more reflective of the original parent material and can distinguish coal-type gas from oil-type gas (Dai et al., 2005; Liu et al., 2016; Wu et al., 2021). Previous studies have shown that the limit of δ¹³C-C₂H₆ value for both is around –29.0‰ (Fu et al., 1990; Gang et al., 1997; Liu et al., 2004; Dai et al., 2005, 2014; Xiao Z. H. et al., 2008; Liang et al., 2013; Liu et al., 2016; Wu et al., 2021). The δ¹³C-C₂H₆ value of gas from well J3301 is –28.6‰, which shows the characteristics of coal-type gas (Figure 8).

Oil-type gas is drier than coal-type gas at the same thermal evolutionary stages (Bernard et al., 1978; Whiticar, 1999; Liu et al., 2019; Ci et al., 2020). In the δ¹³C-CH₄–C₁/C₂₊₃ gas genetic identification plate, gases from the J3301 well and Kelameili field gas fall in the evolution trend line of coal-type gas (Figure 9), reflecting their origin from C₁s^b source rocks. Figure 9 reflects the lower maturity of gas from well J3301 than gas from the Kelameili gas field.

Two sets of effective source rocks, i.e., P₂l and C₁s^b, were developed in the Jimsar Sag (the Middle and Lower Jurassic source rocks are immature). Previous studies showed that the P₂l source rocks are brackish lacustrine source rocks deposited in a reducing environment (Bai et al., 2017; Hu et al., 2018). The oil from the Jimsar billion-ton shale oil field is derived from this set of source rocks (Bai et al., 2017; Hu et al., 2018). The C₁s^b source rocks are a set of marine–terrigenous transitional deposits in an oxidizing environment with a predominantly terrestrial higher plant input (Gong et al., 2019,2021). A tiny amount of oil has been obtained in the Jimsar Sag from the Carboniferous weathered crust reservoir in well J15. This study compared the physical properties, biomarker fingerprints, and carbon-isotope characteristics of oil samples from well J15 with oil from the P₂l reservoirs in the Jimsar Sag.

As discussed in Section 4.2.1, sapropelic source rocks (P₂l) have more ¹³C-depleted δ¹³C_kerogen values than the humic source rocks (C₁s^b) when their maturity is close. In addition, the carbon isotopic composition of global Carboniferous sediments is enriched in ¹³C (Wang et al., 2013). Therefore, the carbon isotopes of oil derived from C₁s^b source rock should be more ¹³C-enriched than those from P₂l source rocks. The stable carbon isotopic compositions of saturated (δ¹³C_saturated) and aromatic (δ¹³C_aromatic) fractions of oil from well J15 are –26.7‰ and –25.9‰, respectively. The δ¹³C_saturated and δ¹³C_aromatic values of P₂l reservoired oil in the study area are –33.4‰ to –29.8‰ (average –31.9‰) and –31.4‰ to –27.6‰ (average –30.4‰), respectively, which are lower than those in the J15 well. Therefore, the J15 oil should be derived from C₁s^b source rock.

The β-carotene is associated with anoxic/saline environments (Jiang and Fowler, 1986; Peters et al., 2005). The prevalence of β-carotene is a characteristic of Permian-sourced oils in the Junggar Basin (Wang et al., 2013; Cao et al., 2020). In this study, β-carotene was undetected in the oil from well J15 (Figure 11A), whereas some amount of β-carotene was detected in the P₂l reservoired oil (Figure 11D), reflecting the different genetic sources of the two.

The main precursors of pristane (Pr) and phytane (Ph) are chlorophylls of photosynthetic organisms, and their abundance is related to the sedimentary environment (Powell, 1988; Peters et al., 2005). The high Pr/Ph value of 1.76 for oil from well J15 (Figure 10B, Figure 11A) indicates an oxidizing environment with abundant terrigenous organic matter input Powell, corresponding to the C₁s^b source rock. In contrast, Pr/Ph values for oil from the P₂l reservoir are lower, ranging from 0.83 to 1.52, with an average of 1.30 (Figure 10B, Figure 11D), reflecting that the source rocks were deposited in a reducing–oxidizing transitional environment dominated by algal and bacterial inputs, with some input from the terrigenous higher plant (Powell, 1988; Peters et al., 2005).

Note:1) n-C₁₇; 2) Pr; 3) n-C₁₈; 4) Ph; 5) β-carotene; 6) C₁₉ tricyclic terpane; 7) C₂₀ tricyclic terpane; 8) C₂₁ tricyclic terpane; 9) C₃₀ hopane (10) gammacerane 11) C₃₁ hopane20S 12) pregnanes 13) ααα-C₂₈20S-regular sterane 14) αββ-C₂₈20R-regular sterane 15) αββ-C₂₈20S-regular sterane 16) ααα-C₂₈20R-regular sterane 17) ααα-C₂₉20S-regular sterane 18) αββ-C₂₉20R-regular sterane 19) αββ-C₂₉20S-regular sterane (20)ααα-C₂₉20R-regular sterane.

The gammacerane reflects the stratified water in the depositional environments in which different source rocks were developed (Peters et al., 2005). The stratified water is due to the longitudinal salinity gradients (Sinninghe et al., 1995; Vu et al., 2009). An increase in water salinity increases the gammacerane index [gammacerane/(gammacerane + C₃₁ hopane)] and decreases the Pr/Ph values (Sinninghe et al., 1995; Vu et al., 2009). The P₂l reservoired oils have a higher gammacerane index of 0.35–0.65 (average 0.46), showing that they were derived from a set of saline and reducing source rock (Figure 10B, Figure 11E). In contrast, the gammacerane index of oil from well J15 is lower at 0.30 (Figure 10B, Figure 11B), indicating a set of fresh source rock (Sinninghe et al., 1995; Vu et al., 2009), corresponding to the C₁s^b source rocks.

The oil density from well J15 is 0.7898 g/cm³, approximately 0.1 g/cm³ lower than that of the P₂l reservoired oil (0.8352–0.9732 g/cm³, average 0.8809 g/cm³), indicating that they may have different genetic sources (Figure 10C). A higher abundance of C_31–35 hopane is a feature of the marine environment (Peters et al., 2005). The ƩC_31–35/C₃₀ hopane ratio of the P₂l reservoired oil is low, ranging from 0.56 to 0.86 (average 0.74) (Figure 10C). In contrast, the ƩC_31–35/C₃₀ hopane ratio of oil from well J15 is higher, 0.96 (Figure 10C), corresponding to the depositional environment of C₁s^b source rock whose sediment environment was affected by seawater (Du, 2010).

From the ααα-20R-C₂₈/C₂₉ sterane ratio, the difference between the oil from well J15 and P₂l reservoir is negligible (Figure 10D, Figures 11C,F). However, the relative content of C₂₉ regular steranes in oil from well J15 was low at 45.86% compared to 48.08–52.43% (average 50.12%) for the P₂l reservoired oil (Figure 10D, Figures 11C,F). High levels of C₂₉ steranes indicate significant plant biomass input, reflecting a poor organic matter type (Volkman, 1986; Schwark and Empt., 2006), which seems to be the opposite of the situation in the study area. In previous studies, abundance C₂₉-regular steranes appeared in some algae, such as diatoms and green algae (Orcutt and Patterson, 1975; Grantham, 1986; Volkman, 1986). However, the abundance of C₂₉ steranes in oil does not signify that most organic matter comes from vascular plants. One possible explanation is that the C₂₉-regular steranes in P₂l reservoired oil may come from specific zooplankton that feeds on algae and bacteria. Similar situations have appeared in Paleozoic oils in Oman and the Tarim Basin in China (Grantham, 1986; Zhang and Cheng, 2021).