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. 2021 Jan 14;6(3):2127–2142. doi: 10.1021/acsomega.0c05224

Identification of Oil Produced from Shale and Tight Reservoirs in the Permian Lucaogou Shale Sequence, Jimsar Sag, Junggar Basin, NW China

Lianhua Hou 1,*, Xia Luo 1,*, Zhongying Zhao 1, Lijun Zhang 1
PMCID: PMC7841958  PMID: 33521452

Abstract

graphic file with name ao0c05224_0016.jpg

The Permian Lucaogou Formation of the Jimsar Sag in the Junggar Basin, NW China, is one of the largest areas of oil exploration and exploitation in the lacustrine shale sequence in China. Oil is commercially extracted from this markedly heterogeneous formation, which is characterized by frequently interbedded shale and tight reservoirs, although producible intervals within the Lucaogou Formation remain unresolved. This study focused on the Jimsar Sag reservoirs to investigate petrological and mineralogical characteristics, source rock and reservoir physical properties, and the molecular biogeochemistry of core extracts and crude oils. The i-C18/n-C18 and Pr/n-C19 ratios of two-step ultrasonic extracts were applied to infer whether the oil is produced from shale or tight reservoirs, taking into account solvent polarity, molecular characteristics of n-alkanes and isoprenoids, and physical properties of the reservoir. The experimental results indicated that the shallower pay zone is mainly produced from tight reservoirs, while in deeper zone with organic-matter maturity above 1.0%, some of the oil is produced from shale. The reservoir properties in organic-rich shale with vitrinite reflectance (Ro) exceeding 1.0% are improved by pore interconnectivity, and oil mobility is enhanced by high gas/oil ratios, which favors production of free-phase hydrocarbons. Such zones may become major prospects for shale oil exploration and production. The results of the present study can potentially apply to sweet-spot identification and development optimization for the Lucaogou shale and other lacustrine shale sequences.

1. Introduction

The exploration and commercial development of shale oil have expanded rapidly in many countries in recent years.1−5 In 2019, the daily crude oil production in the USA, for example, was 12.26 MMb d–1, of which 65.17% or 7.99 MMb d–1 was produced from shale sequences.6 Large shale oil resources have recently been discovered in Chinese lacustrine basins with organic-rich shale and strongly heterogeneous sequences, such as in the Ordos, Songliao, Junggar, and Bohai Bay basins.7−13 The Middle Permian Lucaogou Formation (P2l) in the Jimsar Sag of the Junggar Basin, NW China, is one of the main areas of lacustrine shale oil exploration and exploitation in China.14−16 Oil production has shown that the Lucaogou Formation has upper and lower sweet spots, both characterized by marked heterogeneity and frequent interbedded shale and tight reservoirs.17,18 The current exploration target is focused on the tight oil reservoirs of the formation16 because whether oil in shale is also a potential exploration target remains uncertain. A method to determine whether the oil is produced from shale in the Lucaogou Formation needs to be clarified. Oil in shale or tight reservoirs has different accumulation features and exploitation-controlling factors.19−23 The distinction between oil from shale and tight reservoirs is therefore fundamental to the evaluation of layers favorable for exploration and the optimization of development plans.

Previous studies of the Lucaogou Formation have focused mainly on the origin and pore structure of tight reservoirs,24−26 the geochemical characteristics and distribution of shale,27−30 the evaluation of oil content,31−33 and the migration and accumulation of oil.34,35 The actual producible intervals (shale, tight, or hybrid oil) have barely been defined. Some studies have investigated oil-source correlation by routine geochemical techniques and concluded that Lucaogou oil is an in situ or near-source accumulation, with oil in the tight reservoirs being generated from adjacent shale.28,36,37 Other studies start to consider shale oil resources and regard middle shale in the lower Lucaogou Formation as a free enriched interval and potential target for exploration.32,38 However, features of oil produced from shale have not been differentiated from oil produced from tight reservoirs within the same shale sequence in previous studies. Meanwhile, factors controlling shale sequence oil production have not been thoroughly investigated.

This study focuses on a method establishment for the identification of oil produced from shale and tight reservoirs in the same shale sequence package. Various extraction experiments with different solvents were undertaken with shale and tight-reservoir samples, followed by geochemical analysis of these extracts and the produced oil samples. Based on biomarker correlations between shale and tight-reservoir extracts, geochemical indicators were established to distinguish between shale and tight-reservoir oils from the same package of shale deposits, facilitating to determine the contribution of oil produced from a fractured shale sequence. The major controlling factors for mass production of free hydrocarbons from shale have been discussed. Our results are not only relevant to the exploration of lacustrine shale formations in Junggar Basin but also deepen our understanding on similar lacustrine shale basins globally.

2. Results

2.1. Lithofacies

Core and thin-section observations indicate that the shale lithology includes shale and silty, calcareous, and dolomitic shale; tight-reservoir samples include siltstone, argillaceous and dolomitic siltstone, dolomite, and limestone, as shown in core and thin-section photomicrographs (Figure 1). XRD analysis (Figure 2) indicates that the samples comprise quartz (12.4–40.2%; average 29.3%), K-feldspar (up to 17.9%; average 6.0%), plagioclase (12.3–50.3%; average 29.1%), calcite (up to 41.1%; average 9.1%), dolomite (3.1–45.3%; average 18.0%), and clay minerals (up to 20.8%; average 8.5%).

Figure 1.

Figure 1

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Core samples of shale and tight reservoirs, Lucaogou Formation, Jimsar Sag. (a) Calcareous shale, thin section, sample 9; (b) photomicrograph of sample 9 under blue light; (c) cast thin section, sample 9; (d) dolomitic siltstone, thin section of sample 8; (e) photomicrograph of sample 8 under white light; (f) cast thin section, sample 8. H, humosapropelinite; MB, mineral–bitumen; Ed, exinite debris; Q, quartz; Cl, clay; Do, dolomite; SFd, semi-fusinite debris.

Figure 2.

Figure 2

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Mineral composition of the Lucaogou Formation, Well J174, Jimsar Sag.

Maceral composition study indicates that shale samples are enriched in organic matter. Humosapropelinite (H) strips, mineral–bitumen (MB) matrix, microsporinite (Mi), and exinite debris (Ed) are common, and they appear yellow to orange in incident blue light (Figure 1). Humosapropelinite and MB are distributed parallelly to the bedding surfaces; while Mi and Ed are scattered in the samples. Vitrinite (V) and fusinite debris (Fd) are rare. Tight-reservoir samples contain little organic matter with occasional occurrence of semi-fusinite debris (SFd) (Figure 1).

2.2. Source Rock Characteristics

TOC and pyrolysis analyses (Table 1) indicate that the shale samples are superior to tight-reservoir samples in terms of organic-matter content and potential for hydrocarbon generation in the lower and upper members of the Lucaogou Formation (P2l1 and P2l2, respectively). TOC contents are in the range of 1.59–25.52% (average 7.29%) for shale samples and 0.07–0.79% (average 0.35%) for tight-reservoir samples. Pyrolysis analysis of shale samples indicates that S1 contents are in the range 0.07–2.64 mg HC g–1 rock (average 0.70) and S2 contents are in the range 6.87–109.41 mg HC g–1 rock (average 41.99). Results for tight-reservoir samples show that S1 contents are in the range 0.04–0.18 mg HC g–1 rock (average 0.10) and S2 contents are in the range 1.10–1.93 mg HC g–1 rock (average 1.38).

Table 1. Characteristics of Core Samples from the Lucaogou Formation, Jimsar Sag.

well name formation sample number depth (m) lithology TOC (%) S1 (mg g–1) S2 (mg g–1) Tmax (°C) porosity (%) Ro (%)
J174 P2l2 1 3114.27 silty shale 2.69 0.26 7.96 438   0.67
    2 3127.93 siltstone 0.79 0.18 1.26 435 13.10  
    3 3135.13 siltstone 1.18 0.04 4.64 438 16.20  
    4 3146.10 shale 2.06 0.09 9.38 437 5.90 0.69
    5 3199.99 argillaceous siltstone 0.20 0.12 1.16 435 10.90  
    6 3207.28 dolomitic shale 3.03 0.17 20.45 442 8.90 0.63
  P2l1 7 3263.29 dolomitic siltstone 0.75 0.12 1.93 435 10.20  
    8 3274.87 dolomitic siltstone 0.30 0.08 1.28 439 13.90  
    9 3276.65 calcareous shale 9.50 0.42 54.08 437 5.30 0.76
    10 3279.11 dolomitic shale 7.99 0.47 52.51 439 5.06 0.78
    11 3285.99 argillaceous siltstone 0.20 0.09 1.10 434 13.27  
    12 3313.18 calcareous shale 7.44 0.74 50.99 440 5.90  
    13 3323.38 shale 4.45 0.20 28.45 436 3.60 0.81
J36 P2l1 14 4213.5 shale 7.54 0.57 32.90 448   1.01
    15 4216.5 shale 8.50 0.42 37.47 449 5.00  
J31 P2l1 16 2863.58 shale 1.59 0.07 6.87 440   0.63
    17 2896.75 siltstone 0.36 0.04 0.28 442 12.60  
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Ro analysis indicates the occurrence of mature organic matter in the Lucaogou Formation, with measured Ro values in the range of 0.63–1.01%. The Ro values are well correlated with burial depth, as illustrated in Well J36, which was drilled into the deeper parts of the Jimsar Sag (Figure 3).

Figure 3.

Figure 3

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Ro–depth plot in the Lucaogou Formation, Jimsar Sag.

2.3. Physical Properties of the Reservoir

Helium porosity values (Table 1) indicate that shale porosities are in the range of 3.6–8.9% (average 6.0%), much lower than those of tight-reservoir samples (10.2–16.2%; average 12.8%). MICP and NMR analysis results (Table 2) indicate that shale samples have smaller pore throat radii and more complicated pore structures than tight-reservoir samples. For samples of the same lithology, P2l2 samples exhibit smaller pore throat radii and more complicated pore structures than P2l1 samples. Capillary pressure curves from MICP analyses (Figure 4) indicate that shale samples have smaller pore throat radii (see Table 2 note for definitions; Rmax = 0.05–0.09 μm), higher entry pressure (Pcd = 8.26–15.20 MPa), and lower mercury displacement efficiency (We = 21.85–25.68%) than tight-reservoir samples with Rmax = 0.94–1.45 μm, Pcd = 0.51–0.78 MPa, maximum mercury saturation (Smax) = 81.91–82.04%, and We = 38.71–40.40%. NMR T2 distribution curves for four water-saturated samples after centrifugation (Figure 5) indicate that pore throat radii are generally >0.05 μm and the mobile fluid content is 8.26–19.02% in the shale samples and 56.87–61.45% in the tight-reservoir samples. Mobile fluids were observed to concentrate in pores with throat radii of 0.1–0.5 μm (Table 2).

Table 2. Pore Throat Structural Parameters from MICP and NMR Analysisa.

    MICP
 NMR (movable fluid saturation, %)
sample munber lithology Pcd (Mpa) Rmax (μm) Smax (%) We (%) 0.05–0.1 μm 0.1–0.5 μm 0.5–1.0 μm >1.0 μm >0.05 μm
2 siltstone 0.78 0.94 82.04 38.71 15.68 28.26 5.57 7.36 56.87
4 shale 15.20 0.05 60.69 25.68 2.99 3.12 1.58 0.57 8.26
10 dolomitic shale 8.26 0.09 82.10 21.85 8.15 8.55 1.60 0.72 19.02
11 argillaceous siltstone 0.51 1.45 81.91 40.40 9.34 21.16 15.73 15.21 61.45
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a

Note: Pcd = entry capillary pressure corresponding to continuous entry of the nonwetting phase to the maximum pore throat; Rmax = maximum radius of the pore throat; Smax = maximum mercury saturation (mercury saturation at the highest experimental pressure); and We = ratio of mercury volume withdrawn and injected in the mercury displacement experiment.

Figure 4.

Figure 4

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Mercury capillary pressure curves for shale and tight reservoirs in the Lucaogou Formation, Jimsar Sag. (a) Siltstone in P2l2, sample 2; (b) shale in P2l2, sample 4; (c) argillaceous siltstone in P2l1, sample 11; (d) dolomitic shale in P2l1, sample 10.

Figure 5.

Figure 5

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NMR T2 distribution curves for shale and tight reservoirs in the Lucaogou Formation, Jimsar Sag. (a) Siltstone in P2l2, sample 2; (b) shale in P2l2, sample 4; (c) argillaceous siltstone in P2l1, sample 11; (d) dolomitic shale in P2l1, sample 10.

2.4. Molecular Geochemical Characteristics

Biomarkers obtained from the GC and GC–MS analyses include n-alkanes, isoprenoids, terpanes, and steranes. Biomarker parameters determined by peak areas are listed in Tables 3 and 4.

Table 3. Parameters Derived from n-Alkanes and Isoprenoids in the Lucaogou Formation Core Extracts and Oil Samples, Jimsar Saga.

sample number lithology type extraction method Cmax CPI Σn-C21–/Σn-C22+ Pr/n-C17 Ph/n-C18 Pr/Ph i-C15/n-C15 i-C16/n-C16 i-C18/n-C18 Pr/n-C19 Ph/n-C20
1 Sh So 23 1.06 0.90 1.05 1.05 1.20 0.29 0.68 0.70 1.08 0.90
1 Sh U1 23 1.05 0.73 0.98 1.03 1.08 0.03 0.38 0.69 1.13 0.97
1 Sh U2 23 1.05 0.50 1.24 1.25 0.90 0.00 0.00 0.44 0.99 1.03
2 T So 23 1.08 0.73 1.22 1.46 1.05 0.00 0.25 0.75 1.11 1.13
2 T U1 23 1.09 0.72 1.03 1.21 1.02 0.00 0.45 0.72 1.14 1.11
2 T U2 23 1.06 0.69 1.25 1.43 1.00 0.00 0.24 0.70 1.10 1.11
3 T So 23 1.07 0.72 1.22 1.33 1.04 0.36 0.89 0.87 1.13 1.04
3 T U1 23 1.10 0.77 1.05 1.17 1.10 0.18 0.54 0.78 1.17 1.05
3 T U2 23 1.08 0.69 1.26 1.32 1.12   0.36 0.77 1.15 1.03
4 Sh So 23 1.08 0.70 0.54 0.38 1.29 0.17 0.36 0.30 0.35 0.25
4 Sh U1 23 1.07 0.84 0.51 0.42 1.20 0.08 0.42 0.40 0.42 0.33
4 Sh U2 23 1.07 0.58 0.59 0.47 1.13 0.00 0.19 0.34 0.39 0.30
5 T So 23 1.08 1.09 1.26 1.28 1.23 0.44 0.99 0.94 1.29 1.08
5 T U1 23 1.09 0.98 1.30 1.24 1.24 0.42 0.91 0.87 1.27 1.01
5 T U2 23 1.08 0.82 1.46 1.34 1.24 0.09 0.83 0.90 1.30 1.05
6 Sh So 23 1.06 0.67 1.34 1.37 1.21 0.31 0.77 0.85 1.35 1.00
6 Sh U1 23 1.09 1.21 1.14 0.94 1.46 0.22 0.51 0.75 1.21 0.84
6 Sh U2 23 1.09 0.88 1.22 0.91 1.27 0.00 0.41 0.48 0.92 0.70
7 T So 17 1.06 1.03 1.78 2.39 1.05 0.48 1.16 1.30 2.18 2.13
7 T U1 17 1.07 0.89 1.70 2.37 1.00 0.06 0.84 1.32 2.27 2.20
7 T U2 17 1.06 0.90 1.77 2.29 0.94 0.09 0.77 1.28 2.20 2.24
8 T So 17 1.06 0.97 1.43 2.25 1.05 0.38 0.97 1.23 2.22 2.29
8 T U1 17 1.06 1.05 1.61 2.27 1.02 0.18 0.96 1.27 2.22 2.28
8 T U2 17 1.06 0.91 1.60 2.35 0.96 0.09 0.85 1.29 2.20 2.18
9 Sh So 17 1.03 0.59 1.30 2.00 1.08 0.46 1.02 1.23 2.17 2.12
9 Sh U1 17 1.02 1.58 1.04 1.46 0.98 0.03 0.52 0.99 1.91 1.98
9 Sh U2 17 1.04 0.85 1.41 1.76 0.98 0.26 0.70 0.86 1.66 1.81
10 Sh So 17 1.03 0.61 1.22 1.85 1.08 0.41 1.02 1.41 2.32 2.32
10 Sh U1 17 1.02 1.51 1.13 1.58 0.97 0.00 0.24 0.94 1.97 2.27
10 Sh U2 17 1.04 0.78 1.35 1.88 0.98 0.00 0.15 0.75 1.85 2.08
11 T So 17 1.06 0.95 1.49 2.25 1.10 0.42 1.00 1.43 2.40 2.39
11 T U1 17 1.06 0.92 1.59 2.24 1.00 0.09 0.85 1.26 2.19 2.09
11 T U2 17 1.07 0.92 1.57 2.23 0.99 0.09 0.85 1.27 2.21 2.11
12 Sh So 17 1.06 1.63 1.23 2.08 1.13 0.36 1.00 1.39 2.42 2.51
12 Sh U1 17 0.98 1.41 1.14 1.43 1.19 0.52 1.02 1.07 1.99 2.06
12 Sh U2 17 0.98 1.41 1.14 1.43 1.19 0.05 0.51 0.94 1.69 1.71
13 Sh So 17 1.03 3.52 0.94 1.46 1.19 0.44 1.14 1.34 2.34 3.06
13 Sh U1 17 1.02 1.50 1.27 1.60 1.09 0.23 0.99 1.14 1.88 1.91
13 Sh U2 17 1.01 1.28 1.29 1.57 1.06 0.21 0.77 0.97 1.67 1.74
14 Sh So 17 1.05 0.79 0.96 0.97 1.20 0.22 0.60 0.68 1.21 1.00
14 Sh U1 17 0.98 0.59 0.86 1.10 0.92 0.15 0.46 0.69 1.19 1.05
14 Sh U2 17 1.06 0.65 1.01 0.90 1.32 0.00 0.38 0.67 1.00 0.74
15 Sh So 17 1.09 2.03 0.96 1.15 1.10 0.34 0.65 0.75 1.11 1.22
15 Sh U1 17 1.03 1.13 0.82 0.99 1.20 0.02 0.04 0.73 1.19 1.25
15 Sh U2 17 0.99 1.06 0.88 0.96 0.85 0.00 0.00 0.39 0.78 0.96
16 Sh So 23 1.08 0.92 1.22 1.05 1.24 0.32 0.62 0.65 0.95 0.74
16 Sh U1 23 1.07 0.62 0.95 0.77 1.10 0.18 0.38 0.40 0.62 0.52
16 Sh U2 23 1.07 0.63 0.75 0.65 1.04 0.00 0.11 0.29 0.52 0.42
17 T So 23 1.07 0.83 1.02 0.86 1.23 0.27 0.54 0.56 0.84 0.67
17 T U1 23 1.10 0.64 0.81 0.69 1.12 0.16 0.44 0.56 0.77 0.63
17 T U2 23 1.08 0.46 1.02 0.89 1.13 0.00 0.00 0.52 0.77 0.65
J174 oil in shale     23 1.07 0.84 0.58 0.43 1.32 0.08 0.42 0.44 0.47 0.34
J174 produced oil     17 1.06 1.25 1.69 2.32 1.07 0.27 1.35 1.43 2.37 2.33
J31 produced oil     23 1.06 0.82 1.07 0.88 1.23 0.35 0.69 0.60 0.83 0.63
J36 produced oil     17 1.06 1.19 1.19 1.26 1.15 0.49 0.89 0.81 1.29 1.12
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a

Note: Sh = shale; T = tight reservoirs; So = Soxhlet extraction; U1 = ultrasonic extraction step 1 (n-hexane); U2 = ultrasonic extraction step 2 (chloroform); Cmax = main carbon peak number; CPI = carbon preference index; Pr = pristane; and Ph = phytane.

Table 4. Parameters Derived from Terpanes and Steranes in the Lucaogou Formation Core Extracts, Jimsar Saga.

                  sterane abundance
sample number lithology type extraction method Tm/Ts gammacerane/C31 hopane tricyclic terpane/hopane C32 hopane S/(S + R) C29 ββ/(αα + ββ) C29 ααα20S/(S + R) C27 C28 C29
2 T So 10.26 0.57 0.25 0.57 0.31 0.45 0.12 0.43 0.46
2 T U1 10.18 0.60 0.29 0.60 0.32 0.49 0.13 0.42 0.45
2 T U2 9.71 0.60 0.26 0.60 0.32 0.45 0.12 0.42 0.46
8 T So 14.77 0.61 0.23 0.59 0.30 0.45 0.15 0.41 0.44
8 T U1 17.53 0.58 0.23 0.59 0.30 0.47 0.10 0.41 0.48
8 T U2 14.22 0.59 0.25 0.58 0.30 0.47 0.11 0.42 0.47
9 Sh So 18.22 0.76 0.34 0.60 0.29 0.46 0.15 0.41 0.44
9 Sh U1 16.97 0.67 0.33 0.58 0.28 0.46 0.12 0.42 0.46
9 Sh U2 17.24 0.69 0.26 0.60 0.28 0.47 0.12 0.42 0.46
10 Sh So 8.90 0.43 0.24 0.58 0.28 0.43 0.12 0.44 0.44
10 Sh U1 20.43 0.66 0.29 0.57 0.27 0.45 0.11 0.42 0.47
10 Sh U2 12.67 0.58 0.24 0.59 0.28 0.40 0.12 0.41 0.48
12 Sh So 3.65 0.61 0.18 0.56 0.25 0.49 0.16 0.37 0.47
12 Sh U1 3.36 0.56 0.21 0.56 0.25 0.46 0.16 0.40 0.44
12 Sh U2 3.48 0.56 0.19 0.59 0.24 0.44 0.16 0.39 0.45
13 Sh So 3.02 0.62 0.18 0.59 0.30 0.45 0.17 0.37 0.46
13 Sh U1 2.73 0.62 0.21 0.57 0.29 0.47 0.17 0.38 0.45
13 Sh U2 3.65 0.61 0.18 0.56 0.30 0.49 0.16 0.37 0.47
14 Sh So 9.40 0.58 0.19 0.59 0.36 0.48 0.15 0.42 0.43
14 Sh U1 7.23 0.62 0.25 0.60 0.36 0.48 0.15 0.43 0.42
14 Sh U2 7.54 0.63 0.25 0.60 0.36 0.48 0.15 0.42 0.42
15 Sh So 11.07 0.73 0.24 0.60 0.36 0.47 0.17 0.40 0.43
15 Sh U1 11.59 0.70 0.30 0.59 0.36 0.46 0.16 0.40 0.44
15 Sh U2 12.78 0.79 0.29 0.61 0.36 0.45 0.16 0.40 0.44
17 T So 10.11 0.85 0.28 0.58 0.33 0.40 0.12 0.41 0.47
17 T U1 7.14 0.64 0.25 0.59 0.33 0.46 0.16 0.40 0.44
17 T U2 7.32 0.64 0.22 0.60 0.32 0.48 0.16 0.40 0.44
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a

Note: Sh = shale; T = tight reservoirs; So = Soxhlet extraction; U1 = ultrasonic extraction step 1 (n-hexane); U2 = ultrasonic extraction step 2 (chloroform); and tricyclic terpane/hopane = (C19–C31) tricyclic terpanes/(C30–C35) pentacyclic hopanes.

The n-alkane distributions in tight-reservoir and shale extracts obtained by the different methods are shown in Figure 6a–c,d–f, respectively. The carbon preferential index (CPI) values are ranging from 0.98 to 1.10, and Σn-C21–/Σn-C22+ ratios are ranging from 0.46 to 3.52 (average 0.99) (Table 3). Pr and Ph occur in all samples with Pr/n-C17, Ph/n-C18, and Pr/Ph ratios of 0.51–1.78, 0.38–2.39, and 0.85–1.46, respectively (Table 3). Farnesane (i-C15), iso-hexadecane (i-C16), and nor-pristane (i-C18) are clearly identified. The i-C15/n-C15, i-C16/n-C16, i-C18/n-C18, Pr/n-C19, and Ph/n-C20 ratios are 0–0.52, 0–1.35, 0.29–1.43, 0.35–2.42, and 0.25–3.06, respectively (Table 3).

Figure 6.

Figure 6

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Gas chromatograms of extracts from shale and tight reservoirs, obtained with different extraction methods. (a) Dolomitic siltstone, sample 8, U1; (b) dolomitic siltstone, sample 8, U2; (c) dolomitic siltstone, sample 8, S; (d) calcareous shale, sample 9, U1; (e) calcareous shale, sample 9, U2; (f) calcareous shale, sample 9, S. U1, ultrasonic extraction, step 1 (n-hexane); U2, ultrasonic extraction, step 2 (chloroform); S, Soxhlet extraction.

Terpane biomarkers identified from m/z 191 mass chromatograms are dominated by C30-hopane and C29-norphane, with moderate amounts of C31–C35 homohopanes and C19–C26 tricyclic terpanes (Figure 7). Gammacerane/C31 hopane and C32 hopane 22S/(22S + 22R) values range from 0.43 to 0.85 and 0.56 to 0.61, respectively (Table 4). 17α(H)-22,29,30-trisnorhopane (Tm) is significantly higher than 18α(H)-22,29,30-trisnorneohopane (Ts), with Tm/Ts ratios of 2.73–20.43 (Table 4).

Figure 7.

Figure 7

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Mass chromatograms of saturated fractions for shale and tight reservoirs in the Lucaogou Formation, Jimsar Sag. (a) Dolomitic siltstone, sample 8, m/z 191; (b) dolomitic siltstone, sample 8, m/z 217; (c) calcareous shale, sample 9, m/z 191; (d) calcareous shale, sample 9, m/z 217.

Sterane biomarkers, identified from the m/z 217 mass chromatograms, occur in the representative samples, with C29 sterane predominated (Figure 7). The relative abundance of C27, C28, and C29 sterane is 0.10–0.17, 0.35–0.44, and 0.42–0.49, respectively (Table 5). Most C29 ααα 20S/(20S + 20R) ratios are >0.4 and C29 ββ/(αα + ββ) ratios are >0.3, suggesting that the Lucaogou oil is generally mature (Table 4).

Table 5. Characteristics of Produced-Oil Samples from the Lucaogou Formation (Data from Xinjiang Oil Company).

        group component (%)
well name depth (m) density (g cm–3) viscosity (50 °C mPa·s) sat. HC aro. HC NSO Asph.
J174 3255.00–3314.00 0.92 196.2 42.53 15.70 36.87 4.91
J31 2875.00–2916.00 0.91 132.9 48.61 19.09 28.59 3.70
J36 4209.00–4255.00 0.88 71.4 55.29 16.79 25.14 2.77
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3. Discussion

3.1. Biomarker Differences between Shale and Tight Reservoirs

The Soxhlet extracts from shale and tight-reservoir samples have similar n-alkane, isoprenoid, terpane, and sterane contents (Tables 3 and 4; Figure 7). These biomarker proxies for oil source, maturity, and migration cannot distinguish between shale and tight reservoirs due to the overlap in values between these reservoir types (Figure 8). Pr/Ph and gammacerane/C31 hopane ratios were in the respective ranges of 1.08–1.29 and 0.43–0.76 for shale and 1.04–1.23 and 0.57–0.85 for tight reservoirs. C29 ββ/(αα + ββ) and C29 ααα 20S/(20S + 20R) ratios were in the respective ranges of 0.24–0.36 and 0.43–0.49 for shale and 0.30–0.33 and 0.40–0.45 for tight reservoirs. Tm/Ts and tricyclic terpane/hopane ratios were in the respective ranges of 3.02–18.22 and 0.18–0.34 for shale and 10.11–14.77 and 0.23–0.28 for tight reservoirs.

Figure 8.

Figure 8

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Biomarker parameter plots for Soxhlet extracts from shale and tight reservoirs. (a) (Pr/Ph)–(Σn-C21–/Σn-C22+); (b) (Pr/n-C17)–(Ph/n-C18); (c) (i-C18/n-C18)–(Pr/n-C19); (d) (C29 ααα20S/(S + R))–(C29 ββ/(αα + ββ)); (e) (C32 hopane (S/S + R))–(tricyclic terpane/hopane); (f) (gammacerane/C31 hopane)–(Tm/Ts).

The similarity of biomarker parameters for shale and tight-reservoir samples can be attributed to the recovery of all hydrocarbons (free and adsorbed) by Soxhlet extraction, from all storage places (micrometer–nanometer scale pores).39 Previous studies have shown that Lucaogou oil is characterized by near-source accumulation, with oil in tight reservoirs originating in proximal shale without long-distance migration.17,37 This could account for the similarity in biomarker values between shale and tight reservoirs.

Ultrasonic extracts (steps 1 and 2) from shale and tight-reservoir samples have similar terpane and sterane contents but different n-alkane and isoprenoid contents (Tables 3 and 4; Figure 9). These extracts exhibit terpane and sterane profiles similar to those of Soxhlet extracts and cannot distinguish between shale and tight reservoirs. However, the ultrasonic extracts exhibit similar n-alkane and isoprenoid distributions in extracts from both steps for tight-reservoir samples but different distributions between steps for shale samples (Figure 6).

Figure 9.

Figure 9

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Biomarker parameter plots for ultrasonic extracts from shale and tight reservoirs, from step 1 (n-hexane) and step 2 (chloroform). (a) (Pr/Ph) vs (Σn-C21–/Σn-C22+); (b) (Pr/n-C17) vs (Ph/n-C18); (c) (i-C18/n-C18) vs (Pr/n-C19); (d) (C29 ααα 20S/(20S + 20R)) vs (C29 ββ/(αα + ββ)); (e) (C32 hopane (22S/(22S + 22R))) vs (tricyclic terpanes/hopanes); (f) (gammacerane/C31 hopane) vs (Tm/Ts).; U1 = ultrasonic extraction step 1 (n-hexane); U2 = ultrasonic extraction step 2 (chloroform).

The ratio of isoprenoids to n-alkanes with the same carbon number depends on the extraction method and lithology when the organic input of source rocks is the same. There are no clear patterns regarding the ratios of light hydrocarbons such as i-C15 and i-C16 (Table 3), possibly due to the loss of these compounds by evaporation during the experiment. The ultrasonic-extract i-C18/n-C18 and Pr/n-C19 distributions in steps 1 and 2 differ between shale and tight-reservoir samples (Figure 9c), with marked variation in two extraction steps (without overlap) for shale samples. In contrast, i-C18/n-C18 and Pr/n-C19 ratios are consistent between two extraction steps for tight-reservoir samples, with almost equal ranges (Figure 10). P2l1 and P2l2 shale and tight-reservoir ultrasonic extracts display markedly different i-C18/n-C18 and Pr/n-C19 distributions between extraction steps (Figure 10), attributable to different organic inputs of source rocks. Previous studies have shown that, compared to P2l1, the organic matter sources and depositional paleoenvironments of P2l2 changed frequently due to changes in lake water levels, with depositional conditions changing gradually from brackish, stratified, suboxic–anoxic to aerobic freshwater.17,40 It follows that consistency of the organic input is a fundamental condition for identifying oil produced from shale or tight reservoirs in the same shale sequence package and that oil in P2l1 and P2l2 should be identified separately.

Figure 10.

Figure 10

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I-C18/n-C18 and Pr/n-C19 plots for ultrasonic extracts from shale and tight reservoirs, steps 1 and 2. (a) i-C18/n-C18 Step 2 vs i-C18/n-C18 Step 1; (b) Pr/n-C19 Step 2 vs Pr/n-C19 Step 1.

P2l1 tight-reservoir ultrasonic extracts from Well J174 have similar i-C18/n-C18 and Pr/n-C19 ratios in steps 1 and 2, with average values of 1.28 and 2.20, respectively (Figure 10; Table 3). In contrast, step 1 P2l1 shale ultrasonic extracts have higher i-C18/n-C18 and Pr/n-C19 ratios (averages 1.03 and 1.94, respectively) than step 2 extracts (averages 0.88 and 1.71, respectively) (Figure 10; Table 3). P2l2 shale and tight-reservoir ultrasonic extracts from Well J174 have i-C18/n-C18 and Pr/n-C19 ratios similar to those of P2l1 extracts from both extraction steps, but with lower values (Figure 10; Table 3). The i-C18/n-C18 and Pr/n-C19 ratios for P2l2 tight-reservoir ultrasonic extracts (averages 0.79 and 1.18, respectively) are very similar between extraction steps (Figure 10). For P2l2 shale ultrasonic extracts, the respective average i-C18/n-C18 and Pr/n-C19 ratios are 0.62 and 0.92 in Step 1 and 0.42 and 0.77 in step 2. For Wells J36 and J31, shale and tight-reservoir ultrasonic extracts have i-C18/n-C18 and Pr/n-C19 ratios similar to those of both extraction steps for Well J174.

The differences in i-C18/n-C18 and Pr/n-C19 ratios between extraction steps can be attributed to three factors: solvent polarity, the molecular characteristics of n-alkanes and isoprenoids, and the physical properties of the reservoir. The polarity of n-hexane is lower than that of chloroform (0.06 and 4.4, respectively, at 20 °C), so isoprenoids are more easily extracted by n-hexane. Step 1 of the ultrasonic extraction, with hexane, therefore extracts mainly free alkanes from rock micropores, including C12–C30n-alkanes and isoprenoids.41 Step 2, with chloroform, extracts mainly free hydrocarbons and some hydrocarbons adsorbed in nano–micropores, including alkanes, aromatic hydrocarbons, nonhydrocarbons, and pre-existing asphaltene.

Isoprenoids have a more symmetric molecular structure than n-alkanes of the same carbon number and are therefore less polar. I-C18 and Pr, with four regular lateral chains and approximately cylindrical structures, have lower polarity than n-C18 and n-C19 alkanes,42 with Pr having the lowest solubility in water (1.0 × 10–8 mg L–1 at 25 °C; cf. n-C19, 3.7 × 10–5 mg L–1) and the corresponding lowest polarity. Because n-hexane is less polar than chloroform, i-C18 and Pr dissolve more readily in n-hexane than n-C18 and n-C19 alkanes. Therefore, step 1 ultrasonic extracts tend to have higher i-C18/n-C18 and Pr/n-C19 ratios than step 2 extracts (Table 3).

Physical properties of the reservoir have the greatest effect on extraction. Tight-reservoir samples have better reservoir properties, with an average porosity of 12.8% (Table 1), and hydrocarbons (mainly free hydrocarbons) in pore spaces can be extracted with both n-hexane and chloroform. Steps 1 and 2 ultrasonic extracts therefore exhibit similar biomarker parameters (Table 3). Shale samples have worse reservoir properties, with an average porosity of 6% (Table 1). Shales also have a capacity for hydrocarbon generation. Previous studies have shown that free and adsorbed hydrocarbons coexist in Lucaogou shale, with early hydrocarbons usually occurring in an adsorbed state.43−45 The adsorbed hydrocarbons cannot be extracted with weakly polar n-hexane but can be extracted with chloroform, resulting in differences between biomarker distributions between step 1 and step 2 ultrasonic extracts (Table 3). A density comparison indicates that i-C18 and Pr have higher density and lower molecular volume than n-alkanes of the same carbon number, making it easier for isoprenoids to migrate through micro- and nanopores in the shale sequence. Hydrocarbons accumulating in tight reservoirs with no generation capacity have migrated from nearby shale, while hydrocarbons in shale have accumulated in situ, without migration after their generation. Tight reservoirs therefore have i-C18/n-C18 and Pr/n-C19 ratios higher than those of proximal shale (Figure 10).

3.2. Identification of Oil-Producing Rocks in the Jimsar Sag

Values of two key biomarkers in oil samples (Table 5), namely, i-C18/n-C18 and Pr/n-C19 ratios, were compared with ratios in shale and tight-reservoir ultrasonic extracts (steps 1 and 2) to identify the Lucaongou oil-producing rocks, with their correlation demonstrating that i-C18/n-C18 and Pr/n-C19 ratios can be used as indicators of oil identification. Oil samples from sample 4 shale fractures (Well J174; P2l2) and sample 4 shale ultrasonic extracts (steps 1 and 2) have almost identical i-C18/n-C18 and Pr/n-C19 ratios, while proximal shale and tight-reservoir ultrasonic extracts have quite different ratios (Figure 11). Δi-C18/n-C18 and ΔPr/n-C19 values (i.e., the absolute differences in i-C18/n-C18 and Pr/n-C19 ratios between oil samples and rock ultrasonic extracts (steps 1 and 2)) were used to estimate oil–rock correlation, with Δi-C18/n-C18 and ΔPr/n-C19 values of <0.2, indicating strong oil–rock correlation (Figure 12). The method was tested by comparing Δi-C18/n-C18 and ΔPr/n-C19 values for oil samples from sample 4 shale fractures in Well J174 (P2l2) with ultrasonic extracts from sample 4 and with other P2l2 shale and tight-reservoir ultrasonic extracts (Figure 12). Only sample 4 shale displays strong oil–rock correlation, confirming the reliability of the method.

Figure 11.

Figure 11

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Determination of Lucaogou oil produced from shale and tight reservoirs for Wells J174, J36, and J31 in the Jimsar Sag.

Figure 12.

Figure 12

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Δi-C18/n-C18vs ΔPr/n-C19 plots for ultrasonic extracts (steps 1 and 2) from shale and tight reservoirs. (a) Δi-C18/n-C18, step 2 vs Δi-C18/n-C18, step 1; (b) ΔPr/n-C19, step 2 vs ΔPr/n-C19, step 1. Note: Δi-C18/n-C18 and ΔPr/n-C19 are the absolute differences in these factors between oil and extracts.

The i-C18/n-C18 and Pr/n-C19 ratios of P2l1 oil samples from Wells J174, J31, and J36 were compared with ratios of P2l1 ultrasonic extracts from shale and tight reservoirs in fractured formations, and corresponding Δi-C18/n-C18 and ΔPr/n-C19 are calculated (Figures 11 and 12). Oil and tight-reservoir samples from Wells J174 and J31 have closer i-C18/n-C18 and Pr/n-C19 ratios (Figure 11), and Δi-C18/n-C18 and ΔPr/n-C19 values for tight-reservoir samples plot within the strong-correlation range (Figure 12), suggesting that P2l1 oil in these wells produced from tight reservoirs. For Well J36, P2l1 oil and shale samples have close i-C18/n-C18 and Pr/n-C19 ratios (Figure 11) and the Δi-C18/n-C18 value for sample 14 shale also plots in the strong-correlation range (Figure 12). Tight-reservoir cores from this well are currently unavailable, so it was not possible to evaluate the correlation between oil and tight reservoirs. However, the strong correlation between oil and shale samples indicates that P2l1-produced oil in Well J36 contains free hydrocarbons from shale.

Previous studies have shown that there is a positive correlation between reservoir properties, connectivity, and organic matter maturity in shale, with higher organic matter maturity corresponding to more pores and fractures and better connectivity.44,46,47 At Ro = 1.0, 30–50% of hydrocarbons are occluded in shale.48,49 Hydrocarbon mobility increases with maturity due to the higher gas/oil ratio and lower oil density and viscosity.50,51 In the Jimsar Sag, there is a positive correlation between organic matter maturity and burial depth (Figure 3). In the shallow zones (e.g., the J174 and J31 well fields), Ro is <0.85% and the density of produced oil is >0.90 g cm–3 (Tables 1 and 5). Considering the poor reservoir properties, connectivity, and hydrocarbon mobility in shale, it is inferred that oil in such zones is produced mainly from tight reservoirs. In the deeper zones (e.g., the J36 well field), Ro > 1.0% and the density of the produced oil <0.90 g cm–3 (Tables 1 and 5). In these zones, some free hydrocarbons may have produced from shale, due to the better reservoir properties, connectivity, and hydrocarbon mobility in shale.

Whether or not mass production of free hydrocarbons has occurred may depend on the maturity of organic matter in the Lucaogou shale. Free hydrocarbons in shale may be produced when organic matter maturity reaches an Ro of 1.0%. More oil is produced at higher maturities for shale, with improved reservoir properties, connectivity, and higher gas/oil ratios for hydrocarbons, enhancing oil quality and mobility. Most oil is currently produced from shallow Lucaogou tight reservoirs with an Ro of < 1.0%. However, deeper organic-rich shale zones with an Ro of > 1.0% may become important exploration and production targets in the Jimsar Sag.

4. Conclusions

  • (1)

    Lucaogou shale and tight oil reservoirs in the Jimsar Sag yielded similar Soxhlet-extract biomarker values, but ultrasonic extracts yielded different n-alkane and isoprenoid values in both n-hexane and chloroform extraction steps. Due to the effects of solvent polarity, molecular characteristics of n-alkanes and isoprenoids, and physical properties of the reservoir, n-hexane ultrasonic shale extracts had higher i-C18/n-C18 and Pr/n-C19 ratios than those of chloroform extracts, while extracts from tight reservoirs had very similar ratios with both extracts.

  • (2)

    Biomarker correlations between oil samples and ultrasonic extracts resolved the identification of the Lucaogou oil-producing rocks. In shallow zones of the Jimsar Sag (e.g., the J174 and J31 well fields), organic matter maturity has an Ro of <0.85% and an oil density of >0.90 g cm–3. Shales are characterized by poor reservoir properties, connectivity, and hydrocarbon mobility, and in these zones, oil is mainly produced from tight reservoirs. In deeper zones, for example, the J36 well field, organic-matter maturity has an Ro of >1.0% and an oil density of <0.90 g/cm–3. The better reservoir properties, connectivity, and hydrocarbon mobility in shale in these zones mean that some of the free hydrocarbons there may have been produced from shale.

  • (3)

    The mass production of free hydrocarbons may depend on the organic matter maturity of the Lucaogou shale. Free hydrocarbons can be produced from shale when organic matter maturity reaches an Ro of 1.0%. Higher organic matter maturity will result in better reservoir properties and connectivity, higher gas/oil ratios for occluded hydrocarbons, and better oil quality and mobility, which favor the production of free hydrocarbons in the Lucaogou shale. Deeper organic-rich shale zones with an Ro of > 1.0% may become important exploration and production targets in the Jimsar Sag.

5. Geological Setting

The Jimsar Sag is a dustpan-like sag with an area of 1278 km2 on the southeastern margin of Junggar Basin, NW China (Figure 13a,b). It is bordered by the Fukang Fault Zone (the Santai Fault) to the south, is separated from the Shaqi Uplift by the Jimsar Fault to the north, abuts the Beisantai Uplift via the Xidi Fault and the southern part of the Well Qing-1 Fault to the west, and transitions into the Guxi Uplift toward the east. The sag was formed on the middle Carboniferous folded basement after a succession of multistage tectonic events. To the west, the sag is deeply buried and faulted; in the east, it is shallow, with stratigraphic overlap (Figure 13c).52,53 Unconventional oil discoveries have been made mainly in the middle Permian Lucaogou Formation of the sag. The Lucaogou Formation, with a thickness of 100–300 m, comprises vertical alternations of shale and tight reservoirs deposited in a semideep to deep lake environment with a dry climate and high water salinity (Figure 13d).30,54,55 The shale is mainly siliceous and dolomitic with an average total organic carbon (TOC) content of 3.24%, a hydrocarbon generation potential (S1 + S2) of >6.0 mg g–1,56 Type I and Type II1 kerogen, and a vitrinite reflectance (Ro) of 0.6–1.2%. Shale porosity is generally <8% with a main pore throat radius of 7–100 nm.55 The brittle mineral content of the shale is >60%.55 Bedding seams and structural microfractures are common, accompanied by local irregular, high-angle microfractures that contain oil-rich strip-like zones.14 The tight reservoirs are mainly siltstone, argillaceous and dolomitic siltstone, and silty dolomite, with abundant nanopores. They are characterized by medium–low porosity and low–ultralow permeability with a main pore throat radius of 50–500 nm.32 Porosity and permeability, measured under confining pressures, are 5–16% and <10–4 μm, respectively.56 The average reservoir porosity measured under confining pressure in the development wells is 11%, associated with an average permeability of 10–5 μm. The oil saturation is 45–90%.

Figure 13.

Figure 13

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Geological maps of the Permian Lucaogou Formation in the Jimsar Sag, Junggar Basin. Reprinted (Adapted or Reprinted in part) with permission from Hu et al.(38) Copyright 2018 Elsevier Ltd. Locations of (a) Junggar Basin, (b) the Jimsar Sag, and (c) oil wells, with a contour map of the Lucaogou Formation (P2l). (d) Stratigraphy of the Lucaogou Formation (P2l).

The Lucaogou Formation can be divided into lower and upper members (P2l1 and P2l2, respectively), each with a sweet spot (Figure 13d). The upper sweet spot (in P2l2) is ∼41 m thick and is distributed mainly in the middle of the sag over an area of 640 km2. The lower sweet spot (P2l1) covers an area of 1096 km2 and is thicker in the southern sag.56 The upper sweet spot has oil reserves of >4.5 × 108 tonne (t) with 15 exploration wells currently producing oil. The lower sweet spot has oil reserves of >6.7 × 108 t with eight exploration wells currently producing oil.16

6. Samples and Methods

6.1. Samples

Ten shale samples, seven tight-reservoir samples, and four oil samples (Tables 1 and 5) were collected from wells J174, J36, and J31 (Figure 13c). Well J174, from which 13 core and 2 oil samples were obtained, was the main focus of this study (Figure 14). One oil sample was acquired from the producing well, and the other was acquired from fractures (Figure 14a,b) in core sample 4 caused by a rotary drilling machine. Well J36 did not yield any tight-reservoir cores, with only shale samples being acquired from this well.

Figure 14.

Figure 14

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Profile of Well J174, showing the location and characteristics of Lucaogou Formation samples, Jimsar Sag. Reprinted (Adapted or Reprinted in part) with permission from Yang et al.(55) Copyright 2019 Elsevier Ltd. For lithology, see Figure 13. (a) Fractures in shale, white light, sample 4; (b) fractures in shale, fluorescent light, sample 4; (c) tight reservoir, white light, sample 8; (d) tight reservoir, fluorescent light, sample 8; (e) shale, white light, sample 9; (f) shale, fluorescent light, sample 9.

6.2. Experimental Methods

All analyses described here were undertaken at the Research Institute of Petroleum Exploration and Development, China National Petroleum Corporation, Beijing, except for petrographic, vitrinite reflectance, and maceral analyses, which were carried out at the China University of Geosciences, Beijing.

6.2.1. Petrographic and Mineralogical Analysis

After core scanning with white and blue fluorescent light, all core samples from Well J174 were processed for thin-section petrography, X-ray diffraction (XRD) analysis, and maceral study. To make pore space more readily identifiable, blue resin was injected into the samples. Thin sections were prepared from all samples and studied using a petrographic microscope. XRD analysis involved the same method as Wang et al.(57) Maceral observations were made under plane-polarized reflected white light and incident blue light.

6.2.2. Source-Rock Geochemistry

The 17 core samples were crushed to powder and oil was extracted in preparation for TOC measurement and pyrolysis analysis, following standard procedures described in Espitalie et al.(58) A Rock Eval-6 Standard analyzer was used to determine the content of free hydrocarbons (S1), pyrolysis hydrocarbons (S2), and the temperature of the maximum pyrolysis yield (Tmax). Vitrinite reflectance (Ro) was measured for eight shale samples following the standard procedure described in Taylor et al.(59) More than 50 point-count measurements were performed on each sample, and the frequency distribution of values was evaluated.

6.2.3. Reservoir Porosity and Pore Structure Analysis

Solid cylinders of 2.5 cm diameter were cut from 14 core samples and the oil was removed in preparation for porosity, mercury-injection capillary pressure (MICP), and nuclear magnetic resonance (NMR) analysis. Porosity measurement followed the method of Wang et al.(57) Based on results of porosity analysis, four samples from Well J174 (P2l1 and P2l2) were analyzed by MICP and NMR to characterize the pore structure and connectivity in shale and tight reservoirs. MICP analysis and pore-throat radius calculations followed the method of Pang et al.(60) NMR analysis followed the Chinese Oil and Gas Industry Standard (SY/T) 6490-2014. The NMR T2 distribution was measured for water-saturated samples before centrifugation to provide T2 distribution curves with centrifugal forces of 20, 40, 200, and 400 psi, corresponding to pore-throat radii of 1.0, 0.5, 0.1, and 0.05 μm, respectively. The pore throat radius was calculated following the same method as Lai et al.(61)

6.2.4. Extraction and Fractionation

Subsamples of ∼200 g from each of the 17 core samples were ground to 20–30 mesh (0.85–0.55 mm) and divided into two groups for either Soxhlet or ultrasonic extraction of hydrocarbons. The former involved extraction with chloroform for 72 h at 60 °C using a conventional Soxhlet extraction method,62 and the latter consisted of a two-step ultrasonic extraction as follows. In step 1, each sample was placed in a beaker to which n-hexane was added until the sample was submerged; the mixture was then ultrasonicated for 6 h at <40 °C to extract organic matter; the supernate was removed with a pipette for further analysis. In step 2, samples previously subjected to n-hexane extraction were dried and ground to 200 mesh (0.074 mm) and subjected to extraction with chloroform for 6 h at <40 °C as for step 1; the supernate was again removed with a pipette. The core samples remained submerged in the solvent during the entire process. Soxhlet and ultrasonic extracts and the oil samples were separated by column chromatography into saturated and aromatic hydrocarbon fractions without prior separation of asphaltenes. Elution with n-hexane yielded the saturated fraction. In total, 51 extracts were thus collected for molecular biogeochemical analysis.

6.2.5. Molecular Biogeochemical Analysis

The 51 core extracts and 4 oil samples were analyzed by gas chromatography (GC) using an Agilent Technologies (USA) 6890N gas chromatograph fitted with a flame ionization detector. The saturated fractions of 27 core extracts were also analyzed for biomarkers by GC–mass spectrometry (GC–MS). GC analyses involved a fused silica column (60 m × 0.25 mm i.d. × 0.25 μm film thickness) coated with DB-5MS (5% phenyl) methyl-polysiloxane, with a split injection technique and with the oven temperature programmed from 40 °C (10 min) to 320 °C at 4 °C min–1 (held for 20 min). GC–MS analyses involved an Agilent 6890N gas chromatograph with an Agilent 5973C mass spectrometer. The GC procedure was as mentioned above but with a 30 m column with 0.32 i.d. and an initial oven period (40 °C) of 1 min.

Acknowledgments

We thank Dr Se Gong for constructive comments and suggestions that significantly improved the manuscript. We also acknowledge the Xinjiang Oilfield for sample collection. This work was supported by the CNPC International Science and Technology Cooperation Development Project (2012A-4802-02; 2015D-4810-02).

The authors declare no competing financial interest.

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