1 Introduction

Since the Laojunmiao oilfield was discovered in 1938, the Jiuquan Basin has had a history of oil exploration and development for nearly 80 years (Chen et al. 2001). At present, a great deal of crude oil has been discovered in the Qingxi Sag and the South Uplift, including the Laojunmiao and the Shiyougou oilfields in the South Uplift, and the Qingxi oilfield (including Liugouzhuang and Kulongshan areas) and the Ya’erxia oilfield in the Qingxi Sag (Fan et al. 2004; Zhou et al. 2006; Wang et al. 2008; Li et al. 2010). In the South Uplift, oil resources of the Laojunmiao and Shiyougou oilfields are concentrated mainly in the Paleogene; in the Qingxi Sag, oil resources of the Kulongshan and Liugouzhuang fields are concentrated chiefly in the Lower Cretaceous Xiagou Formation and those in the Ya’erxia oilfield are concentrated primarily in the Xiagou Formation, with less in the Paleogene and the Silurian (Xie et al. 2001; Cheng et al. 2007; Zhao et al. 2008; Li et al. 2010). A lot of research into tectonics, sedimentology, reservoir, oil accumulation, and exploration has been undertaken in the Qingxi Sag and the South Uplift (Yang et al. 2004; Wang et al. 2005; Sun et al. 2006; Pan et al. 2007). Previous research indicates that the crude oil in the Qingxi Sag and the South Uplift was chiefly derived from the Xiagou Formation source rock distributed in the Qingxi Sag (Fan et al. 2004; Li et al. 2005; Cheng et al. 2007; Han et al. 2007), but up to now, research into the source rock has been chiefly focused on kerogen geochemistry, thermal evolution, and hydrocarbon-generating kinetics, etc. (Yang et al. 2003; Ma et al. 2009, 2011). With the advancement of oil exploration, there have been more and more crude oil resources discovered in the Xiagou Formation and a great amount of source rocks occur within the Qingxi Sag. Current information has revealed that the Xiagou Formation is the major source rock layer in the study area (Fan et al. 2004; Li et al. 2005; Han et al. 2007), but comprehensive research into the detailed geochemistry and hydrocarbon potential of this set of source rocks is scarce. The present study focuses on systematical research into mineral components, abundance, type, maturity of organic matter, and biomarker geochemistry of the source rocks, in order to improve the understanding of the oil exploration potential in the deep sag.

2 Geological setting

The Qingxi Sag, which covers an area of 230 km2, is located in the southwest of the West Depression of the Jiuquan Basin (Chen et al. 2001). It is one of the most important hydrocarbon-rich sags in the Jiuquan Basin, and it contains more than 0.16 billion tonnes of proved oil resources. It occupies 76% of the Western Depression of the Jiuquan Basin (You et al. 2011) (Fig. 1a). The Qingxi Sag is bordered by the Qingxi Low Uplift in the northwest, the Jinta Sag and Yabei Uplift in the northeast, the South Uplift in the southeast, and the Overthrust Nappe Zone in the southwest (Fig. 1a). The basement of the Jiuquan Basin consists of pre-Cretaceous metamorphic rocks (Fig. 1b). In the Qingxi Sag, the sedimentary strata include the Lower Cretaceous Chijinpu (K1c), Xiagou (K1g), and Zhonggou (K1z) Formations, the Paleogene Oligocene, the Neogene Miocene and Pliocene, and Quaternary strata, from oldest to youngest, while in the South Uplift, sedimentary formations only include the Oligocene (E3), the Miocene (N1), the Pliocene (N2), and the Quaternary (Q), from oldest to youngest, without sedimentary strata older than the Oligocene (Wang et al. 2005). In the Qingxi Sag, there are three unconformities between basement and overlying sedimentary strata, between the Zhonggou Formation and Oligocene, and between the Miocene and the Pliocene. In the South Uplift, there are two unconformities between basement and Oligocene, and between the Miocene and the Pliocene (Fig. 1b).

Fig. 1
figure 1

Sketch map of tectonic location, geological elements (a), and stratigraphic column (b) in the study area

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There are three sets of organic matter-rich rocks in the study area, the Chijinpu, the Xiagou, and the Zhonggou Formations, but the Zhonggou Formation rock is not an effective source rock, due to low maturity (Yang et al. 2003). Because of greater burial depth, the rocks in the Xiagou and Chijinpu Formations may become effective source rocks (Ma et al. 2009). The Xiagou Formation is the major source rock for the discovered crude oil (Fan et al. 2004; Ma et al. 2007, 2011). According to the lithologic combination, the Xiagou Formation was divided into four members: the Zeroth (K1g0), First (K1g1), Second (K1g2), and Third (K1g3), from oldest to youngest. The Xiagou Formation mainly consists of shale, dolomitic shale, dolomitic sandstone, and sandstone. The shale and dolomitic shale as source rocks generally contain laminas and microfractures as well as minor stylolites (Cheng et al. 2007; Ma et al. 2007). The formation of the source rock which contains carbonates was generally related to saline lacustrine conditions. Generally, this set of source rocks is of high quality, and some of this type of source rocks have been reported globally (Jin et al. 2001; Hudec and Jackson 2006). Because of stronger oil generation and expulsion capacities, the crude oil which comes from the Xiagou Formation source rock was accumulated in the Silurian in the east margin of the Qingxi Sag. These strata overlie the Xiagou Formation in the Qingxi Sag and the Paleogene in the South Uplift. In the Qingxi Sag, fracture reservoirs are the main oil reservoir type; however, in the South Uplift, structural traps are the chief types for oil accumulation (Chen et al. 2001; Cheng et al. 2007; Wang et al. 2008).

3 Samples and experiments

3.1 Samples

A total of 37 core samples were collected from the K1g0 (2), K1g1 (14), K1g2 (16), and K1g3 (5) for source rock analyses of the Xiagou Formation. These samples include dolomitic shale and shale from 7 wells (Long105, Q2-3, Q2-4, Liu10, Liu4, Liu6, and Liu104). The locations of the sampling wells are shown in Fig. 1a (left). All of 37 source rock samples were crushed into powder smaller than 80 mesh.

3.2 Total organic carbon (TOC) and Rock–Eval pyrolysis and bitumen extraction of source rocks

All of 37 samples were examined as follows: total organic carbon (TOC), Rock–Eval pyrolysis, solvent extraction, and fraction separation. Analyses of TOC were carried out on a Leco CS-230 carbon analyzer. Rock–Eval analysis was performed on an OGE-II rock pyrolyzer which was developed by Experimental Center of Petroleum Geology of China Petroleum Exploration and Development Research Institute, and which can obtain the parameters of S1 (mg HC/g Rock), S2 (mg HC/g Rock), and Tmax (maximum peak temperature of S2, °C). 80–100 g of powder samples (80–100 mesh) was extracted for 72 h with Soxhlet apparatus and chloroform to obtain solvent extract (bitumen). Fractions of extracts were separated by conventional column chromatography. The extracts were dissolved in excess petroleum ether for 24 h and then filtered to obtain asphaltene. The soluble remnants were separated with an activated silica gel/alumina chromatography column (Activity I, 80–200 mesh) into saturated, aromatic, and resin fractions by gaseous–solid-phase adsorption chromatography. Hydrocarbon (HC) refers to the saturated plus aromatic fraction of the extract. Extract and hydrocarbon contents are expressed as the percentage content in the rock.

3.3 GC–MS of source rock saturated fractions

All of 37 samples were analyzed by gas chromatography–mass spectrometry (GC–MS) of the saturated fractions. GC–MS was performed by using an Agilent 7890-5975C gas chromatography–mass spectrometer. The gas chromatograph was equipped with an HP-5MS elastic silica capillary column 60 m in length, 0.25 mm in radius, and 0.25 μm in film thickness. Helium (99.999%) was used as the carrier gas; the temperature of injection port was 300 °C and the transmission line temperature was also 300 °C; the column temperature was programmed from the initial 50 °C (hold on 1 min) to 200 °C at 20 °C/min, to 250 °C at 4 °C/min, and then to 300 °C (hold on 30 min) at 3 °C/min; and the flow rate of carrier gas was 1 mL/min. The mass spectrometer was operated in EI mode at an ionization voltage of 1047 V.

3.4 X-ray diffraction (XRD) and vitrinite reflectance (R o) of source rock

In total, 21 source rock samples were selected for X-ray diffraction analysis, and 18 source rock samples were analyzed for vitrinite reflectance. The whole rock X-ray diffraction (XRD) analysis for mineral composition was performed on a Bruker D2 PHASER diffractometer system using Cu Ka radiation at 30 kV and 10 mA. The powders were scanned over a sampling range of 5–60° 2\(\theta\) (\(\theta\) is the diffraction angle) with a step of 0.01° 2\(\theta\) and a scan speed of 2 s per step. The analytical precision is about 4% (2 s, standard deviation). The vitrinite reflectance (Ro) values of 18 bulk rock samples were tested by using an MPV-SP microscope photometer.

All of the experimental tests were carried out in State Key Laboratory of Petroleum Resource and Prospecting of China University of Petroleum, Beijing. Apart from the above-mentioned analysis of collected samples, the other analytical testing of source rocks such as TOC, Rock–Eval parameters, and Ro was undertaken at the Research Institute of Exploration and Development of Yumen Oilfield Company.

4 Results

The mineral composition data for the 21 source rock samples analyzed by XRD analysis are shown in Table 1. The TOC, TS, bitumen extract, HC content values, the Rock–Eval pyrolysis data for the 37 source rock samples, and the Ro data for the 18 source rock samples are shown in Table 2. The statistical parameters for the saturated fraction from the Xiagou Formation source rocks are given in Table 4, and the statistical parameters for saturated fraction, terpane, and sterane from the Xiagou Formation source rocks are shown in Table 5.

Table 1 Mineral composition of the Xiagou Formation source rocks of Qingxi Sag, Jiuquan Basin
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Table 2 Analytical data for TOC, extract, HC, Rock–Eval pyrolysis, and Ro from the Xiagou Formation source rocks
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5 Discussion

5.1 Mineral composition of source rocks

Mineral composition of sedimentary rock is controlled by many factors including material source, transport distance, hydrodynamic conditions, the sedimentary environment, and diagenesis (Soleimani and Zamani 2015). From Table 1, it can be observed that the mineral components in the source rocks include mainly potassium feldspar, plagioclase, dolomite, clay, and a small quantity of quartz, calcite, pyrite, and anhydrite (Table 1). There is more plagioclase than potassium feldspar in the source rocks, and their contents vary between 27% and 74% (averaging 50%) and between 0% and 19% (averaging 6%), respectively. In carbonate minerals, the dolomite is dominate and the calcite can hardly be detected, and their contents vary between 7% and 45% (averaging 27%) and between 0% and 2% (averaging 0.3%), respectively. The clay mineral has medium contents ranging from 3% to 15% (averaging 8%). The contents of quartz, pyrite, and anhydrite vary from 1% to 7% (averaging 3%), 0% to 5% (averaging 1.4%), and 0% to 7% (averaging 4%), respectively. The existence of anhydrite and dolomite minerals indicates that the Xiagou Formation source rock was formed in an alkaline sedimentary environment (Kuang et al. 2012; Li et al. 2014), and the appearance of pyrite indicates that the Xiagou Formation source rock was formed in a reducing environment (Berner 1984). Therefore, the above-mentioned analyses indicate that the Xiagou Formation source rock was formed in a closed and reducing alkaline sedimentary environment. In the ternary plot of carbonates, feldspars, and clay minerals, the feldspar minerals are the most abundant, the carbonate minerals are the second, and the clay minerals are the least (Fig. 2). These source rocks with high abundance of brittle minerals (carbonates and feldspars, etc.) are easily fractured under the action of tectonic stress. This is consistent with the existence of fracture reservoirs in the Qingxi Sag (Cheng et al. 2007; Wang et al. 2008).

Fig. 2
figure 2

Ternary plot of mineral components of the Xiagou Formation source rocks of the Qingxi Sag, Jiuquan Basin

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5.2 Organic matter richness

Organic matter (OM) is fundamental to hydrocarbon generation in source rocks (Tissot and Welte 1984), and generally, four parameters (TOC, extract, HC, and S1 + S2) are used to evaluate organic matter abundance of source rock (Cheng et al. 2007). In the Qingxi Sag, the organic matter abundances of the Xiagou Formation source rocks are higher (Tables 2, 3). The TOC contents of the K1g3, K1g2, K1g1, and K1g0 source rocks vary from 0.31% to 3.33% (average: 1.23%), 0.51% to 3.1% (average: 1.32%), 0.17% to 6.89% (average: 1.56%), and 0.85% to 11.53% (average: 2.36%), respectively, and the S1 + S2 values vary from 0.11 to 27.4 mg HC/g rock (average: 5.42 mg HC/g rock), 0.6 to 25.2 mg HC/g rock (average: 5.2 mg HC/g rock), 0.07 to 36.1 mg HC/g rock (average: 6.51 mg HC/g rock), and 1.97 to 16.1 mg HC/g rock (average: 7.08 mg HC/g rock), respectively (Tables 2, 3). As shown in Fig. 3a, different members of the Xiagou Formation contain a great amount of fair to excellent source rocks (Huang et al. 1984; Cheng 1994).

Table 3 Statistical data of TOC, bitumen extract, HC, and Rock–Eval parameters in different members of the Xiagou Formation source rocks
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Fig. 3
figure 3

Cross diagrams of TOC versus S1 + S2 (a) and bitumen extract versus HC (b) for the Xiagou Formation source rock samples

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Extract contents of the K1g3, K1g2, K1g1, and K1g0 source rocks range from 0.0094% to 0.452% (average: 0.166%), 0.050% to 1.253% (average: 0.228%), 0.0044% to 1.631% (average: 0.200%), 0.0621% to 0.365% (average: 0.162%), respectively, and their HC contents vary from 0.0030% to 0.231% (average: 0.077%), 0.0181% to 0.603% (average: 0.101%), 0.0013% to 0.91% (average: 0.105%), and 0.0285% to 0.211% (average: 0.0946%), respectively (Tables 2, 3). As shown in Fig. 3b, most source rock samples of the K1g3, K1g2, K1g1, and K1g0 fall in the fair–excellent source rock zone.

Based on the above-mentioned analyses, there are large amounts of high-quality source rocks distributed in the different members of the Xiagou Formation.

5.3 Organic matter type

The organic matter type determines the oil-prone/gas-prone property of source rock (Salah and Alsharhan 1997; Alsharhan 2003). The S2 and HI parameters of Rock–Eval pyrolysis are often used to evaluate the organic matter type of source rock (Espitalié et al. 1985; Langford and Blanc-Valleron 1990; Hakimi et al. 2010; Korkmaz et al. 2013). In the study area, the S2 values range from 0.01 to 32.5 mg HC/g rock (average: 5.36 mg HC/g rock), and the HI has a wide scope between 1.4 and 1680 mg HC/g TOC (average: 329 mg HC/g TOC) (Table 3; Fig. 4a). Some samples show HI values more than 900 mg/g TOC, but they have lower TOC contents (Fig. 4a). It is speculated that these samples are possible to be influenced by migrated hydrocarbon (Gao et al. 2016). Figure 4a, b indicates that there are the most Type II organic matter and some Type III and Type I in the source rocks. According to statistical results, the HI values of the K1g3, K1g2, K1g1, and K1g0 source rocks range from 28 to 869 mg HC/g TOC, 75 to 797 mg HC/g TOC, 23 to 706 mg HC/g TOC, and 24 to 631 mg HC/g TOC with an average of 350, 318, 307, and 259 mg HC/g TOC, respectively (Table 3). It can be observed that the HI values of the K1g3, K1g2, K1g1, and K1g0 source rocks gradually decrease (Table 3). This should be related to their gradually increasing maturity. This indicates that organic matter-type distributions of the K1g3, K1g2, K1g1, and K1g0 source rocks are similar, and all of them have stronger oil-prone properties in the study area.

Fig. 4
figure 4

Cross diagrams of Tmax versus HI (a) and TOC versus S2 (b) for the Xiagou Formation source rocks. a The organic matter-type boundary line according to Sadettin Korkmaz et al. (2013); b source rock quality boundary representing oil- and gas-prone attribute after Hakimi et al. (2010); border between Type II/III organic matter (300 mg HC/g TOC) after Langford and Blanc-Valleron (1990), border between Type I/II organic matter (700 mg HC/g TOC) after Espitalié et al. (1985)

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5.4 Thermal maturation

The vitrinite reflectance (Ro) and Rock–Eval parameter are applied to assess thermal evolution for source rock (Peters et al. 2005). In the study area, the tested Ro values for the source rock vary from 0.49% to 0.98% (averaging 0.67%), and the Tmax values range between 426 and 452 °C (averaging 439 °C) (Table 3). In Fig. 5a, b, both the Ro and the Tmax values have an increasing trend with increasing depth, and the inferred low maturity (Ro = 0.5%–0.7%) depth interval is about 3000–3800 m, the mature source rock is mainly below about 3800 m depth with an oil peak depth of 4500 m (corresponding Ro is about 0.8%), and the bottom depth of oil window is not easily determined and is speculated to be about 5900 m (Ro = 1.3%) (Fig. 5a, b). In Fig. 5c–e, with the increase of depth, the envelop curves of extract/TOC, S1/(S1 + S2), and HCI (S1/TOC, mg HC/g TOC) content values firstly increase and then decrease, and their turning points correspond to an Ro of about 0.8% and a Tmax of about 440 °C. This indicates that the source rock in the Xiagou Formation has generated a great deal of hydrocarbon before the classic oil peak of Ro = 1% (Tissot and Welte 1984).

Fig. 5
figure 5

Diagrams of Ro, Tmax, extract/TOC, S1/(S1 + S2), and HCI versus depth for the Xiagou Formation source rocks in the Qingxi Sag, Jiuquan Basin

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The diagrams of Tmax versus productive index [PI = S1/(S1 + S2)] for the different members of the Xiagou Formation (Fig. 6a–d) show that all of the K1g0 source rock samples fall within the oil window, most of the K1g1 source rock samples are within oil window with a small number in the low maturity stage, while the K1g2 and K1g3 source rock samples fall in the low-mature–mature stages, but they have relatively more samples in the low-mature stage than the K1g1 and K1g0 source rock (Peters et al. 1986). According to Fig. 6, it seems that the samples in K1g2 are much closer to the samples in K1g1, compared with the samples in K1g3.

Fig. 6
figure 6

Cross plots of Tmax versus S1/(S1 + S2) for the Xiagou Formation source rocks in the Qingxi Sag (after Peters et al. 1986)

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In the deep Qingxi Sag, the Xiagou Formation reservoirs, having lower porosity and permeability, are typical tight reservoirs (Yang et al. 2004; Sun et al. 2015). Many fractures occur in tight reservoirs of the Xiagou Formation; therefore, the reservoirs of the Xiagou Formation in the Qingxi Sag are typical fractured tight reservoirs (Zhou et al. 2006; Cheng et al. 2007). Figure 7 shows that the K1g source rocks of the Qingxi Sag experienced two significant stages of uplifting during the Late Cretaceous, Paleocene, and Eocene and secondary burial began in the Eocene. At present, the Xiagou Formation source rocks of the deep sag are in the stage of oil generation (Fig. 7). The above-mentioned maturity distribution of the Xiagou Formation source rocks shows that the mature source rock tends to be distributed in the older members and greater depth. Therefore, the fractured tight reservoir and mature source rock distributions indicate that there is a better tight oil exploration potential in the deep Qingxi Sag.

Fig. 7
figure 7

Hydrocarbon generation and accumulation history of K1g source rocks in the Qingxi Sag, Jiuquan Basin

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5.5 Saturated fraction geochemistry

The composition of the saturated hydrocarbon is intimately related to the material source, sedimentary environment, and thermal evolution (Peters et al. 2005). In the study area, n-alkanes of the source rock samples range between n-C11 and n-C35, of which the main peak carbon number is n-C23 with a few being n-C21 and n-C17 (Fig. 8). The C21−/C22+ ratios of the K1g0, K1g1, K1g2, and K1g3 samples have higher values ranging from 1.43 to 1.45 (average: 1.44), 0.49 to 7.27 (average: 1.32), 0.73 to 2.36 (average: 1.39), and 0.93 to 1.26 (average: 1.09), respectively, and their (C27 + C29 + C31)/(C15 + C17 + C19) ratios are lower from 0.17 to 0.2 (average: 0.19), 0.02 to 1.84 (average: 0.57), 0.11 to 0.88 (average: 0.38), and 0.31 to 0.61 (average: 0.44), respectively (Table 4). This indicates that aquatic organisms had a greater contribution to the source rocks (Tissot and Welte 1984; Peters et al. 2005). Odd–even-predominance (OEP) and the carbon preference index (CPI) values of the K1g0, K1g1, K1g2, and K1g3 samples have a greater range. OEP changes from 1.23 to 1.36 (average: 1.3), 0.96 to 1.56 (average: 1.25), 0.95 to 1.24 (average: 1.09), and 1.01 to 1.24 (average: 1.11), respectively, and the CPI varies from 1.27 to 1.34 (average: 1.31), 1.08 to 1.85 (average: 1.43), 1.05 to 1.41 (average: 1.17), and 1.07 to 1.44 (average: 1.22), respectively (Table 4). The pristane (Pr) (C19) and phytane (Ph) (C20) contents of the source rock relative to adjacent normal alkanes have larger variations (Fig. 8). The Pr/nC17 ratio of the K1g0, K1g1, K1g2, and K1g3 samples ranges from 0.47 to 0.63 (average: 0.55), 0.3 to 3.04 (average: 1.09), 0.43 to 1.78 (average: 0.9), and 1.62 to 3.41 (average: 2.54), respectively; the Ph/nC18 ratios from 0.58 to 0.58 (average: 0.58), 0.3 to 4.7 (average: 1.53), 0.62 to 2.14 (average: 1.15), and 0.92 to 2.82 (average: 1.93), respectively; and the Pr/Ph ratio from 0.86 to 1.06 (average: 0.96), 0.2 to 2.29 (average: 0.78), 0.64 to 1.23 (average: 0.86), and 0.99 to 1.91 (average: 1.44), respectively (Table 4). In Fig. 9, the Pr/n-C17 ratio has a roughly positive correlation with the Ph/n-C18 ratios, and the youngest K1g3 has obviously higher Pr/n-C17 and Ph/n-C18 ratios than those of the oldest K1g0. This correlation implies that maturity has an influence for the Pr/n-C17 and Pr/n-C18 ratios (Dzou et al. 1995; Obermajer et al. 1999). It can be observed that most shale samples fall in the Type II organic matter zone, while only a few samples from the K1g1 fall in the Type III and Type I zones (Fig. 9). This indicates that the K1g source rocks have better oil-generating potential. Moreover, in the TIC plots, carotane can be observed in some samples (Fig. 8). This shows that contribution of algae in anoxic and saline lacustrine water body (Hall and Douglas 1981; Jiang and Flower 1986).

Fig. 8
figure 8

Examples of total ion current plots of GC–MS for the saturated fractions of the Xiagou Formation source rocks in the Qingxi Sag

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Table 4 Statistical data of saturated fraction from the Xiagou Formation source rocks
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Fig. 9
figure 9

Genetic characterization of Pr/n-C17 versus Ph/n-C18 of the Xiagou Formation source rock extracts [according to the categories of Obermajer et al. (1999)]

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5.6 Terpanes

Terpane (m/z = 191) distributions of all source rock samples are similar, showing that the tricyclic terpanes are lower than the pentacyclic triterpanes (Fig. 10). The tricyclic terpane abundance increasing with respect to hopane is controlled by thermal maturity and biodegradation (Connan and Cassou 1980; Seifert and Moldowan 1986; Peters et al. 2005), and higher pentacyclic triterpane is associated with bacterial contribution to OM in the source rocks (Ourisson and Rohmer 1992; Montero-Serrano et al. 2010). The tricyclic/pentacyclic terpane ratios of the Xiagou Formation source rocks range between 0.03 and 0.06 (average: 0.19) (Table 4). This indicates that thermal maturity of the source rocks is not high and bacterial has contribution to OM (Ourisson and Rohmer 1992; Montero-Serrano et al. 2010).

Fig. 10
figure 10

Examples of the m/z = 191 and m/z = 217 fragmentograms of some saturated fractions of the Xiagou Formation source rocks

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The tricyclic terpanes range from C19 to C29, with higher C20, C21, and C23 tricyclic terpanes (Fig. 10). High C19–C20–C21 tricyclic terpanes indicate that organic matter derived from a terrestrial origin (Ozcelik and Altunsoy 2005), high C23 tricyclic terpane indicates a high contribution of marine matter (Ourisson et al. 1982), and C24 tetracyclic terpane was mainly sourced from terrestrial OM input (Philp and Gilbert 1986). Low C24 tetracyclic terpane/C23 tricyclic terpane reflects reducing conditions (Waples and Machihara 1991). In the Xiagou Formation source rocks, the tricyclic terpane contents are generally low, with the tricyclic/pentacyclic terpane ratios between 0.03 and 0.6 (average: 0.19) (Table 4). The tricyclic/pentacyclic terpane ratios of the K1g0, K1g1, K1g2, and K1g3 samples vary from 0.07 to 0.1 (average: 0.08), 0.03 to 0.6 (average: 0.14), 0.14 to 0.41 (average: 0.28), and 0.18 to 0.41 (average: 0.26), respectively (Table 4). This indicates that the thermal maturity of source rocks is not high and can have bacterial contribution to OM (Ourisson and Rohmer 1992; Montero-Serrano et al. 2010). The C21/C23 tricyclic terpane ratios of the K1g0, K1g1, K1g2, and K1g3 source rocks range from 1.13 to 1.37 (average: 1.25), 0.53 to 1.91 (average: 1.28), 0.83 to 1.8 (average: 1.29), and 1.14 to 1.78 (average: 1.38), respectively, and the C24 tetracyclic/C23 tricyclic terpane ratios range from 0.82 to 0.94 (average: 0.88), 0.26 to 7.25 (average: 1.36), 0.22 to 1.67 (average: 0.6), and 0.25 to 1.08 (average: 0.59), respectively (Table 5). This indicates that terrigenous higher plants have also contributed to the source rock OM.

Table 5 Biomarker parameters of four members of the Xiagou Formation
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The relative abundance of 18α(H)-22,29,30-C27 trisnorneohopane (Ts) to 17α(H)-22,29,30-C27 trisnorhopane (Tm) ratio is used as maturity indicator, for Ts has a greater stability than Tm and increases with increasing maturation; therefore, Ts/Tm ratio rises with increasing thermal maturation; however, this ratio is controlled by the sedimentary environment (Peters et al. 2005). The Ts/Tm ratios for the K1g0, K1g1, K1g2, and K1g3 samples vary from 0.29 to 0.56 (average: 0.42), 0.01 to 1.56 (average: 0.29), 0.01 to 0.26 (average: 0.19), and 0.13 to 0.52 (average: 0.25), respectively. This indicates that source rocks are mainly in the early-mature to mature stage. The C30 diahopane abundance is related to clay-rich, oxic-anoxic depositional environments (Peters et al. 2005), and its abundance increases with increasing maturity (Kolaczkowska et al. 1990). The C30 diahopane/C30 hopane ratios are lower between 0.003 and 0.081 for all of the source rock samples (Table 5). This indicates that the source rocks of the K1g0, K1g1, K1g2, and K1g3 were formed in an anoxic depositional environment.

The gammacerane abundance is mainly related to water salinity (Moldowan et al. 1986; Mello et al. 1988; Ten Haven et al. 1988). The source rocks from the K1g0, K1g1, K1g2, and K1g3 contain higher gammacerane, with their gammacerane/C30 hopane ratios varying from 0.29 to 0.4 (average: 0.35), 0.03 to 0.72 (average: 0.18), 0.16 to 0.49 (average: 0.29), and 0.27 to 0.79 (average: 0.47), respectively (Table 5). Figure 11 shows that most of the Xiagou Formation source rock samples fall in the zone of anoxic to suboxic depositional environment with a stratified water column or possibly enhanced water salinity, with some samples of the K1g1 in the zone of anoxic to suboxic depositional environment with normal lacustrine water or no stratification.

Fig. 11
figure 11

Cross diagram of the gammacerane/C30 hopane ratio versus Pr/Ph ratio of the Xiagou Formation source rocks in the Qingxi Sag

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5.7 Steranes

Steranes are generally used to assess the source and maturity of OM in source rock (Peters and Moldowan 1993; Peters et al. 2005). The relative abundance of regular steranes C27, C28, and C29, is often used to determine the dominant source of OM since C27, C28, and C29 sterols derive mainly from zooplankton, phytoplankton, and land plants, respectively (Huang and Meinschein 1979). The C29/C27 sterane ratios of the K1g0, K1g1, K1g2, and K1g3 source rock samples vary from 1.71 to 2.08 (average: 1.9), 0.36 to 23.08 (average: 2.3), 1.13 to 2.55 (average: 1.63), and 2.02 to 5.97 (average: 3.53), respectively, and the C28/C29 ratios change from 0.42 to 0.49 (average: 0.46), 0.23 to 0.74 (average: 0.52), 0.41 to 0.75 (average: 0.57), and 0.48 to 0.85 (average: 0.67), respectively (Table 5). In Fig. 12a, all of the samples from the K1g0, K1g2, and K1g3 and most samples from the K1g1 fall in the planktonic/land plant zone, with a few of samples from the K1g1 in the planktonic/algal zone. This indicates that the OM of the Xiagou Formation source rocks came chiefly from planktonic and land plant organisms, with the OM of part of the source rocks from plankton, and algal and bacterial organisms (Adegoke et al. 2014). Diagrams of Pr/Ph ratio versus ααα-20R-C29/C27 ratio are applied to analyze OM source and redox condition (Mei and Liu 1980; McKenzie et al. 1981). In Fig. 12b, the samples from the K1g0 and K1g3 fall in the land plant zone with reducing fresh water, and the samples of the K1g1 and K1g2 fall in the algal zone and the land plant zone with both reducing fresh water and heavily reducing salt water. It can be concluded that the Xiagou Formation source rock was formed in a favorable sedimentary environment for oil source rock, the K1g1 and the K1g2 source rocks have alternative algal and land plant input, and the K1g0 and K1g3 source rocks have relatively more land plant input. In addition, some of the source rock samples contain some C30 steranes (Fig. 10). This further indicates that there are some algal contributions in the source rocks (Fu et al. 1985; Brassell et al. 1986; Zan et al. 2012).

Fig. 12
figure 12

Ternary plot of regular steranes (C27, C28, and C29) (a) and diagram of Pr/Ph versus ααα-20R-C27/C29 ratio (b) of the Xiagou Formation source rocks. a Shows the relationship between sterane composition and organic matter input in the Xiagou Formation [modified after Adegoke et al. (2014)]; b shows relation of organic matter input and depositional condition, Pr/Ph ratio standard line according to Mei and Liu (1980), and ααα-20R C29/C27 sterane standard line according to McKenzie et al. (1981)

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The C2920S/(20S + 20R) and C29ββ/(ββ + αα) sterane ratios are applied to evaluate maturation of source rock OM (Peters and Moldowan 1993), and with increasing maturity, they increase until equilibrium of 0.55 and 0.7, respectively (Peters et al. 2005). In the study area, the C29 20S/(20S + 20R) sterane ratios of the K1g0, K1g1, K1g2, and K1g3 range from 0.49 to 0.51 (average: 0.5), 0.28 to 0.53 (average: 0.43), 0.39 to 0.49 (average: 0.44), and 0.3 to 0.42 (average: 0.36), respectively, and the C29ββ/(αα + ββ) sterane ratios range from 0.56 to 0.58 (average: 0.57), 0.15 to 0.54 (average: 0.32), 0.2 to 0.39 (average: 0.27), and 0.2 to 0.27 (average: 0.23), respectively (Table 5). This indicates that the source rocks are mainly in the low-mature to mature stage. In Fig. 13, it can be observed that the Klg0 source rock samples are in the mature stage, the Klg3 samples are mainly low maturity, the Klg2 samples are mainly low mature with a small number mature, and the Klgl samples have a wide maturation range from low-mature to mature stages. Therefore, the Klg0 and Klgl contain a great amount of mature source rocks and should have more prospects for oil reservoirs in the deep sag.

Fig. 13
figure 13

Cross diagram of the 20S/(20S + 20R)-C29 sterane ratio and the ββ/(αα + ββ)-C29 sterane ratio of the Xiagou Formation source rocks, the equilibrium scope after Peters et al. (2005)

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6 Conclusions

The existing research for the Lower Cretaceous Xiagou Formation source rocks in Qingxi Sag of the Jiuquan Basin is scattered. The current study systematically analyzes the mineral composition and organic geochemistry of the Cretaceous Xiagou Formation source rocks, and it suggests the following major conclusions:

Mineral composition and biological marker analyses show that the Xiagou Formation source rock was formed in a closed, reducing, anoxic, and alkaline lacustrine environment with higher salinity, with more brittle minerals which are favorable for fracture reservoirs within source rock formations in the Qingxi Sag. According to analyses of TOC, Rock–Eval pyrolysis, extract, and HC, there are a great number of fair to excellent source rocks distributed in the Xiagou Formation.

TOC, Rock–Eval pyrolysis, and biomarker analyses suggest that the Xiagou Formation source rocks mainly contain OM coming from plankton/algae and higher plants as well as possible bacteria organisms, and its OM is mainly Type II and part of Type III and I, and they have a stronger oil generation potential.

The Xiagou Formation source rocks are mainly in the early-mature to mature stage, and Ro value corresponding to its oil peak is lower than classic oil peak Ro value (0.8%). This indicates that the source rock of the Xiagou Formation has generated a great deal of hydrocarbon before the classic oil peak of Ro = 1%.

The mature source rock in the Xiagou Formation tends to be distributed in the older members and at greater depth. This indicates that there is a better tight oil exploration potential in the deep Qingxi Sag.