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Source rock potential and depositional environment of upper Permian oil shales of the lucaogou formation in the southeastern Junggar Basin, Northwest China.

1. Introduction

The Upper Permian oil shales of the Lucaogou Formation outcropping in the southeastern Junggar Basin, Northwest China were long ago identified and reported to contain abundant organic matter and have considerable thickness [1-4]. Several authors have ranked these silicic mudstones among the thickest and richest petroleum source rock intervals in the world [2, 3]. Carroll et al. [4] studied two Upper Permian sections in the western foothill of Bogda Mountain identified as the Tianchi and Urumuqi sections, which included rocks (from the oldest to the youngest) of the Jingjingzigou, Lucaogou and Hongyanchi formations. Li [5] and Tao et al. [6] documented several Lucaogou Formation profiles in the eastern part of the foothill of Bogda Mountain. The Upper Permian rocks of the Junggar Basin are exclusively lacustrine deposits, based on fossil evidence, metallogenic characteristics, sedimentary facies, as well as macro-, trace and rare earth elements analyses [7-13].

Although several investigations have been carried out on Lucaogou oil shales in the Junggar Basin, they chiefly concerned with the sedimentary environment by using elemental geochemical methods [5-7, 9, 10, 13]. The study area of most of these articles was the eastern part of the foothill of Bogda Mountain. However, some researchers conducted a comprehensive study of oil shales in the western part of Bogda Mountain to describe their sedimentary and organic geochemical characteristics [4, 14]. In the present work, oil shales from three sections of the Lucaogou Formation in the western part of Bogda Mountain--Yamalikeshan (YMS), Shuimogou (SMG) and Sangonghe (SGH)--were analysed using organic geochemistry methods, including biomarkers and total organic carbon isotope, to define the source rock quality, depositional environment and organic matter input. We focus on the comparison of the sedimentary environments, organic material inputs and potentials for hydrocarbon source rock exploration of oil shales from the said sections of the Lucaogou Formation. Moreover, organic geochemistry evidence of the paleogeographic relations between the sections is presented. This is also the first study ever to report the occurrence of oxygenated compounds in oil shales in the area investigated.

1.1. Geological setting

Located in the northern part of the Xinjiang Uygur Autonomous Region, Northwest China, the Junggar Basin is a triangular foreland deposit covering an area of approximately 137,000 [km.sup.2] [15]. The lateral extent of the Junggar Basin is marked by Palaeozoic fold mountain systems on its northwestern, northeastern and southern edges (Fig. 1a). The basement of the basin appears to be accretionary oceanic rocks and island arcs that were stabilized as late as the Carboniferous to the Early Permian [14, 16]. The Junggar Basin is a giant polycyclic superposition basin with multiple sets of hydrocarbon source rocks, with the Upper Permian source rocks, which are primarily exposed at the northern foothill of Bogda Mountain and the front of Kelameili Mountain, being the most important among them [11].

The study areas, i.e. the Yamalikeshan, Shuimogou and Sangonghe sections (Fig. 1b, simplified from [17, 18]), which are located at the northern foothill of Bogda Mountain in the southeastern part of the Junggar Basin, went through multiple stages of tectonic movement and intense folding. During the Late Carboniferous, the basin was still in the stage of peripheral foreland basins. The depositional environment evolved from a shallow marine system in the Carboniferous to a coastal system in the Early Permian [19, 20]. The Middle and Upper Permian series deposited in the alluvial fan-fluvial to lacustrine environment are mainly non-marine clastic sediments [21, 22]. During the Late Permian the Bogda Mountain area was in the extension rift setting and a deep to semi-deep lacustrine depositional environment [4, 9, 22, 23] (Fig. 2, modified after [10, 24]). In addition to the provenance derived from the Late Paleozoic magmatic belt in the North Tianshan block, the other major source of the Bogda area was synchronous pyroclastic material [23, 25]. During the Middle-Late Triassic to the Early Jurassic period, the Bogda area was in the weak extension and stable subsidence stage, and the sedimentary facies include braided river delta and lacustrine facies. Bogda Mountain began to uplift during the Middle-Late Jurassic and became a major provenance of the submountain region [23, 25]. Due to the huge south-north compressive stress caused by the India-Asia collision, the Bogda area uplifted rapidly and greatly since the Neogene. The Upper Permian oil shales at the northern foothill of the mountain were exposed and formed a large-scale oil shale distribution zone (Figs. 1b-c, modified after [19]), with a length of approximately 143 km and width of 9-15 km [1, 10].

Oil shales of the Lucaogou Formation in the Bogda area were mainly deposited in a deep to semi-deep lacustrine depositional environment, with the provenance derived from the Late Paleozoic magmatic belt in the North Tianshan block (Fig. 2). The Lucaogou Formation can be divided into three segments corresponding to three sedimentary systems (Fig. 3) [10, 13]. Segment 1 consists of siltstone interbedded with sandstone in the lower part and siltstone in the upper part, deposited in a strand shallow lake environment during the period of the lowstand systems tract. Segment 2 mainly consists of sandy shale and sandstone interbedded with sandy oil shale, and was deposited in shallow to semi-deep lake facies during the period of the transgressive stand system. Segment 3 was deposited in a semi-deep to deep lake environment during the period of the highstand systems tract. The latter segment chiefly consists of grey black thick-layered oil shale interbedded with disseminated dolomitic limestone concretions in the lower part and gradually changing to a submillimeter-scale oil shale layer interbedded with several thin layers of dolomitic limestone in the upper part [9, 10, 14]. Carbonate concretion precipitation in the lower part of segment 3 may be diagenetic and displace the primary structure. This distribution may reflect the corresponding bedrock controlled water column chemistry of alkali. However, the interbedded thin-layered dolomitic limestone in the upper part of the segment may have recorded the climate changes from unfavourable to appropriately warm for carbonate precipitation. Disseminated pyrite and siderite are common in the third segment of Lucaogou Formation mudstone [9, 10, 14]. The presence of pyrite and siderite crystals large enough to be seen with the naked eye may be due to their diagenetic origin [26, 27]. These minerals are common in the semi-deep to deep lacustrine environment, and are indicative of the redox condition of bottom waters. The Lucaogou Formation contains abundant fossils of freshwater organisms such as Tienshaniscus longipterus, Turfania taoshuyuanensis, Anthraconauta pseudophilipsii, Anthraconauta ilijinskiensis, Darwinula parallela, Darwinula ornata and Darwinula momitoria [28-31].

2. Material and methods

A total of 41 oil shale samples were collected from the Yamalikeshan (nine samples), Shuimogou (eight samples) and Sangonghe (twenty-four samples) outcrop sections (see Fig. 1b for approximate locations and Fig. 3 for positions on the outcrop section). The samples were labelled as indicated in Table 1. All samples were studied by Rock-Eval pyrolysis/TOC, solvent extraction, fractionation, gas chromatography-mass spectrometry (GC-MS) and total organic carbon isotope analyses. Analyses were conducted in the Key Laboratory of Petroleum Resources Research, Institute of Geology and Geophysics, Chinese Academy of Sciences.

Samples for TOC and organic carbonate isotope ([[delta].sup.13][]) analyses were decarbonated with 5% HCl, washed with distilled water to neutralize pH and dried in an oven at 50[degrees]C for 24 h. TOC analyses were conducted on the LECO CS-344 carbon/sulphur analyser. [[delta].sup.13][] analyses were performed with the MAT-252 Mass Spectrometer on C[O.sub.2] generated from the organic carbon that was oxidized in a furnace up to 850[degrees]C filled with CuO oxidant. Isotopic measurements had a standard deviation of 0.2 [per thousand] allowing for fluctuations higher than 0.5 [per thousand]. The stable carbon isotope values are reported in customary notation in [per thousand] relative to the VPDB carbonate standard.

The Rock-Eval pyrolysis was performed on 50 mg crushed rock samples (100 mesh) by using a Delsi Rock-Eval II instrument.

100 g crushed samples were Soxhlet extracted using chloroform continuously for 72 h. The concentrated extracts were separated into saturated hydrocarbons, aromatic hydrocarbons and non-hydrocarbons and eluted successively with n-hexane, toluene and chloroform:methanol (98:2), respectively, by using a silica gel-alumina chromatographic column (after precipitation of asphaltenes). The GC-MS analysis of saturated and aromatic hydrocarbons employed an HP 5973 MSD directly interfaced to an HP 6890 gas chromatograph fitted with a fused silica capillary column (30 m x 0.25 mm I.D., 0.25 [micro]m DB-5 coating). The GC oven temperature was increased from 80 (hold time 1 min) to 300[degrees]C (hold time 30 min) at 3[degrees]C/min. Helium was used as the carrier gas. MS was operated in EI mode at the ionization energy of 70 eV, with a source temperature of 230[degrees]C.

3. Results and discussion

3.1. Rock-Eval pyrolysis

Rock-Eval and TOC data of oil shale samples collected from the YMS, SMG and SGH sections are summarized in Table 1. The TOC content ranges of the samples are 1.45-35.60, 1.55-12.70 and 4.09-22.50%, respectively (Fig. 4a), the average TOC values are 8.66 (except for sample Y-5), 4.24 and 11.97%, respectively. So, the TOC values of all the samples remain within the range of 1.45-22.50%, except for one sample (Y-5 from the YMS section containing shale oil and being ignitable) whose TOC value is 35.60%. The total generation potential ([S.sub.1] + [S.sub.2]) of YMS, SMG and SGH oil shales varies from 1.90 to 216.30, between 10.18 and 67.77, and from 15.86 to 120.18 mg HC/g rock, respectively. The [S.sub.1] + [S.sub.2] value of the SGH oil shale is constantly higher, averaging 65.01 mg HC/g rock, compared with the 35.30 mg HC/g rock (without sample Y-5) and 23.68 mg HC/g rock for the YMS and SMG oil shales, respectively (Fig. 4b).

The values of TOC and [S.sub.1] + [S.sub.2] indicate that Lucaogou oil shales in the study area are rich in organic matter and have a high oil-generating potential, the SGH oil shale having the highest TOC and [S.sub.1] + [S.sub.2] values.

Oil shales of the three sections have hydrogen index (HI) values of 89-602, 405-621 and 375-663 mg HC/g TOC, averaging respectively 366, 516 and 528 mg HC/g TOC. Their oxygen index (OI) values range from 1 to 76, between 5 and 83, and from 19 to 49 mg C[O.sub.2]/g TOC, and average 36, 43 and 30 mg C[O.sub.2]/g TOC, respectively (Table 1). Oil shale from the SGH section is characterized by higher hydrogen index values and lower oxygen index values. On plots of HI vs [T.sub.max]: (Fig. 5a, the kerogen type line based on [32]) and plots of HI vs OI (Fig. 5b, the kerogen type line based on [33]), samples from the three sections plot around the Type II boundary, with most of the YMS samples being in the Type II-III area, the SMG samples along the Type II line, and the SGH samples in the Type I-II area. Based on the plot of [S.sub.2] vs TOC, the organic matter in all oil shale samples can be classified as Type [II.sub.1] kerogen, except for samples Y-4-3 and Y-4-1 whose kerogen is of Type III (Fig. 6, without sample Y-5, the kerogen type line based on [34]).

Dembicki [35] observed that when 25% Type III kerogen is mixed with Type I kerogen, the source rock appears to contain Type II kerogen, and when more Type III kerogen is added to the mix, the data could easily be interpreted as a mixture of types II and III [35]. Obviously, the quality of the kerogen of oil shales becomes gradually higher from the YMS section to the SGH section. Therefore, it is more reasonable to define the kerogen type of the three oil shales as a mixture of types I and III, with a higher input of terrestrial organic matter in the YMS oil shale compared with the oil shales of the other two sections. Based on this it may be stated that the oil shales may have been deposited in a single lake with the Sangonghe section as a depocenter which was further away from external sources.

As is clear from the above, there are great differences in TOC and S2 values among the samples even within the same section, which is usually considered homogeneous. This may be explained by the different organic richness of the samples caused by the different organic input into the sediments due to seasonal changes.

The [T.sub.max] values which range from 432 to 460, between 434 and 441, and from 433 to 446[degrees]C, and average 437, 437 and 440[degrees]C for the three respective sections (Table 1) suggest that their thermal maturity is immature to mature, early in the oil window (Fig. 5a). This pronouncement is in agreement with the finding of a previous report about Upper Permian oil shales in the southern Junggar Basin with [R.sub.o] of 0.54-0.91% [36].

3.2. Chloroform extract and its group composition

The chloroform extract (CE) content of all the oil shale samples of the Lucaogou Formation ranged from 0.013 to 0.373% (wt% of rock), being mostly between 0.050 and 0.300%, with an average value of 0.175% (Table 2). The average CE value of the samples was 0.163, 0.117 and 0.191%, respectively, with the highest value occurring in the SGH oil shale and the lowest in the SMG oil shale. The total hydrocarbon (saturated hydrocarbons plus aromatic hydrocarbons) content of the samples was between 52 and 1917 ppm (without sample Y-5) and averaged 700 ppm, the SGH oil shale possessing the highest average value, 788 ppm. The average values for the YMS and SMG oil shales were respectively 569 and 565 ppm. So the yield of soluble organic matter of the samples was relatively high, indicating that the oil shales are good hydrocarbon source rocks, the SGH oil shale being the richest source rock.

The CEs consist of 8.9-47.8% saturates, 2.2-26.2% aromatics, 30.3-85.3% non-hydrocarbons and 1.2-8.9% asphaltenes (wt% of the extract) (Table 2). In general, the ratio of saturated to aromatic hydrocarbons in Type I kerogen is above 3, between 3 and 1 in Type II kerogen, and below 1 in Type III kerogen [37]. For the YMS, SMG and SGH oil shales, this ratio varies between 0.77 and 2.40, from 1.18 to 3.57, and between 1.36 and 4.45, averaging 1.34, 2.22 and 2.70, respectively (Table 2). The ratio increases from the YMS section to the SGH section, which is indicative of the higher quality of kerogen of the SGH oil shale, as also demonstrated by the Rock-Eval data analysis. In view of the above, we can conclude that the kerogen types of oil shales of the three sections are a mixture of types I and III, with the SGH section oil shale having experienced a higher sapropelic parent material input.

3.3. Molecular composition of organic matter

3.3.1. n-Alkanes and isoprenoids

Gas chromatograms of the saturated hydrocarbons isolated from the oil shale samples under study are shown in Figure 7, their parameters are given in Table 3. Generally, n-alkanes are in the [C.sub.12]-[C.sub.35] range, showing a unimodal distribution. The ratio of [summation]n[C.sub.21.sup.-]/[summation]n[C.sub.22.sup.+] is used as a relative indicator of terrigenous vs lower-organism organic matter input, but is also sensitive to thermal maturation and biodegradation. Long-chain n-alkanes in the range [C.sub.10]-[C.sub.24] degrade most rapidly due to biological activity. Normal alkanes of greater chain length are more difficult to be consumed by microorganisms. In view of this, the ratio of [summation]n[C.sub.21.sup.-]/[summation]n[C.sub.22.sup.+] should decrease due to biodegradation. Since the kerogen of the YMS oil shale is mostly of Type III, suggesting a significant input of land-plant organic matter, the relatively high values of [summation]n[C.sub.21.sup.-]/[summation]n[C.sub.22.sup.+] (0.55-2.87) for this oil shale may be the consequence of maturation. In addition, a study demonstrated that certain nonmarine algae, e.g., Scenedesmus quadricauda, Tetrahedron sp., Anacystis montana and Botryococcus braunii, produce a significant amount of both medium- and high-molecular-weight paraffins [38]. Therefore, the simultaneous presence of the above algae in the SMG and SGH oil shale samples may explain their higher ratio of [summation]n[C.sub.21.sup.-]/[summation]n[C.sub.22.sup.+].

The values of the odd-to-even preference ratio of n-alkanes (OEP) for samples Y-5, Y-4-8, Y-4-6 and Y-4-5 are 0.68, 0.82, 0.75 and 0.84, respectively. Of n-alkanes, n-C20 turns out to be the most abundant, showing the predominance of even-numbered species, especially those ranging from n-[C.sub.18] to n-[C.sub.22], which is indicative of microbial activities in sediments [39]. In the extracts from the SMG and SGH oil shales (Fig. 7), mainly n-[C.sub.20] to n-[C.sub.23] alkanes prevail, implying the contribution of non-marine brackish water algae or aquatic macrophytes [37, 40-43]. However, the ratio of [summation]n[C.sub.21.sup.-]/[summation]n[C.sub.22.sup.+] for most of the SMG oil shale samples is lower than 1, suggesting the origin of lipids from higher plants [44-47]. Therefore, the oil shale of the SMG section may represent a mixed-source depositional environment including higher terrestrial plants, aquatic macrophytes and algae. In contrast, the ratio of [summation]n[C.sub.21.sup.-]/[summation]n[C.sub.22.sup.+] for most of the SGH oil shale samples is higher than 1, pointing to the provenance dominated by lower organisms.

In most samples, pristane (Pr) is more abundant than phytane (Ph), the Pr/Ph ratio ranging from 0.84 to 1.75 (Fig. 7, Table 3). On the Pr/n[C.sub.17] vs Ph/n[C.sub.18] plot (Fig. 8), the samples mostly lie within the zone of mixed organic matter sources and transitional environments, near the reducing zone. This indicates a weakly oxic to reducing transitional depositional environment for the oil shales under study [48]. Several SGH oil shale samples plot in the reducing zone in Figure 8, referring to the lower organisms input in a reducing environment.

3.3.2. Terpanes

The m/z 191 chromatograms of terpanes determined by GC-MS are shown in Figure 9, the homohopane parameters of the studied oil shale samples are reported in Table 3. [C.sub.31] is the dominant homohopane. The homohopanes distribution exhibits a decrease from [C.sub.31] to [C.sub.35] in all the samples (Fig. 9). [C.sub.34] and [C.sub.35] homohopanes occur only in low quantities or cannot be detected in the extracts, suggesting a fresh-water non-marine depositional environment [49].

Gammacerane was also present in all samples, exhibiting a characteristic peak. The gammacerane index (gammacerane/[C.sub.30][alpha][beta]-hopane) varies from 7 to 14, between 5 and 16, and from 2 to 25% (Table 3) for the YMS, SMG, and SGH oil shales, respectively. The presence of gammacerane indicates a stratified water column during source rock sedimentation in marine and nonmarine environments, commonly associated with hypersalinity at depth [40, 49-52]. Concentrations of gammacerane are not significant in the oil shales of the studied sections, indicating brackish water depositional conditions.

The 22S/(22S + 22R) ratio for [C.sub.31] homohopane increases with thermal maturity (0-0.6) and reaches the equilibrium value at 0.58-0.62 [53]. After reaching equilibrium at the early oil-generative stage, no further maturity information is available because the 22S/(22S + 22R) ratio remains constant [49, 54]. For YMS, SMG and SGH oil shale samples the ratio ranges from 0.58 to 0.61, between 0.58 and 0.60, and from 0.58 to 0.60, respectively, having attained the so-called "equilibrium value". This indicates that the samples have reached or surpassed the early phase of oil generation (vitrinite reflectance ca 0.5%).

During maturation, [C.sub.27] 17[alpha]-trisnorhopane (Tm) is less stable than [C.sub.27] 18a-trisnorhopane (Ts) and the Ts/Tm ratio increases with maturity [55]. This ratio is also dependent on sedimentary facies and depositional environment. Redox potential can have a higher effect on the relative amount of Ts and Tm than maturity, with the Ts/Tm ratio smaller than 1 even in highly mature anoxic sediments. With the similar thermal maturity, sediments deposited in the anoxic environment tend to have lower Ts/Tm ratio than those deposited in the oxidizing environment [40, 56]. In the oil shale samples analysed, the Ts/Tm ratio values (0.27-0.75, 0.24-0.38 and 0.06-0.42 for the YMS, SMG and SGH sections, respectively) are not consistent with those of the other maturity parameters, such as [T.sub.max] and the [alpha][beta]C31 22S/(22S + 22R) ratio. These relatively low values of Ts/Tm in the oil shale samples of the three sections may indicate anoxic depositional conditions, and, probably due to the deeper water, a more reducing environment for the SGH section whose Ts/Tm ratio is lower than those for the other two sections.

Established from organic geochemical data the water depth distribution agrees well with the assumption about the area's paleogeography put forward by Peng et al. [13], Carroll et al. [16] and Wartes et al. [20]. Based on the correlation between the lithostratigraphic cross sections of Upper Permian rocks, the Junggar and Turpan-Hami basins were supposed to have been occupied by a single large lake that was comparable in size to the modern Caspian Sea [16, 20]. According to the well connecting profile and sequence stratigraphic data, Peng et al. [13] suggested that the YMS, SMG and SGH sections were occupied by a single large lake during the deposition period of the Lucaogou Formation, with the Sangonghe section as a depocenter having the maximum water depth and being further away from the external source. In the Lucaogou Formation, the sediments thickness was the greatest, up to 1000 m, in the SGH section, which then decreased significantly from the east to the west, reaching below 400 m in the YMS section [13].

3.3.3. Steranes

The distribution of regular [C.sub.27], [C.sub.28] and [C.sub.29] steranes can reflect the source of organic matter in sediments. Previous studies have shown that the enhanced amount of [C.sub.27] steranes may be derived from marine phytoplankton, the high concentration of [C.sub.28] steranes may be related to lacustrine algae and the increased amount of C29 steranes may indicate the contribution from higher land plants [40, 48, 57]. In addition, it has been proposed that numerous microorganisms such as primitive algae [58], cyanobacteria [59], diatoms and freshwater eustigmatophytes [43] could be alternative sources for [C.sub.29] steranes.

Most of the oil shale samples under study have a similar distribution of [C.sub.27], [C.sub.28] and [C.sub.29] steranes--[C.sub.29] > [C.sub.28] > [C.sub.27] (Figs. 10 and 11, and Table 3), which is a sign of their similar organic matter type and depositional paleoenvironment. The slightly higher amount of [C.sub.29] steranes (32-57%) does not necessarily suggest the dominance of higher plant organic matter input, since the compounds may also originate from other sources. In all of the studied oil shale samples, the concentrations of [C.sub.28] steranes (22-46%) and C29 steranes (32-57%) are close, which is indicative of a high contribution of lacustrine algae. The [C.sub.28]/[C.sub.29] sterane ratio of SGH oil shale samples is higher than those of YMS and SMG oil shale samples, signifying a higher input of lacustrine algae in the SGH section compared to the other two.

For [C.sub.29] steranes the isomerization ratios S/(S + R) and [alpha][beta][beta]/([alpha][alpha][alpha] + [alpha][beta][beta]) are the two most commonly used sterane maturity parameters. Both increase with maturity and reach equilibrium values of approximately 0.55 (vitrinite reflectance about 0.8-0.9%) and ca 0.70 (vitrinite reflectance about 0.911.0%) around peak oil generation, respectively [49, 54, 60]. In YMS, SMG and SGH oil shale samples, the above ratios are lower than the equilibrium values (Table 3, Fig. 12), suggesting that oil shales of the three sections have not reached the thermal maturity level of the late stage of oil generation. These ratios also show that the SMG and SGH oil shale samples are slightly less mature than those of the YMS section (Fig. 12), which is consistent with the values of [summation]n[C.sub.21.sup.-]/[summation]n[C.sub.22.sup.+].

3.3.4. Oxygenated compounds

Of oxygenated compounds, ketones, aldehydes and fatty acid methyl esters (FAMEs) were detected in the studied samples. n-Alkanones were found in all samples. Samples Y-4-6 and Y-4-5 from the YMS section contained n-aldehydes, with the carbon number distribution of [C.sub.12]-[C.sub.27] and [C.sub.12]-[C.sub.24], both maximized at [C.sub.21] (Fig. 13). There are two possible sources for these n-aldehydes. One is the microbial alteration of other compounds, such as n-alkanes, in oil shale. In this case, the distribution of aldehydes is similar to that of n-alkanes and ketones [61, 62]. Another possible source is the living organisms growing in or around the lake. In this case, the n-aldehydes in the sediments are dominated by the [C.sub.22]-[C.sub.30] even-carbon-numbered ones. To the best of our knowledge, the supporting studies in this case are all focused on contemporary lake sediments [63, 64]. This may indicate that the n-aldehydes from living organisms cannot be preserved after long geological evolution.

The distribution pattern of aldehydes detected in samples Y-4-6 and Y-4-5 is similar to those of alkanes and ketone assemblages (Fig. 13). Based on the above discussion, it is suggested that the n-aldehydes in the oil shale samples from the YMS section may have been derived from other compounds, such as n-alkanes, as a result of their microbial diagenesis.

A prominent suite of FAMEs, [C.sub.12]-[C.sub.30] or [C.sub.12]-[C.sub.26], was identified in samples Y-4-2 and Y-4-1 (Fig. 14). Since the solvent used in the Soxhlet extraction is chloroform, the FAMEs detected in the extracts cannot be the derivatives of fatty acids liberated from the sediments. The distribution of these esters in both the samples maximized at [C.sub.16], with even-numbered species predominating. Studies of FAMEs in geological structures are rare and there are none regarding their occurrence in organisms. Severely alkaline-neutral environments are needed for the existence of FAMEs in geological structures [65, 66]. Naturally occurring FAMEs are considered to originate from higher plant leaf waxes and suberin [67]. Therefore, the occurrence of FAMEs in the two samples may indicate an alkaline-neutral depositional environment. Furthermore, the kerogen type of sample Y-4-1 is III, unlike the other YMS oil shale samples whose kerogen type is a mixture of types I and III. Thus, the occurrence of FAMEs may also be related to the higher plant input.

In addition, it is worth noting that none of the samples contained aldehydes and FAMEs at the same time. Since aldehydes are very easily oxidized and generate carboxylic acids, their occurrence in the oil shale formation may reflect a reducing lacustrine depositional environment. In contrast, FAMEs are very easily reduced and generate alcohols [68]. Therefore, their presence in two YMS oil shale samples may mirror an oxidizing depositional environment. This might explain why aldehydes and FAMEs cannot coexist. The depositional environment changes of the YMS section from oxidizing to anoxic conditions may have been caused by lake level changes. If this was the case, then samples Y-4-6 and Y-4-5 were deposited during the low-lake-level period and samples Y-4-2 and Y-4-1 during the high-lake-level period. The lake level change may have also led to the change of the distance from external sources like higher plants, which in turn accounts for the kerogen type difference between the oil shale samples studied.

3.4. Organic carbon isotope

The total organic carbon isotope ([[delta].sup.13][]) value is an important proxy for tracing biological sources and palaeoenvironment in lakes. For the samples of the YMS section the [[delta].sup.13][] values varied from -32.2 to -24.8 [per thousand], with an average value of -28.6 [per thousand]. The respective figures for the samples from the SMG section ranged between -31.8 and -25.7 [per thousand], with an average value of -27.8 [per thousand], and for the samples from the SGH section from -33.2 to -29.2 [per thousand], averaging -30.9 [per thousand].

Based on their photosynthetic processes, terrestrial plants are classified into two types: [C.sub.3] and [C.sub.4]. The [[delta].sup.13][] values of [C.sub.3] plants range from -34.0 to -22.0 [per thousand], while [C.sub.4] plants have [[delta].sup.13][] values varying from -14.0 to -10.0 [per thousand]. The great carbon isotopic value difference between terrestrial [C.sub.3] and [C.sub.4] plants is caused by the different types of photosynthesis [69-72]. In addition, aquatic organisms have higher negative [[delta].sup.13][] values than higher terrestrial plants, and deep water plants have higher negative [[delta].sup.13][] values than shallow water plants [72, 73].

Based on the above discussion, the [[delta].sup.13][] values indicate that higher terrestrial plants are dominated by [C.sub.3] plants, suggesting a cool and humid palaeoclimate. This agrees with the evidence of Upper Permian flora which matches with a cool, temperate climate [4, 74-77]. In general, the negative [[delta].sup.13][] values of the SGH oil shale are higher than those of oil shales of the other two sections (Table 1, Fig. 15). As seen from Figure 15, there is a negative correlation between the [[delta].sup.13][] and HI values of oil shale samples. Therefore, we suggest that the higher negative [[delta].sup.13][] values of the SGH oil shale compared to those of the YMS and SMG oil shales are the consequence of a higher algal material input, indicating that during the sedimentation period of the Lucaogou Formation the lake water was deeper in the SGH section.

4. Conclusions

1. Oil shales from the Yamalikeshan, Shuimogou and Sangonghe sections of the Lucaogou Formation in the southeastern Junggar Basin, Northeast China are rich in organic matter and have a high hydrocarbon generation potential, as suggested by bulk Rock-Eval and chloroform extract analyses. The different organic content of the samples studied implies that the Sangonghe oil shale has the highest TOC, [S.sub.1] + [S.sub.2] and chloroform extract values and Sangonghe is the richest hydrocarbon source rock section as established in this study.

2. The kerogen type of Lucaogou Formation oil shales in the study area is a mixture of types I and III, the Yamalikeshan oil shale having enjoyed a relatively high contribution of terrestrial organic matter and the Sangonghe oil shale a higher algal material input, as indicated by RockEval data, chloroform extract analyses, and the normal sterane distribution and organic carbon isotopic data. The kerogen type of oil shales gradually changes from Type III to Type I from the Yamalikeshan section to the Sangonghe section, along the southwest-northeast direction through the foothill of Bogda Mountain. Based on this it appears that the oil shales may have been deposited in a single lake with the Sangonghe section as a depocenter, which was further away from external sources, while the Yamalikeshan section area was closest to the lake shore.

3. [T.sub.max] values and hopane isomerisation ratios indicate that the Lucaogou Formation oil shales are low mature to mature, in the early oil window, corresponding to the vitrinite reflectance of 0.54-0.91% reported in the literature. Sterane isomerisation ratios suggest that the oil shale of the Yamalikeshan section is slightly more mature than those of the other two sections.

4. The oil shales analysed in this study were deposited in semi-deep to deep lacustrine environments with fresh to brackish water, under mild anoxic conditions of a cool, humid paleoclimate, as indicated by the plots of Pr/n[C.sub.17] vs Ph/n[C.sub.18], the values of Ts/Tm and the organic carbon isotope composition. Some layers were partly subjected to microbial modification, as suggested by the n-alkane distribution. The Sangonghe section suggested a more reducing, higher salinity and deeper depositional environment and had a more significant aquatic lower organism input compared with the other two sections.

5. In samples Y-4-6 and Y-4-5 from the Yamalikeshan section, ketones and aldehydes were present, showing a similar distribution as n-alkanes, which suggests that aldehydes may be the product of the microbial oxidation of n-alkanes or other lipids. In samples Y-4-2 and Y-4-1 from the same section, ketones and fatty acid methyl esters occurred, indicating an alkaline-neutral depositional environment during the corresponding deposition intervals. However, no sample contained ketones, aldehydes and fatty acid methyl esters simultaneously, due to the fact that the latter two need a reducing and oxidizing environment respectively to be preserved. This unique occurrence of aldehydes and fatty acid methyl esters is indicative of the varying depositional environment of the Yamalikeshan section.

doi: 10.3176/oil.2016.4.01


We would like to thank the anonymous reviewers for giving useful comments on the paper. This research was supported by the Chinese Academy of Sciences Key Project (Grant No. XDB10030404), the Major State Basin Research Development Program of China (No. 2012CB214701), the Chinese Academy of Sciences Key Project (Grant No. XDB03020405), the National Natural Science Foundation of China (Grant Nos. 41172169, 41272147, 40672123), the Western Light Joint Scholars Project, and the Key Laboratory Project of Gansu Province (Grant No. 1309RTSA041).


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Presented by J. Qian and A. Soesoo

Received June 15, 2015


(a) State Key Laboratory of Organic Geochemistry, Guangzhou Institute of Geochemistry, Chinese Academy of Sciences, Guangzhou 510640, China

(b) Gansu Provincial Key Laboratory of Petroleum Resources, Key Laboratory of Petroleum Resources Research, Institute of Geology and Geophysics, Chinese Academy of Sciences, Lanzhou 730000, China

(c) State Key Laboratory of Petroleum Resources and Prospecting, College of Geosciences, China University of Petroleum, Beijing 102249, China

(d) University of Chinese Academy of Sciences, Beijing 100049, China

* Corresponding author: e-mail,

Table 1. TOC and Rock-Eval data and organic isotope compositions for
Lucaogou oil shale samples, SE Junggar Basin

Sample   Section   TOC, %   [S.sub.1], mg    [S.sub.2], mg
                              HC/g rock        HC/g rock

Y-5        YMS     35.60         1.82            214.48
Y-4-8               9.48         0.62            38.32
Y-4-7              12.50         0.80            55.26
Y-4-6               9.13         0.31            39.26
Y-4-5              14.30         0.72            63.96
Y-4-4              11.70         0.62            45.54
Y-4-3               2.04         0.09             1.83
Y-4-2               8.65         0.59            32.56
Y-4-1               1.45         0.17             1.73
S-2-7      SMG     12.70         1.21            66.56
S-2-6               4.16         1.45            17.36
S-2-5               4.17         1.33            16.92
S-2-4               2.31         0.59            13.04
S-2-3               1.55         2.22             7.96
S-2-2               1.74         2.56            10.85
S-2-1               4.39         1.92            24.31
S-1                 2.89         5.91            15.28
G-2-23     SGH     10.70         2.01            70.32
G-2-22              8.83         0.93            46.04
G-2-21             11.30         1.12            66.96
G-2-20             10.80         1.28            59.80
G-2-19             15.20         2.32            83.16
G-2-18              9.60         0.72            45.20
G-2-17             21.50         1.25            86.88
G-2-16              5.86         0.47            30.34
G-2-15              6.89         0.56            30.46
G-2-14              5.16         0.40            23.60
G-2-13              9.69         0.61            46.56
G-2-12              4.37         0.28            23.96
G-2-11             17.70         1.88            85.24
G-2-10              6.67         0.44            29.64
G-2-9              11.80         1.50            60.34
G-2-8               4.09         0.51            15.35
G-2-7               5.96         0.56            39.52
G-2-6              22.50         2.06            118.12
G-2-5               8.43         0.67            50.34
G-2-4              18.90         0.61            112.24
G-2-3              21.30         1.86            116.25
G-2-2              14.10         1.17            81.28
G-2-1              18.60         2.90            108.76
G-1                17.30         1.86            101.96

Sample    [S.sub.1] +     HI, mg         OI, mg          Tmax,
          [S.sub.2],     HC/g TOC   C[O.sub.2]/g TOC   [degrees]C
         mg HC/g rock

Y-5         216.30         602             1              460
Y-4-8        38.94         404             26             437
Y-4-7        56.06         442             37             437
Y-4-6        39.57         430             42             438
Y-4-5        64.68         447             36             440
Y-4-4        46.16         389             34             434
Y-4-3        1.92           89             76             436
Y-4-2        33.15         376             22             432
Y-4-1        1.90          119             52             439
S-2-7        67.77         524             5              440
S-2-6        18.81         417             35             441
S-2-5        18.25         405             37             435
S-2-4        13.63         564             33             437
S-2-3        10.18         513             65             440
S-2-2        13.41         621             83             435
S-2-1        26.23         553             55             434
S-1          21.19         528             32             434
G-2-23       72.33         657             40             444
G-2-22       46.97         521             23             440
G-2-21       68.08         592             26             444
G-2-20       61.08         553             20             445
G-2-19       85.48         547             20             446
G-2-18       45.92         470             35             439
G-2-17       88.13         404             39             438
G-2-16       30.81         517             36             441
G-2-15       31.02         442             42             443
G-2-14       24.00         457             20             438
G-2-13       47.17         480             37             438
G-2-12       24.24         548             30             442
G-2-11       87.12         481             49             436
G-2-10       30.08         444             36             441
G-2-9        61.84         511             28             443
G-2-8        15.86         375             46             440
G-2-7        40.08         663             31             441
G-2-6       120.18         524             20             436
G-2-5        51.01         597             32             433
G-2-4       112.85         593             19             440
G-2-3       118.11         546             23             435
G-2-2        82.45         576             27             438
G-2-1       111.66         584             26             439
G-1         103.82         589             23             442

Sample   [[delta].sup.13]
          [per thousand]

Y-5           -32.2
Y-4-8         -28.6
Y-4-7         -31.0
Y-4-6         -29.8
Y-4-5         -29.6
Y-4-4         -27.6
Y-4-3         -24.8
Y-4-2         -27.8
Y-4-1         -26.4
S-2-7         -28.5
S-2-6         -25.7
S-2-5         -26.6
S-2-4         -28.8
S-2-3         -26.9
S-2-2         -28.3
S-2-1         -31.8
S-1           -25.8
G-2-23        -33.2
G-2-22        -29.7
G-2-21        -32.6
G-2-20        -31.1
G-2-19        -32.2
G-2-18        -32.2
G-2-17        -32.2
G-2-16        -31.0
G-2-15        -29.8
G-2-14        -29.2
G-2-13        -30.3
G-2-12        -31.8
G-2-11        -32.0
G-2-10        -30.1
G-2-9         -29.2
G-2-8         -28.3
G-2-7         -31.2
G-2-6         -32.0
G-2-5         -31.1
G-2-4         -28.7
G-2-3         -31.5
G-2-2         -31.1
G-2-1         -31.1
G-1           -31.3

Abbreviations: YMS--Yamalikeshan, SMG--Shuimogou, SGH--Sangonghe.

Table 2. Bulk geochemical parameters for Lucaogou oil shale samples,
SE Junggar Basin

Sample   Section   Chloroform   Saturated   Aromatic    Non-HC
                   extract, %   HC (a), %   HC (a), %   (a), %

Y-5        YMS       0.314        40.7        26.2       30.9
Y-4-8                0.188        24.5        20.6       53.2
Y-4-7                0.338        14.9        13.5       68.4
Y-4-6                0.133        18.8        21.7       57.3
Y-4-5                0.231         9.6        12.5       75.6
Y-4-4                0.168        18.9        12.9       64.9
Y-4-3                0.013        25.0        15.3       52.5
Y-4-2                0.199        23.2        22.0       51.8
Y-4-1                0.033        45.6        19.0       30.3
S-2-7      SMG       0.233        31.3        21.9       43.9
S-2-6                0.117        29.6         8.3       60.4
S-2-5                0.064        32.1        12.0       53.7
S-2-4                0.106        28.9        14.8       49.9
S-2-3                0.037        41.8        17.5       35.7
S-2-2                0.097        22.7        15.6       52.8
S-2-1                0.034        23.5        19.9       50.6
S-1                  0.246        41.4        13.5       43.2
G-2-23     SGH       0.373        32.8         7.7       50.7
G-2-22               0.233        47.0        12.4       38.7
G-2-21               0.274        28.4        10.6       58.2
G-2-20               0.294        34.5        15.3       47.5
G-2-19               0.316        43.9        16.5       38.1
G-2-18               0.198        28.6        16.8       52.2
G-2-17               0.228        12.0         6.5       74.1
G-2-16               0.105        37.4        12.4       46.1
G-2-15               0.137        47.8        12.6       36.9
G-2-14               0.094        35.7        18.9       41.8
G-2-13               0.134        19.9        14.6       63.1
G-2-12               0.088        40.1        22.2       34.5
G-2-11               0.176         9.8         7.2       74.8
G-2-10               0.096        33.4        16.6       48.1
G-2-9                0.362        36.9        16.0       45.9
G-2-8                0.074        43.6        16.7       37.2
G-2-7                0.103        15.5         6.4       75.1
G-2-6                0.191        16.3         7.7       73.3
G-2-5                0.144        28.0         9.7       60.3
G-2-4                0.285        10.8         3.0       79.6
G-2-3                0.187         8.9         2.2       85.3
G-2-2                0.192        30.2        10.3       58.1
G-2-1                0.309        31.5         7.1       60.0
G-1                  0.181        18.1         6.0       74.0

Sample   Asphaltene, %      Total      Saturated HC/
                         HC (a), ppm    aromatic HC

Y-5           2.2           2102           1.55
Y-4-8         1.7            846           1.19
Y-4-7         3.2            959           1.10
Y-4-6         2.2            539           0.87
Y-4-5         2.3            510           0.77
Y-4-4         3.3            535           1.47
Y-4-3         7.2            52            1.63
Y-4-2         3.0            897           1.05
Y-4-1         5.1            214           2.40
S-2-7         2.9           1241           1.43
S-2-6         1.7            443           3.57
S-2-5         2.2            282           2.68
S-2-4         6.4            464           1.95
S-2-3         5.0            222           2.39
S-2-2         8.9            371           1.46
S-2-1         6.0            146           1.18
S-1           1.9           1349           3.07
G-2-23        8.8           1512           4.24
G-2-22        1.9           1385           3.79
G-2-21        2.8           1067           2.68
G-2-20        2.7           1464           2.25
G-2-19        1.6           1911           2.66
G-2-18        2.4            897           1.70
G-2-17        7.4            422           1.83
G-2-16        4.1            525           3.02
G-2-15        2.7            827           3.82
G-2-14        3.6            512           1.89
G-2-13        2.4            461           1.36
G-2-12        3.2            546           1.81
G-2-11        8.2            300           1.37
G-2-10        1.8            481           2.01
G-2-9         1.2           1917           2.31
G-2-8         2.5            447           2.61
G-2-7         3.0            226           2.42
G-2-6         2.7            458           2.13
G-2-5         2.0            544           2.88
G-2-4         6.6            394           3.53
G-2-3         3.6            208           3.97
G-2-2         1.4            779           2.93
G-2-1         1.4           1193           4.45
G-1           1.9            436           3.02

(a) HC = hydrocarbons. Abbreviations: YMS--Yamalikeshan,
SMG--Shuimogou, SGH--Sangonghe.

Table 3. Molecular parameters for the extractable organic matter of
Lucaogou oil shale samples, SE Junggar Basin

Sample   Section   [C.sub.range]   [C.sub.max]   [C.sub.21.sup.-]/

Y-5        YMS         13-29           20              2.43
Y-4-8                  12-35           20              2.19
Y-4-7                  12-33           17              2.36
Y-4-6                  12-33           20              2.53
Y-4-5                  13-35           20              2.75
Y-4-4                  13-35           21              1.61
Y-4-3                  13-35           17              1.38
Y-4-2                  13-33           17              2.87
Y-4-1                  13-35           25              0.55
S-2-7      SMG         12-35           17              3.43
S-2-6                  12-37           21              1.14
S-2-5                  12-35           21              0.99
S-2-4                  13-35           27              0.23
S-2-3                  13-35           23              0.59
S-2-2                  12-35           23              0.61
S-2-1                  12-35           22              1.02
S-1                    12-37           23              0.45
G-2-23     SGH         12-35           23              0.48
G-2-22                 12-35           23              0.75
G-2-21                 12-35           23              0.85
G-2-20                 12-35           23              1.12
G-2-19                 12-35           23              1.18
G-2-18                 12-35           23              0.90
G-2-17                 12-35           22              0.95
G-2-16                 12-35           23              1.12
G-2-15                 12-35           23              0.81
G-2-14                 12-35           23              1.10
G-2-13                 12-35           17              1.60
G-2-12                 12-35           23              0.70
G-2-11                 12-35           22              1.18
G-2-10                 12-35           23              0.86
G-2-9                  12-35           23              0.82
G-2-8                  12-37           23              0.70
G-2-7                  12-35           20              1.54
G-2-6                  12-33           20              1.57
G-2-5                  12-37           22              0.94
G-2-4                  13-33           20              2.62
G-2-3                  13-37           20              1.73
G-2-2                  12-37           21              1.25
G-2-1                  12-35           21              0.87
G-1                    12-35           17              2.06

Sample   OEP    Pr/Ph   Pr/[C.sub.17]   Pr/[C.sub.18]   Ts/Tm

Y-5      0.68   1.04        0.53            0.50        0.47
Y-4-8    0.82   1.31        0.33            0.26        0.43
Y-4-7    1.03   1.10        0.29            0.37        0.36
Y-4-6    0.75   1.36        0.22            0.15        0.40
Y-4-5    0.84   1.36        0.20            0.14        0.36
Y-4-4    1.07   1.35        0.30            0.23        0.38
Y-4-3    1.01   1.52        0.50            0.38        0.27
Y-4-2    1.07   1.42        0.18            0.16        0.36
Y-4-1    1.03   1.33        0.77            0.51        0.75
S-2-7    1.10   1.31        0.17            0.16        0.38
S-2-6    1.06   1.31        0.75            0.57        0.26
S-2-5    1.02   1.16        0.85            0.76        0.24
S-2-4    1.09   1.21        1.55            1.22        0.25
S-2-3    1.14   1.02        0.39            0.38        0.31
S-2-2    1.11   1.23        0.61            0.50        0.25
S-2-1    0.90   1.56        0.36            0.25        0.25
S-1      1.16   1.21        0.67            0.58        0.25
G-2-23   1.12   0.93        1.12            1.29        0.36
G-2-22   1.13   1.38        1.63            1.18        0.30
G-2-21   1.20   1.16        0.91            0.74        0.30
G-2-20   1.07   0.87        0.77            0.74        0.32
G-2-19   1.06   1.19        0.75            0.69        0.29
G-2-18   1.07   1.23        0.66            0.58        0.32
G-2-17   0.98   1.21        0.63            0.49        0.24
G-2-16   1.18   1.44        0.45            0.32        0.30
G-2-15   1.20   0.92        0.57            0.63        0.33
G-2-14   1.14    084        0.50            0.47        0.25
G-2-13   1.09   1.36        0.85            0.69        0.25
G-2-12   1.09   1.25        0.92            0.82        0.30
G-2-11   0.89   1.43        0.77            0.59        0.28
G-2-10   1.11   1.34        1.49            1.02        0.22
G-2-9    1.03   1.00        1.32            1.38        0.36
G-2-8    1.10   1.27        0.57            0.45        0.38
G-2-7    0.93   1.31        0.91            0.65        0.25
G-2-6    0.97   1.20        0.73            0.67        0.22
G-2-5    0.98   1.12        0.50            0.42        0.33
G-2-4    0.77   1.45        0.14            0.07        0.30
G-2-3    0.84   1.31        0.17            0.10        0.42
G-2-2    1.00   1.47        0.97            0.62        0.33
G-2-1    1.04   1.45        0.68            0.39        0.29
G-1      0.98   1.75        0.86            0.54        0.06

Sample    Gamma         22S/(22S + 22R)       [alpha][beta][beta]/
         index (a)   [C.sub.31] homohopane   ([alpha][beta][beta] +
                                               [C.sub.29] sterane

Y-5         11               0.59                     0.37
Y-4-8       12               0.58                     0.31
Y-4-7       12               0.59                     0.31
Y-4-6       12               0.60                     0.32
Y-4-5       14               0.61                     0.28
Y-4-4        7               0.60                     0.27
Y-4-3        7               0.60                     0.29
Y-4-2       10               0.60                     0.28
Y-4-1        7               0.61                     0.35
S-2-7        5               0.59                     0.33
S-2-6       10               0.59                     0.26
S-2-5        9               0.58                     0.29
S-2-4        9               0.59                     0.27
S-2-3        5               0.59                     0.26
S-2-2       16               0.59                     0.23
S-2-1       10               0.60                     0.27
S-1          8               0.60                     0.27
G-2-23      17               0.59                     0.17
G-2-22       4               0.58                     0.17
G-2-21       3               0.58                     0.21
G-2-20       6               0.59                     0.24
G-2-19       3               0.59                     0.23
G-2-18       5               0.58                     0.22
G-2-17       4               0.59                     0.19
G-2-16       2               0.59                     0.21
G-2-15       3               0.60                     0.23
G-2-14       2               0.59                     0.21
G-2-13       4               0.60                     0.23
G-2-12       5               0.58                     0.22
G-2-11       6               0.58                     0.21
G-2-10       3               0.59                     0.19
G-2-9       11               0.59                     0.24
G-2-8        9               0.60                     0.23
G-2-7       11               0.58                     0.26
G-2-6       14               0.58                     0.22
G-2-5       14               0.59                     0.26
G-2-4        6               0.59                     0.23
G-2-3        6               0.58                     0.25
G-2-2       25               0.60                     0.26
G-2-1       22               0.59                     0.24
G-1         14               0.59                     0.18

Sample    20S/(20S + 20R)     [C.sub.27]   [C.sub.28]    [C.sub.29]
         [C.sub.29] sterane   sterane,%     sterane,%    sterane,%

Y-5             0.45              19           33            48
Y-4-8           0.45              17           34            49
Y-4-7           0.43              18           33            49
Y-4-6           0.46              19           34            47
Y-4-5           0.46              24           33            43
Y-4-4           0.44              23           31            46
Y-4-3           0.42              28           29            43
Y-4-2           0.47              25           29            46
Y-4-1           0.46              28           26            46
S-2-7           0.48              23           27            50
S-2-6           0.33              21           34            45
S-2-5           0.35              22           36            42
S-2-4           0.35              20           32            48
S-2-3           0.39              19           28            53
S-2-2           0.32              30           22            48
S-2-1           0.34              17           35            48
S-1             0.38              16           33            51
G-2-23          0.27              16           34            50
G-2-22          0.27              22           31            47
G-2-21          0.31              24           31            45
G-2-20          0.36              25           26            49
G-2-19          0.35              20           29            51
G-2-18          0.36              20           37            43
G-2-17          0.35              21           33            45
G-2-16          0.33              20           37            43
G-2-15          0.33              19           36            45
G-2-14          0.35              18           38            44
G-2-13          0.37              25           30            45
G-2-12          0.36              15           28            57
G-2-11          0.39              22           34            44
G-2-10          0.34              16           32            52
G-2-9           0.39              27           29            44
G-2-8           0.39              17           37            46
G-2-7           0.36              24           33            44
G-2-6           0.38              31           37            32
G-2-5           0.41              20           36            45
G-2-4           0.39              16           46            39
G-2-3           0.41              19           45            36
G-2-2           0.43              25           31            44
G-2-1           0.38              13           31            56
G-1             0.34              10           38            52

(a) Gamma index = [Gammacerane/[C.sub.30]17[alpha](H), 21[beta]
(H)-hopane]*100. OEP--odd-to-even preference ratio of n-alkanes.
Abbreviations: YMS--Yamalikeshan, SMG--Shuimogou, SGH--Sangonghe.
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Author:Gao, Yuan; Wang, Yongli; Peng, Ping'an; He, Daxiang; Wang, Gen; Wang, Zixiang; Meng, Pei; Sun, Zepen
Publication:Oil Shale
Article Type:Report
Geographic Code:9CHIN
Date:Dec 1, 2016
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