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Geochemical investigation of lacustrine oil shale in the lunpola basin (Tibet): implications for paleoenvironment and paleoclimate.

1. Introduction

Oil shale deposits are widespread in China, and proved reserves amount to about 32 billion tons, representing a potential energy source [1]. Tertiary oil shales, such as Fushun and Maoming ones, were mainly formed in lacustrine environments [1-3].

Research about oil shale in Tibet has made some breakthrough in recent years and some articles about marine oil shale have been published [4-7]. However, lacustrine oil shale in the Lunpola basin has received less attention, although oil shale in this basin was first mentioned by Xu already in 1984 [8].

In this paper, geochemical investigations of the Lunpola basin lacustrine oil shale are described systematically. The primary aim is to interpret the paleoenvironment and paleoclimate during oil shale deposition. The results also provide geologists worldwide information about the geochemistry of oil shale in the Tertiary continental sedimentary basin in Tibet.

2. Geological setting

The Lunpola basin is a primarily Tertiary sedimentary basin situated in the central part of the Tibetan plateau (Fig. 1). The basin axis strikes mainly east-west and has been variably deformed along basin-parallel thrust faults and associated folds. Erosion through these structures has exposed much of the succession at the surface. The Lunpola basin contains a thick stratigraphic succession that extends from the Palaeocene to the Pliocene [9]. The basin has been explored geophysically and through a series of wells that has established the stratigraphic context and correlation of sediments within the basin [10].

The basin base consists of Mesozoic strata, which are composed of marine carbonate, clastic rocks, mafic lava and volcaniclastic units [11-12]. The Cenozoic strata of the Lunpola basin are more than 4000 m thick, and consist of two primary stratigraphic units: the Niubao Formation and the overlying Dingqinghu Formation. The age of these formations was determined to be the Paleocene-Oligocene and Miocene-Pliocene, respectively [13-15], based primarily on fossil ostracod and palynological assemblages. More recent investigation indicated that the Niubao and Dingqinghu formations are Paleocene-Eocene and Oligocene, respectively [16-17]. The Dingqinghu Formation discussed herein mainly consists of dark mudstone, marlstone, oil shale, siltstone and shale, and contains ostracods and green algae identified in exploration wells [12].

3. Samples and tests

The study profiles (LP01 and LP02) are located in the central part of the Lunpola basin (Fig. 1B). A total of 26 samples were collected from the two profiles. All samples were collected for geochemical analyses. Details of sampling locations and rock assemblages are shown in Figure 2.

Total organic matter (TOC) was determined on a LECO CS-200 apparatus (BGR, Germany). About 100 mg of sample (ground to 120 mesh) was heated from ambient temperature up to 1200 [degrees]C in an induction furnace after removing carbonate with hydrochloric acid (HCl). Standard deviations are less than 0.5%. Pyrolysis data were collected using a Rock-Eval II apparatus (Petrobas Research Centre, France). A 100 mg crushed sample (120 mesh) was analyzed following guidelines established by Peters [18].

The powdered samples to be analyzed were extracted with chloroform for 72 h in a Soxhlet apparatus. The extractable organic matter was separated by column chromatography into saturated hydrocarbons, aromatic hydrocarbons and NSO compounds by using a silica gel alumina column, after precipitation of asphaltenes [19]. Gas chromatography (GC) was carried out with an Agilent 6890 N gas chromatograph (Agilent Technologies, Inc., USA) equipped with a 30 m x 0.20 [mu]m ID x 0.2 film silica column. The oven temperature was programmed from 70 to 300 [degrees]C at a rate of 8 [degrees]C/min and held at 300 [degrees]C for 20 min. Injection was performed in the split/splitless mode with a splitless time of 60 s. Helium was used as a carrier gas (injection temperature 310 [degrees]C). GC/MS analysis was carried out using a TRACE2000/SSQ-7000 mass spectrometer (Triplemass, Netherlands). A 30 m x 0.20 mm ID x 0.2 film Varina CP Sil-8CB fused silica column was used. Helium was used as carrier gas. The temperature was programmed from 80 to 160 [degrees]C at a rate of 8 [degrees]C/min and from 160 to 310 [degrees]C at a rate of 2.8 [degrees]C/min, with a 5 min isothermal period at 310 [degrees]C.

To prepare kerogens, fragments of rock were leached in 12 N HCl for 12 h to remove carbonates, then washed several times with distilled water and treated with hydrofluoric acid (HF) for 12 h to remove silicates [20]. The samples were again washed several times with distilled water and again treated with 12 N HCl [20]. A visual estimation of the relative abundance of maceral content was made using a Zeiss incident-light microscope and a Swift point counter (Canimpex Enterprises Ltd., Canada) [19]. Elemental analyses were performed on a FLASH EA-1112 Series elemental analyzer (Conquer Scientific, USA) with a precision generally around 0.3% for carbon and 0.5% for nitrogen. The [[delta].sup.13]C kerogen isotopic measurements were determined on an EA-Finnigan Delta plus XL mass spectrometer. The results of carbon isotope analysis are reported in the usual 5-notation relative to the PDB standard; the analytical precision by this method was better than [+ or -]0.2 [per thousand] [5]. All analyses were performed in the Organic Geochemistry Laboratory, Research Institute of Exploration and Development, Huabei Oilfield Branch Company of PetroChina.

4. Results and discussion 4.1. TOC and Rock-Eval

Rock-Eval and TOC data are summarized in Table 1. The TOC contents of six oil shale samples from the LP01 profile vary from 2.84 to 6.92%, whereas mudstone samples contain 0.25 to 5.99% TOC (Table 1). The [S.sub.2] values of oil shale samples are in the range of 12.75-57.38 mg HC/g rock, compared to 0.90-50.45 mg HC/g rock for mudstone samples (Table 1). The HI of oil shale samples from the LP01 profile varies between 449 and 841 mg HC/g TOC. The high [S.sub.2] and HI values clearly indicate that the oil shale from the LP01 profile has a good source-rock potential. All analyzed samples from the LP01 profile are characterized by relatively low PI (0.01-0.46) and [T.sub.max] values (427-438) (Table 1) indicating that the organic matter is thermally immature to early mature.

The twelve oil shale samples from the LP02 profile have TOC contents varying between 1.46 and 11.85%, whereas three marlstone samples contain 0.28 to 1.04% TOC (Table 1). The high [S.sub.2] values of 4.79-115.80 mg HC/mg rock and HI values of 328-1040 HC/g TOC (Table 1) indicate that oil shale from the LP02 profile has a good source-rock potential, whereas the source-rock potential of marlstone is relatively low. [T.sub.max] values for all the samples mostly fall within the range of 430-440 [degrees]C indicating that the samples are thermally immature to early mature.

4.2. Element and stable carbon isotopic composition of kerogen

The elemental analysis data are listed in Table 2. The H/C ratio of oil shale from the LP01 profile varies between 1.44 and 1.63 and that of O/C between 0.13 and 0.14 (Table 2). The H/C and O/C ratios of twelve oil shale samples from the LP02 profile range from 1.36 to 1.63 and 0.12 to 0.14, respectively. Based on these ratios (Fig. 3), the organic matter in oil shale samples from LP01 and LP02 profiles can be classified as Type I kerogen (except for samples LP02-2 and LP02-6) (Fig. 3) and marlstone as Type II. Type I kerogen mainly originated from planktonic green algae or amorphous organic matter [21]. The high HI values (> 700 mg HC/g TOC) in most oil shale samples support the algal or bacterial contribution to the organic matter [22].

The oil shale from LP01 and LP02 profiles have a similar heavy C isotopic composition, ranging in [[delta].sup.13] values of the bulk organic matter from -29.6 to -26.7 [per thousand] and -29.9 to -27.3 [per thousand], respectively (Table 2). The oil shale shows no enrichment in [13.sup]C, which is different from the Tertiary lacustrine Duatinga oil shale in Australia [23]. Regional organic facies variations caused by bioassemblage input or significant climatic fluctuation [22], or water column productivity variation [5, 24] may result in differences in stable carbon isotope compositions. Enrichment in [13.sup.C] seems to be a common feature in hypersaline systems. Hypersalinity itself has been suggested to be the cause for these heavy isotope values in microbial mats [25]. As discussed below, the Lunpola basin oil shale, mudstone and marlstone were deposited in hypersaline environments, and the organic matter derived from these rocks should exhibit similar enrichment and consistent isotopic trends. Therefore, organic facies variations may be the main reason for lower [[delta].sup.13][C.sub.org] values (-29.9 to -26.7%) of oil shale. Lewan [26] proposed that the phytoplankton residing in environments that are dominated by organic-derived [CO.sub.2] results in amorphous kerogens, which are expected to occur in restricted basins that are overlain by stratified shallow (<200 m) water. The Lunpola palaeo-lake was a stratified and shallow water lake. Therefore, it is suggested that lacustrine algae are considered to be the precursors of amorphous kerogens and the isotopically low carbon isotopic values are attributed to lacustrine algae.

4.3. Molecular composition of organic matter

4.3.1. n- and iso-alkanes

Gas chromatograms of the saturated hydrocarbons isolated from LP01 and LP02 oil shale samples are presented in Figure 4 and their parameters are given in Table 3. The analyzed samples contain abundant [C.sub.15+] n-alkanes indicating a slight biodegradation at the most [27] (Fig. 4). The n-alkanes patterns of oil shale from both profiles are dominated by long-chain n-alkanes with a marked odd-over-even preference in the n[C.sub.23] to n[C.sub.31] range (most samples having the carbon preference index CPI > 3) with the exception of the sample LP01-6. Long-chain n-alkanes (n-[C.sub.27] to n-[C.sub.31)] are known as biomarkers for higher terrestrial plants waxes [28-29]. The dominance of long-chain n-alkanes for the samples LP01-1, LP02-3, LP02-12 and LP02-13 therefore reflects the contribution of terrestrial plants.

The oil shale samples from LP01 and LP02 profiles exhibit low values of the pristane/phytane (Pr/Ph) ratio ranging from 0.03 to 0.43 (Table 3). The Pr/Ph ratio has been used in many studies to infer the oxic/anoxic character of depositional environments and sources of organic matter. High Pr/Ph ratios are usually associated with organic matter that has undergone oxidation to the extent that the phytol side chain of chlorophyll or related structures has been oxidized, a pathway that leads preferentially to the formation of pristane [30]. However, several factors, such as thermal maturity [31] and variable source input [32], must be taken into account when Pr/Ph ratios are considered. Ten Haven et al. [33] proposed that it is virtually impossible to draw valid conclusions from Pr/Ph ratio with respect to the redox conditions of the environment of deposition. However, Peters et al. [32] still recommended that Pr/Ph <0.6 indicates anoxic, commonly hypersaline or carbonate environments, whereas Pr/Ph >3.0 typifies terrigenous organic matter input under oxic conditions for rocks within the oil generative window. Maturity variations within the studied samples can be excluded. The low Pr/Ph ratio indicates that these rocks were deposited in anoxic and probably hypersaline conditions, which is supported by the abundant pyrite crystals found in the Lunpola oil shale [34]. Syngenetic pyrite in coal and oil shale indicates an anoxic sedimentary environment [6, 35].

Peters et al. [32] suggested that [beta]-carotane is the most prominent compound of the carotenoid carbon skeleton preserved in sediments under highly reducing conditions. The presence of [beta]-carotane is associated primarily with anoxic, saline lacustrine, or highly restricted marine settings [32, 36]. [beta]-carotane occurs in several oil shale samples from the Lunpola basin (Table 3), indicating an anoxic and saline lacustrine environment. This compound is also reported in Chinese Junggar Permian [37] and Jianghan oil shales [38].

4.3.2. Hopanes and steranes

The gammacerane index varies from 0.71 to 9.93 and 1.34 to 25.24 (Table 3) for LP01 and LP02 profile oil shale, respectively. Gammacerane is a biomarker of highly reducing, hypersaline conditions during deposition of the contributing organic matter [39-40]. Sinninghe Damste et al. [41] argued that gammacerane indicates a stratified water column in marine and nonmarine source rock depositional environments, commonly resulting from hypersalinity at depth. Clearly, because the water columns in hypersaline depositional environments are often density stratified, it may be the reason that the compound is abundant in saline lacustrine deposits [41]. The Lunpola basin oil shale was therefore probably deposited in a highly saline lacustrine environment, which is also supported by the very low Pr/Ph values and the presence of [beta]-carotane. The discovery of gypsum of the Dingqinghu Formation in the Nima basin (west of the Lunpola basin) [17] also supports this interpretation. It is possible that the salinity in the water column remained the same and water-column stratification is constant during most of the time when the Lunpola oil shale deposited, which is supported by the high TOC and HI values of Lunpola basin oil shale samples [21].

Oil shale samples from the LP01 profile show slightly higher [C.sub.29] (37-76%) normal sterane contents compared to those of [C.sub.27] (12-41%) and [C.sub.28] (12-23%) normal steranes (Table 3). A similar distribution of steranes was also observed in the LP02 profile (Table 3), reflecting a contribution of higher terrestrial plants [42]. In contrast, mudstones (e.g., LP01-7) exhibit a different distribution; their [C.sub.29] steranes exhibit a relatively low abundance ranging from 16 to 34%. Huang and Meinschein [43] proposed that the predominance of [C.sub.29] sterols (steranes) should indicate a strong contribution from the organic matter of higher plants, whereas the prevalence of [C.sub.27] sterols (steranes) should imply the dominance of marine plankton. Based on this interpretation, the relative amount of steranes was used to infer biological sources of organic matter in oils [44]. However, we should be careful when interpreting [C.sub.29] sterane predominances. Volkman [45] found that marine sediments, including those deposited in pelagic environments far from terrigenous influence, showed the predominance of [C.sub.29] steranes, and concluded that there must be unproven marine sources of [C.sub.29] steranes. In addition, as illustrated in Figure 4, steranes of the LP01-4 oil shale exhibit a V-shaped pattern, namely [C.sub.27]>[C.sub.28]<[C.sub.29], revealing mixed contributions from algae or bacterial and higher plant wax sources [42].

5. Paleoenvironmental and paleoclimatic significances

It is well known that distribution of lakes, lake productivity and preservation of organic matter are controlled by climatic and tectonic factors. Palaeoclimate and palaeogeography not only play major roles in controlling distribution of lake bodies but also influence water chemistry. It is clear that saline lakes develop when evaporation exceeds precipitation and fresh-water lakes develop when precipitation exceeds evaporation. As discussed above, the Lunpola basin oil shale was deposited in a highly saline lacustrine environment, which indicates arid climate. Other evidence supports this interpretation. Regional uplift in central Tibet at about 40 Ma contributed to an abrupt global cooling and dramatic aridification [46-49]. Climate in the Tibetan plateau became dry after the Eocene/Oligocene transition. DeCelles et al. [17] suggested that considerable lake evaporation and low soil respiration rates existed in the Oligocene of the Nima basin based on the oxygen isotope values in palaeo-lacustrine carbonates and carbon isotope values in palaeosol carbonates, which is indicative of an arid climate. All data probably support a conclusion that the saline palaeo-lakes were widely developed in the central Tibetan plateau in the Oligocene and the climate was arid. Therefore, the climate of the Lunpola basin region during the deposition of oil shale was arid.

6. Conclusions

Twenty-six samples of lacustrine oil shale, mudstone and marlstone from LP01 and LP02 profiles in the Lunpola basin have been studied with regard to their organic geochemical characteristics. The TOC contents and [S.sub.2] values of oil shale samples from LP01 and LP02 profiles in the Lunpola basin are high, indicating that this oil shale has a good source-rock potential. The thermal maturity assessed from PI and [T.sub.max] shows an immature to early mature stage of the organic matter. The Lunpola basin oil shale exhibits characteristics of odd-over-even predominance, maximum n-alkanes peak at [nC.sub.25] or [nC.sub.23], a higher proportion of [C.sub.29] sterane, low [[delta].sup.13][C.sub.org] values, a low Pr/Ph ratio, high values of the gammacerane index, and presence of [beta]-carotane, which is consistent with a reducing, stratified and hypersaline palaeo-lake with the main contribution of algae and bacteria to the organic matter. A highly saline lacustrine environment and regional uplift in central Tibet at about 40 Ma suggest that the climate of the Lunpola basin region during the deposition of oil shale was probably cool and arid.

doi: 10.3176/oil.2013.2.02

Acknowledgements

The research project was financially supported by the Fundamental Research Funds for the Central Universities (No. 2011PY0238), the National Natural Science Foundation of China (No. 40672086), and the National Petroleum Resources Special Project: Strategic Investigation and Geological Survey on Oil and Gas Resources in Tibet Plateau (No. 1212011221103). The authors are grateful to Dr. Shunping Ma for analytical work.

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Presented by J. Boak

Received August 2, 2012

TAO SUN (a)(b), CHENGSHAN WANG (a)(b)*, YALIN LI (a)(b), LICHENG WANG (c), JIANGLIN HE (d)

(a) School of Earth Science and Resources, China University of Geosciences, Beijing 100083, China

(b) State Key Laboratory of Geological Process and Mineral Resources, China University of Geosciences, Beijing 100083, China

(c) Institute of Mineral Resources, Chinese Academy of Geological Sciences, Beijing 100083, China

(d) Chengdu Institute of Geology and Mineral Resources, Chengdu 610000, China

* Corresponding author: e-mail chshwang@cugb.edu.cn

Table 1. Results of Rock-Eval and TOC analysis and
calculated parameters

Sample    Lithology   TOC (a),   [S.sub.1] (b),   [S.sub.2] (d),
No.                   wt%        mg HC (c)/g      mg HC (c)/g

LP01-1    Shale          2.84             0.51            12.75
LP01-2    Shale          6.56             1.17            51.99
LP01-3    Shale          6.92             0.83            57.38
LP01-4    Shale          3.89             0.59            30.55
LP01-5    Shale          5.12             1.09            39.84
LP01-6    Shale          4.82             0.80            40.54
LP01-7    Mudstone       3.29             0.99            29.86
LP01-8    Mudstone       5.95             2.52            50.45
LP01-9    Mudstone       0.25             0.76             0.90
LP01-10   Mudstone       5.99             2.62            54.16
LP01-11   Mudstone       0.87             1.02             6.21
LP02-1    Marl           1.04             0.08             1.75
LP02-2    Shale          1.46             0.04             4.79
LP02-3    Marl           0.31             0.03             0.40
LP02-4    Marl           0.28             0.02             0.32
LP02-5    Shale          4.75             0.13            34.47
LP02-6    Shale          2.39             0.34            14.70
LP02-7    Shale          4.29             0.42            33.06
LP02-8    Shale          6.25             5.12            49.77
LP02-9    Shale         10.15             1.06           105.51
LP02-10   Shale          7.65             0.69            66.02
LP02-11   Shale         11.85             2.34           115.80
LP02-12   Shale          7.95             0.73            78.33
LP02-13   Shale         13.05             4.97            96.95
LP02-14   Shale          6.24             0.54            53.97
LP02-15   Shale         11.95             3.59            97.80

Sample    PY (e)         [T.sub.max]     HI (g),    PI (h)
No.       ([S.sub.1] +   (f),            HC/g TOC   ([S.sub.1]/
          [S.sub.2]),    [degrees]C                 ([S.sub.1]+
          mg HC/g                                   ([S.sub.2])

LP01-1          13.26             438        449          0.04
LP01-2          53.16             433        793          0.02
LP01-3          58.21             434        829          0.01
LP01-4          31.14             436        785          0.02
LP01-5          40.93             432        778          0.03
LP01-6          41.34             429        841          0.02
LP01-7          30.85             438        908          0.03
LP01-8          52.97             433        848          0.05
LP01-9           1.66             431        360          0.46
LP01-10         56.78             432        904          0.05
LP01-11          7.23             427        714          0.14
LP02-1           1.83             433        168          0.04
LP02-2           4.83             442        328          0.01
LP02-3           0.43             419        129          0.07
LP02-4           0.34             423        114          0.06
LP02-5           34.6             436        726          0.00
LP02-6          15.04             431        615          0.02
LP02-7          33.48             435        771          0.01
LP02-8          54.89             413        796          0.09
LP02-9         106.57             440       1040          0.01
LP02-10         66.71             432        863          0.01
LP02-11        118.14             436        977          0.02
LP02-12         79.06             438        985          0.01
LP02-13        101.92             439        743          0.05
LP02-14         54.51             435        865          0.01
LP02-15        101.39             440        818          0.04

(a) TOC = total organic carbon.

(b) S1 = free hydrocarbons.

(c) HC = hydrocarbon.

(d) [S.sub.2] = pyrolysable hydrocarbons.

(e) PY = potential yield.

(f) [T.sub.max] = temperature of maximum S2.

(g) HI = hydrogen index.

(h) PI = production index.

Table 2. Results of analysis of organic elements and carbon
isotopes of samples from LP01 and LP02 profiles in the Lunpola
basin

Sample    Lithology   C,      H,     O,      H/C
No.                   wt%     wt%    wt%     ratio

LP01-1    Shale       68.94   8.59   12.56   1.49
LP01-2    Shale       66.74   8.21   12.76   1.48
LP01-3    Shale       68.26   9.26   11.36   1.63
LP01-4    Shale       66.51   8.85   11.25   1.60
LP01-5    Shale       67.56   8.74   11.89   1.55
LP01-6    Shale       68.58   8.22   11.60   1.44
LP01-7    Mudstone    68.11   8.01   11.39   1.41
LP01-8    Mudstone    69.45   8.42   10.73   1.46
LP01-9    Mudstone    69.66   8.43   11.31   1.45
LP01-11   Mudstone    60.50   6.94   9.87    1.38
LP02-1    Marl        75.20   8.46   15.04   1.35
LP02-2    Shale       72.09   8.23   12.50   1.37
LP02-3    Marl        81.51   8.83   16.30   1.30
LP02-4    Marl        87.20   8.72   17.44   1.20
LP02-5    Shale       68.38   9.06   10.94   1.59
LP02-6    Shale       74.65   8.46   13.93   1.36
LP02-7    Shale       69.76   8.72   10.23   1.50
LP02-8    Shale       69.87   8.85   11.18   1.52
LP02-9    Shale       67.14   9.12   10.74   1.63
LP02-10   Shale       67.28   8.69   11.66   1.55
LP02-11   Shale       67.00   8.71   10.72   1.56
LP02-12   Shale       65.81   8.61   10.53   1.57
LP02-13   Shale       64.05   8.38   10.25   1.57
LP02-14   Shale       68.18   9.09   10.91   1.60
LP02-15   Shale       66.15   8.82   10.58   1.60

Sample    O/C       [[delta].sup.13]
No.       ratio     [C.sub.PDB]/ [per thousand]

LP01-1    0.14           -26.7
LP01-2    0.14           -29.6
LP01-3    0.12           -28.5
LP01-4    0.13           -28.6
LP01-5    0.13           -28.8
LP01-6    0.13           -27.2
LP01-7    0.13           -27.6
LP01-8    0.12           -27.9
LP01-9    0.12           -25.7
LP01-11   0.12           -28.2
LP02-1    0.15           -27.9
LP02-2    0.13           -29.7
LP02-3    0.15           -27.8
LP02-4    0.15           -26.3
LP02-5    0.12           -29.9
LP02-6    0.14           -28.8
LP02-7    0.11           -27.5
LP02-8    0.12           -27.3
LP02-9    0.12           -28.5
LP02-10   0.13           -29.7
LP02-11   0.12           -28.3
LP02-12   0.12           -27.9
LP02-13   0.12           -27.9
LP02-14   0.12           -29.1
LP02-15   0.12           -28.9

Table 3. Organic geochemical data for extracts of samples from
LP01 and LP02 profiles in the Lunpola basin

Sample No.   Pr/n         Ph/n         Pr/[Ph   CPI    %[C.sub.27]
             [C.sub.17]   [C.sub.18]     (a)             (b)

LP01-1            1.25        10.38     0.18    2.36       29
LP01-2            0.88        19.15     0.10    4.01       40
LP01-3            0.95         5.98     0.28    5.42       41
LP01-4            1.27         4.98     0.40    8.24       40
LP01-5            1.74        17.08     0.15    4.31       12
LP01-6            1.01         4.59     0.43    2.19       54
LP01-7            1.39         5.83     0.35    1.83       57
LP01-8            1.11         6.37     0.34    2.29       51
LP01-9            1.18         7.90     0.26    1.84       51
LP01-10           0.92         2.44     0.42    1.95       47
LP01-11           2.30         9.77     0.30    1.48       53
LP02-1            0.83        26.94     0.07    3.54       34
LP02-2            0.91        12.31     0.14    4.79       40
LP02-3            1.56        15.54     0.12    2.82       26
LP02-4            1.27         7.52     0.19    3.76       28
LP02-5            1.08        59.91     0.05    3.94       35
LP02-6            1.26        33.45     0.06    4.61       51
LP02-7            1.41        52.94     0.05    4.64       39
LP02-8            1.52        85.17     0.03    8.59       40
LP02-9            1.11        42.80     0.06    2.59       44
LP02-10           1.27        90.20     0.04    5.10       31
LP02-11           0.92        58.20     0.04    7.31       30
LP02-12           1.39        37.00     0.06    3.10       14
LP02-13           2.18        59.72     0.06    3.79       11
LP02-14           1.20        15.61     0.13    4.72       48
LP02-15           1.09        19.80     0.08    5.03       42

Sample No.   %[C.sub.28]   %[C.sub.29]   Gammacer    [beta]-
               (c)           (d)         ane index   carotane
                                           (e)

LP01-1           15            56            2.19      n.d.
LP01-2           23            37            1.04      n.d.
LP01-3           17            42            0.71    present
LP01-4           16            44            2.62      n.d.
LP01-5           12            76            3.96      n.d.
LP01-6           30            16            4.63      n.d.
LP01-7           25            18            5.09    present
LP01-8           28            21            5.55      n.d.
LP01-9           25            24            7.01      n.d.
LP01-10          19            34            2.94      n.d.
LP01-11          19            28            9.93      n.d.
LP02-1           15            51           11.71      n.d.
LP02-2           16            44            8.39      n.d.
LP02-3           12            62            8.11    present
LP02-4           14            58            5.73    present
LP02-5           14            51           25.24    present
LP02-6           21            28           17.37      n.d.
LP02-7           16            45           15.34      n.d.
LP02-8           20            40            3.06      n.d.
LP02-9           17            39           11.26      n.d.
LP02-10          20            49           10.51      n.d.
LP02-11          20            51            5.03      n.d.
LP02-12          19            67           13.85      n.d.
LP02-13          14            75            1.99      n.d.
LP02-14          21            31            3.89      n.d.
LP02-15          17            41            1.34      n.d.

n.d. not detected

(a) Pr/Ph = pristine/phytane ratio.

(b) %[C.sub.27] = % [C.sub.27] [alpha][alpha][alpha] R/
[C.sub.27]-[C.sub.29] [alpha][alpha][alpha]R-steranes.

(c) %[C.sub.28] = % [C.sub.28] [alpha][alpha][alpha] R/
[C.sub.27]-[C.sub.29] [alpha][alpha][alpha]R-steranes.

(b) %[C.sub.29] = % [C.sub.29] [alpha][alpha][alpha] R/
[C.sub.27]-[C.sub.29] [alpha][alpha][alpha]R-steranes.

(e) Gammacerane index = Gammacerane/([C.sub.31](22S+22R)/2)
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Author:Sun, Tao; Wang, Chengshan; Li, Yalin; Wang, Licheng; He, Jianglin
Publication:Oil Shale
Article Type:Report
Geographic Code:9CHIN
Date:Jun 1, 2013
Words:6005
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