A rapid increase in consumption of energy and chemicals leads to a
dramatic increase in the prices of conventional fossil resources  and
stimulates the search for alternative energy. Oil shale, as an
alternative energy source, has received much attention [2-4]. In China,
oil shale deposits are widespread in many regions and were formed mainly
in lacustrine environments, just like Tertiary oil shale in the Maoming,
Huadian and Fushun areas , and Cretaceous oil shale in the Songliao
and Minhe basins . Marine oil shale was mainly found in the Qiangtang
basin, northern Tibet, China, including the Bilong Co oil shale zone
[6-8] and the Shengli River-Changshe Mountain oil shale zone [9-12].
These zones represent a large marine oil shale resource in China.
The Bilong Co oil shale is located in the southern part of the
Qiangtang basin (Fig. 1a). Proved reserves are about 90.6 million tonnes
. The early studies of the oil shale were focused on the geochemistry
of rare earth and trace elements [7-8] and anoxic event [13-14].
However, the data regarding the organic geochemistry of the oil shale
from the Bilong Co area are still scarce and incomplete.
In the present study, we have investigated the organic geochemical
characteristics of oil shale samples collected from the Bilong Co oil
shale area. The primary aim was to reconstruct paleoenvironment during
deposition and assess petroleum prospects.
From north to south, the Tibetan plateau is comprised of the
Kunlun-Qaidam, Songpan-Ganzi flysch complex, Qiangtang, and Lhasa
terranes, which are separated by the east-west trending
Anyimaqen-Kunlun-Muztagh, Hoh Xil-Jinsha River and Bangong Lake-Nujiang
River suture zones, respectively  (Fig. 1a). It is generally accepted
that the paleo-Tethys represented by the present Jinsha River suture
opened probably in the Early Carboniferous  and closed by the
Permian to the latest Triassic . The mid-Tethys branch between the
Lhasa and Qiangtang terranes was open by the Early Jurassic  and
closed along the Bangong Lake-Nujiang River suture during the Late
Jurassic time .
The Qiangtang block, bounded by the Hoh Xil-Jinsha River suture
zone to the north and the Bangong Lake-Nujiang River suture zone to the
south, respectively, consists of the North Qiangtang depression, the
South Qiangtang depression and the central uplift (Fig. 1b). The Bilong
Co area is located in the South Qiangtang depression (Fig. 1b), where
Jurassic marine deposits are widely spread including Lower Jurassic Quse
Formation, Middle Jurassic Sewa Formation, Buqu Formation and Xiali
Formation, and Upper Jurassic Suowa Formation (Fig. 1c). The Bilong Co
oil shale zone is exposed for a distance of more than 4 km in an
east-west trend. Abundant ammonites (Harpoceras sp.), occurring at the
top of the Bilong Co oil shale section , indicate that the Bilong Co
oil shale is of Early Jurassic age (i.e. Quse Formation strata).
[FIGURE 1 OMITTED]
Samples and analytical methods
The investigated section is located in the Bilong Co area, South
Qiangtang depression (Fig. 1b). A total of 18 samples were collected
from the section. Thirteen of them were collected from oil shale seams
with a vertical sampling interval of 1 m on average, and the other five
samples were collected from micritic limestone layers. The present-day
burial depth of the samples is about 50 cm.
The samples for geochemical analysis and Rock-Eval pyrolysis were
all crushed and ground to 120 mesh. Total organic carbon (TOC) and
RockEval pyrolysis were determined using a TOC module-equipped Rock-Eval
II type instrument. About 100 mg of sample was heated from ambient
temperature up to 600[degrees]C in a helium atmosphere . These
analyses were performed at the Geological Laboratory of Exploration and
Development Research Institute of PetroChina Southwest Oil and Gasfield
Analyzed samples were extracted with chloroform in a Soxhlet
apparatus for 72 h. Extracts were separated into saturated hydrocarbons,
aromatic hydrocarbons and polar NSO fractions by column chromatography
using a silica gel-alumina column after the precipitation of asphaltenes
. Saturated fractions were analyzed by gas chromatography (GC) and
gas chromatography-mass spectrometry (GC-MS). An aliquot of each
saturated fraction was separated into n-alkanes and branched/cyclic
alkanes by urea adduction.
The GC-MS analysis was performed using a Finnigan Voyager gas
chromatography/mass spectrometer. This instrument was equipped with a
DB5-MS fused silica capillary column of 30-m length, 0.25-[micro]m film
thickness and 0.32-mm inner diameter. Helium was used as the carrier
gas. For routine GC analysis, the oven was isothermally held for 1 min
at 35[degrees]C, programmed from 35 to 120[degrees]C at
10[degrees]C/min, then from 120 to 300[degrees]C at 3[degrees]C/min,
with a final holding time of 30 min . The MS was operated with an
ionization energy of 70 eV and a source temperature of 200[degrees]C
. For the analysis of biomarkers, metastable ion transition for
sterans (m/z 217) and triterpanes (m/z 191) was recorded at a dwell time
of 25 ms per ion and a cycle time of 1 s. In order to identify the
possible organic contaminations during the experimental processes, we
added a blank sample for reference and no organic contamination
discussed in this study was observed.
Results and discussion
Total organic carbon (TOC)
The TOC content of oil shale and micritic limestone samples from
the Bilong Co area can be found in Table 1. The measurements exhibit
that sediments in the study area as a whole are rich in organic matter
with an average TOC of 7.38 wt.%. The TOC values of oil shale samples
vary from 6.75-19.2 wt.% with an average of 9.70 wt.%, whilst the
micritic limestone samples have relatively low TOC values ranging from
0.36-2.10 wt.% with an average of 1.35 wt.%.
[S.sub.2] values of the studied samples vary from 0.3-70.2 mg HC/g
rock (Table 1). [S.sub.2] values of 5.96-70.2 mg HC/g rock (Table 1)
clearly indicate that oil shale samples from the Bilong Co area possess
shale oil producing potential.
HI values of oil shale samples varying from 202.03-365.63 mg HC/g
TOC indicate that the potential of these sediments is to produce the
mixture of oil and gas, which is in agreement with the kerogen-type
index ([S.sub.2]/[S.sub.3] ratios) (Table 1). According to the HI vs. OI
diagram  (Fig. 2), analyzed samples can be classified as mostly type
II kerogen. The [T.sub.max] values of most samples, between 435 and
443[degrees]C (Table 1), indicate that the organic matter is thermally
[FIGURE 2 OMITTED]
Molecular composition of the organic matter
Normal alkanes and isoprenoid hydrocarbons
Partial gas chromatograms of the saturated hydrocarbons extracted
from the sediments of Bilong Co samples are shown in Fig. 3 and their
parameters are listed in Table 2. The normal alkanes (n-alkanes) are
represented by [C.sub.14-35] homologues and the distributions through
the sections are very similar. The GC traces of all samples studied
demonstrate a unimodal distribution typically dominated by components of
lower molecular weight (the [C.sub.21.sup-]/[C.sub.21.sup.+] ratios of
most samples are from 1.06 to 1.95, Table 2), with a distribution
maximum among the lighter hydrocarbons ([C.sub.17]-[C.sub.19]) and
without a distinct odd or even predominance (the OEP values ranging from
0.88-1.07, Table 2), except the sample BP-9. The n-alkane distribution
of the sample BP-9 is dominated by mid-chain n-alkanes with a marked
even over odd predominance in the [C.sub.22]-[C.sub.28] region and
without a clearly unimodal or bimodal distribution (Fig. 3).
The isoprenoid hydrocarbons pristane (Pr) and phytane (Ph) are
identified in all of the samples taken from the Bilong Co area. The
analyzed samples exhibit lower values of Pr/Ph ratios, varying from 0.13
to 0.88. Most of oil shale samples have the Pr/Ph ratios <0.6 (Table
2). The Pr/n-[C.sub.17] and Ph/n-[C.sub.18] ratios are listed in Table
2, and a plot of Pr/n-[C.sub.17] vs. Ph/n-[C.sub.18]  is shown in
[FIGURE 3 OMITTED]
[FIGURE 4 OMITTED]
The distributions and relative abundances of tricyclic, tetracyclic
and pentacyclic terpanes obtained from m/z 191 ion chromatograms are
given in Fig. 3 and their parameters are summarized in Table 2.
Tricyclic terpanes exhibit low concentrations in all samples from the
Bilong Co area ranging from [C.sub.19] to [C.sub.29], and dominated by
low molecular weight compounds ([C.sub.20]-[C.sub.25]) with a maximum at
[C.sub.25]. The traces of m/z 191 ion chromatograms show dominant
pentacyclic triterpenoids in the [C.sub.29]-[C.sub.35] range maximizing
at [C.sub.30] hopane in all oil shale samples. Gammacerane was recorded
in low amounts for all samples, with a gammacerane index
(gammacerane/[C.sub.30] hopane) varying from 0.07-3.11. The component
18[alpha](H)-trisnorneohopane (Ts) is dominant over its counterpart
17[alpha](H)-trisnorhopane (Tm), with a Ts/(Ts+Tm) ratio ranging from
0.53 to 0.67 in all samples analyzed. The [C.sub.31] hopane and higher
homologues occur as 22S and 22R epimers. The 22S/(22S+22R) ratios for
[C.sub.32] hopane in all samples studied vary from 0.55-0.61 with a mean
value of 0.58.
The m/z 217 mass chromatograms recorded the sterane distributions
of samples analyzed in Fig. 3, and the correlative parameters of
steranes are listed in Table 2. Some samples exhibit a slight
predominance of [C.sub.29] sterane (samples BP-7-1, BP-7-3, BP-10-1,
BP-10-2, BP-10-3, BP-10-4, BP-12-1, BP-12-2, BP-12-3, BP-13, BP-14-1,
BP-14-2, BP-14-3). As for the samples BP-6, BP-7-2, BP-9 and BP-11,
[C.sub.27] is observed as a dominant sterane. Steranes of the BP-8
micritic limestone show a V-shaped pattern (Fig. 3), namely
[C.sub.27]>[C.sub.28]<[C.sub.29], as well as
[C.sub.27]=[C.sub.29]. The steranes/hopanes (St/Hop) ratios show low
values for all samples varying from 0.16 to 0.38.
Type/source of organic matter
The distributions of n-alkanes can be used to indicate the source
of organic matter . Saturated hydrocarbons of most samples exhibit a
dominance of low molecular weight components with the highest peaks at
n-[C.sub.17], [C.sub.18], or [C.sub.19] (Fig. 3). The predominance of
lighter hydrocarbons in most oil shale samples (the
[C.sub.21.sup.-]/[C.sub.21.sup.+] ratios are from 0.82 to 1.95 with an
average of 1.39, Table 2) can be an indicator of algal organic matter
 or/and bacterial biomass input . In contrast, n-alkanes from
the micritic limestones show a different distribution. The
[C.sub.21.sup.-]/[C.sub.21.sup.+] ratios for the samples BP-6, BP-8,
BP-9, BP-11, and BP-13 are 1.15, 1.06, 0.29, 1.30, and 0.91,
respectively. The distribution of n-alkanes in the sample BP-9 shows a
dominance of mid-chain n-alkanes with a distinct even
(Fig. 3). Even over odd distribution in n-alkanes is usually considered
a common feature for organic matter deposited in saline environments
. Generally, these n-alkanes with an even over odd distribution can
directly originate from bacterial lipids  or be produced by a
secondary process involving thermal decomposition of lipid precursors
(e.g., n-fatty acids) . Considering the geochemical parameters for
the depositional environments (e.g., Pr/Ph ratios, Table 2) and
carbonate contents of strata, the n-alkane distribution patterns in our
case are believed to be independent of the redox conditions and the
mineral composition of strata, but to be associated with the composition
of original organic matter . Hence, a strong even predominance
within mid-chain-length n-alkanes in our study may be ascribed to a
contribution of halophilic bacteria or/and microorganisms from deep
saline environments to organic matter accumulation .
Pr/n-[C.sub.17] and Ph/n-[C.sub.18] ratios are usually associated
with source rock types, depositional environments and organic matter
maturity . A plot of Pr/n-[C.sub.17] vs. Ph/n-[C.sub.18] is shown in
Fig. 4. Clearly, most of samples from the Bilong Co area, whether oil
shale or micritic limestone samples, plot in the region designated for
algal kerogens, suggesting that these rock extracts contain considerable
amounts of algal organic matter.
The distribution of regular steranes has been applied to determine
the organic matter source of crude oils . Huang and Meinshein 
found that a predominance of [C.sub.29] sterols would reflect a
contribution of higher plants to organic matter accumulation, whereas a
dominance of [C.sub.27] homologues would be an indicator of marine
plankton. Based on their work, the relative abundances of steranes are
used to infer biological source of organic matter in oils . However,
this approach must be used with caution in interpreting [C.sub.29]
sterane predominances. Volkman  found that some marine sediments,
including those deposited in pelagic environments far from terrigenous
influence, showed a predominance of [C.sub.29] steranes, and thus
concluded that there must be unproven marine source of the [C.sub.29]
The relative abundances of [C.sub.27], [C.sub.28], and [C.sub.29]
regular steranes in oil shale samples are in the range of 34-42%,
16-24%, and 36-47%, respectively (Table 2). Although most oil shale
samples show slight higher [C.sub.29] regular sterane contents compared
to [C.sub.27] and [C.sub.28] regular steranes, obviously, their relative
amounts of [C.sub.27] regular steranes are close to [C.sub.29]
homologues. Combined with other biomarker parameters (e.g., n-alkane
distribution; Pr/n-[C.sub.17] vs. Ph/n-[C.sub.18] diagram), a slight
predominance of [C.sub.29] steranes in oil samples probably reflects a
strong contribution of inferior aquatic organisms (e.g., algae;
bacteria; microorganisms), and some influence of terrestrial organic
matter. In contrast, micritic limestone samples exhibit a different
distribution; their regular sterane content generally shows a
predominance of [C.sub.27] steranes, indicating a contribution of
aquatic algae or/and microbial activity. In addition, steranes of the
BP-8 micritic limestone show a V-shaped pattern (Fig. 3), namely
[C.sub.27]>[C.sub.28]<[C.sub.29] as well as [C.sub.27]=[C.sub.29],
also revealing mixed contributions from bacterial and higher plant wax
Thermal maturity of organic matter
Thermal maturity of organic matter in sediments is determined by
the creation process of hydrocarbons through undergoing a series of
physical or/and chemical changes by different agents such as heat,
pressure, burial and time after deposition. Maturity-related parameters
including [T.sub.max], Ts/(Ts+Tm) ratio, the 22S/(22S+22R) ratio for C32
homohopane and the 20S/(20S+20R) and
[beta][beta]/([alpha][alpha]+[beta][beta]) ratios for [C.sub.29] sterane
are used as the possible indicators for organic maturity in our work.
The [T.sub.max] values of most samples, between 435[degrees]C and
443[degrees]C (Table 1), indicate that the organic matter in sediments
is thermally mature. The Ts/(Ts+Tm) ratio increases from nearly 0 to
close to 1 with increasing maturity. The equilibrium value for
Ts/(Ts+Tm) ratio is measured to be 0.52-0.55 . Analyzed samples show
high Ts/(Ts+Tm) ratios with an average of 0.62 (i.e., in the range of
0.53-0.67 & 0.58-0.67 for the extracts of oil shale and micritic
limestone samples respectively, Table 2), indicating the mature
characteristics of oil shale and micritic limestone samples in the
Bilong Co area. The 22S/(22S+22R) extended hopane ratio increases with
increasing maturity and has been widely used as a maturity indicator
. The 22S/(22S+22R) homohopane ratios for C32 hopane varying from
0.55 to 0.61 with an average of 0.58 are close to equilibrium values
(0.57-0.62) indicating that the organic matter is thermally mature. The
20S/(20S+20R) together with [beta][beta]/([alpha][alpha]+[beta][beta])
isomerization ratios of the [C.sub.29] steranes are usually used as
indicators of maturity. In the Bilong Co area, analyzed samples exhibit
the 20S/(20S+20R) sterane ratios varying from 0.23 to 0.50, whereas, the
ratios of [beta][beta]/([alpha][alpha]+[beta][beta]) are in the range of
0.41 to 0.54. According to the [C.sub.29]St 20S/(20S+20R) vs.
[C.sub.29]St [beta][beta]/([alpha][alpha]+[beta][beta]) diagram (Fig. 5)
, most of samples are plotted in the mature area, indicating the
mature characteristics of the organic matter in sediments, thus
supporting other indicators for organic maturity as mentioned above.
[FIGURE 5 OMITTED]
Pr/Ph ratio, an indicator of redox potential of source sediments
proposed by Didyk et al. , has been widely utilized in many studies
to infer oxicity or anoxicity of depositional environments and source of
organic matter. High Pr/Ph ratios (>3) are usually associated with
suboxic to oxic depositional environments, however, low Pr/Ph ratios
(<0.6) indicate anoxic depositional conditions and usually
hypersaline envirnments . As seen in Table 2, analyzed samples show
low Pr/Ph ratios (<1) and the Pr/Ph values of most samples are
<0.6. The low values of Pr/Ph, combined with some pyrite crystals
found in oil shale samples , indicate that oil shale and micritic
limestone samples in the Bilong Co area were deposited in aquatic and
probably saline environments under reducing bottom conditions.
Although the origin of tricyclic terpanes is controversial, they
have been widely used as environment indicators . The low
concentrations of tricyclic terpanes in all samples from Bilong Co area
indicate a marine environment organism precursor as the source of these
biomarkers . The [C.sub.25]/[C.sub.26] tricyclic terpane ratio has
also been successfully applied as an environment parameter to
distinguish the marine and non-marine depositional environments .
The values of [C.sub.25]/[C.sub.26] (>1) indicate a marine
environment; however, the low [C.sub.25]/[C.sub.26] tricyclic terpane
ratio is usually associated with a non-marine environment. The high
values of [C.sub.25]/[C.sub.26] in most samples from the Bilong Co area
suggest that these rocks have been deposited in a marine environment
Gammacerane, a [C.sub.30] triterpane first identified in bitumen of
the Green River shale, is usually considered an indicator of hypersaline
marine and nonmarine depositional environments . Gammacerane index
(GI: gammacerane/hopane) increases with increasing salinity of
depositional conditions . In this study, the gammacerane indices
ranging from 0.07 to 0.15 in the oil shale samples, and from 0.09 to
3.11 in the micritic limestones (Table 2), probably suggest highly
saline conditions, which can also be supported by the distribution
pattern of even over odd dominance in midchain-length n-alkanes in the
sample BP-9. GI, combined with other biomarker parameters (e.g., Pr/Ph
ratio; [C.sub.25]/[C.sub.26] tricyclic terpane ratio) in our case
probably indicate that analyzed samples from the Bilong Co area were
deposited in a hypersaline marine environment under anoxic conditions.
Potential of hydrocarbon generation and oil-source rock correlation
The analytical data for oil shale samples from the Bilong Co area
show that they possess hydrocarbon generation potential (Table 1) with
greater than 6 wt.% of total organic carbon content and more than 27 mg
HC/g rock of the average [S.sub.2] value, whereas the source-rock
potential of micritic limestone samples is relatively low. The HI index
values of oil shale samples are in the range of 202.03-365.63 with the
average of 286.42 (Table 1). As seen from Fig. 2, obviously, all oil
shale samples are plotted more close to the oil-forming curve. These HI
values indicate that oil shale samples from the Bilong Co area possess
more oil-prone potential than gas-prone potential. This interpretation
is consistent with the high [S.sub.2]/[S.sub.3] rates of oil shale
samples (6.41-19.72). The rate of [S.sub.2]/[S.sub.3] higher than 5 also
indicates that these oil shale samples can generate oil.
Correlation between the characteristics of the oil shale in Bilong
Co area and those of their potential oils in this study was attempted
using biomarker parameters based on the GC, GC-MS. The biomarker
characteristics of the Bilong Co oil shale are very similar to that of
Zharen-Longeni crude oil in the southern Qiangtang depression (Fig. 6),
suggesting that the oil shale in the Bilong Co area has made a strong
contribution to the generation of Zharen-Longeni crude oil. Wang et al.
 also found the correlation between the Bilong Co oil shale and
Longeni oils by using carbon isotope data and biomarker parameters. The
carbon isotope curves of the Bilong Co oil shale and Longeni oils almost
match and their homohopane indices and diasterane contents are highly
similar, suggesting that the Longeni oils could have been sourced from
the oil shale in Bilong Co area. The oil-source rock correlation between
the Bilong Co oil shale and crude oil in the southern Qiangtang
depression is also supported by the research of Fu et al. . They
inferred, based on the similar carbon isotope compositions in both oil
shale and oils, that the Bilong Co oil shale could be one of the source
rocks of Zharen crude oil in the southern Qiangtang depression.
[FIGURE 6 OMITTED]
1. The TOC content and [S.sub.2] values of oil shale samples from
the Bilong Co area are high indicating that the oil shale from the
Bilong Co area has shale oil producing potential. Thermal maturity
assessed by [T.sub.max] shows a mature stage of the organic matter.
2. The Bilong Co oil shale is characterized by a dominance of low
carbon number molecular compositions with relatively high
[C.sup.21-]/[C.sup.21+] (0.82-1.95), low Pr/Ph (0.13-0.80), high
concentrations of homohopanes ([C.sub.31]-[C.sub.35]), and a slight
predominance of [C.sub.29] steranes, indicating reducing environments,
highly saline conditions, a strong contribution of inferior aquatic
organisms, and some influence of terrestrial organic matter.
3. The biomarker characteristics of the Bilong Co oil shale are
very similar to that of oil seepages in the southern Qiangtang
depression, suggesting that the oil shale in the Bilong Co area has made
a strong contribution to the generation of these oils.
This work was supported by the Sichuan Youth Science &
Technology Foundation (No. 09ZQ026-006), and the National Natural
Science Foundation of China (No. 40702020).
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Presented by Jialin Qian
Received January 30, 2011
YUHONG ZENG (a), XIUGEN FU (a) *, SHENGQIANG ZENG (ab), GU DU (a),
JIANG CHEN (a), QIAN ZHANG (a), YIRONG ZHANG (a), YANLING YAO (a)
(a) Chengdu Institute of Geology and Mineral Resources, Chengdu
(b) Chinese Academy of Geological Sciences, Beijing 100037, China
* Corresponding author: e-mail firstname.lastname@example.org
Table 1. Results of Rock-Eval/TOC analysis and calculated parameters
Samples Lithology TOC (a) [S.sub.1] (b) [S.sub.2] (c)
BP-6 Micritic 1.67 0.5 19.1
BP-7-1 Oil shale 6.75 0.51 20.16
BP-7-2 Oil shale 7.23 0.55 22.25
BP-7-3 Oil shale 6.91 0.5 20.67
BP-8 Micritic 1.36 0.54 23.08
BP-9 Micritic 0.36 0.03 0.3
BP-10-1 Oil shale 19.20 2.62 70.2
BP-10-2 Oil shale 7.95 0.4 5.96
BP-10-3 Oil shale 7.66 1.54 22.38
BP-10-4 Oil shale 9.11 1.26 23.79
BP-11 Micritic 2.10 0.24 5.46
BP-12-1 Oil shale 10.27 1.3 30.19
BP-12-2 Oil shale 10.66 1.23 30.36
BP-12-3 Oil shale 7.13 0.47 14.91
BP-13 Micritic 1.24 0.13 1.87
BP-14-1 Oil shale 10.96 1.25 36.48
BP-14-2 Oil shale 8.80 0.65 24.64
BP-14-3 Oil shale 13.50 1.2 39.98
Samples [S.sub.3] (d) type (e) HI (f) OI (g)
BP-6 1.77 10.79 286.36 26.54
BP-7-1 1.7 11.86 298.67 25.19
BP-7-2 1.78 12.50 307.75 24.62
BP-7-3 1.68 12.30 299.13 24.31
BP-8 2.26 10.21 276.08 27.03
BP-9 1.16 0.26 83.33 322.22
BP-10-1 3.56 19.72 365.63 18.54
BP-10-2 0.93 6.41 202.03 31.53
BP-10-3 1.42 15.76 292.17 18.54
BP-10-4 1.83 13.00 261.14 20.09
BP-11 0.64 8.53 260.00 30.48
BP-12-1 2.64 11.44 293.96 25.71
BP-12-2 2.86 10.62 284.80 26.83
BP-12-3 2.28 6.54 209.12 31.98
BP-13 1.12 1.67 150.81 90.32
BP-14-1 2.78 13.12 332.85 25.36
BP-14-2 3.07 8.03 280.00 34.89
BP-14-3 3.55 11.26 296.15 26.30
Samples [T.sub.max] (h)
(a) TOC (wt.%): total organic carbon content; (b) [S.sub.1] (mg
HC/g rock): free hydrocarbons; (c) [S.sub.2] (mg HC/g rock):
pyrolysable hydrocarbons; (d) [S.sub.3] (mg HC/g rock): carbon
dioxide; (e) Kerogen type ([S.sub.2]/[S.sub.3]); (f) HI (mg HC/g
TOC): hydrogen index; (g) OI (mg C[O.sub.2]/g TOC):oxygen index;
(h) [T.sub.max] ([degrees]C): temperature of maximum [S.sub.2].
Table 2. Biomarker parameters calculated based on m/z 191
aand m/z 217 mass chromatogram
Parameters of normal alkanes of
Samples Lithology and isoprenoid hydrocarbons terpanes
A B C D E F G
BP-6 M. l* 1.15 0.98 0.88 0.23 0.32 0.60 0.58
BP-7-1 Oil shale 1.38 0.99 0.70 0.19 0.31 0.55 0.58
BP-7-2 Oil shale 1.33 0.88 0.80 0.24 0.33 0.54 0.59
BP-7-3 Oil shale 1.61 0.93 0.71 0.19 0.27 0.53 0.55
BP-8 M. l* 1.06 0.90 0.83 0.23 0.30 0.58 0.58
BP-9 M. l* 0.29 0.81 0.49 0.32 0.59 0.60 0.61
BP-10-1 Oil shale 1.95 0.95 0.44 0.17 0.43 0.56 0.59
BP-10-2 Oil shale 0.82 0.95 0.49 0.33 0.79 0.67 0.60
BP-10-3 Oil shale 1.20 0.94 0.41 0.26 0.75 0.67 0.58
BP-10-4 Oil shale 1.79 1.03 0.37 0.28 0.87 0.67 0.58
BP-11 M. l* 1.30 0.98 0.40 0.19 0.43 0.67 0.56
BP-12-1 Oil shale 1.56 1.03 0.35 0.19 0.54 0.64 0.59
BP-12-2 Oil shale 1.62 0.98 0.40 0.20 0.53 0.65 0.56
BP-12-3 Oil shale 1.22 0.97 0.47 0.25 0.55 0.64 0.56
BP-13 M. l* 0.91 0.97 0.34 0.30 0.97 0.66 0.56
BP-14-1 Oil shale 1.37 0.98 0.46 0.29 0.70 0.63 0.56
BP-14-2 Oil shale 0.87 0.98 0.13 0.20 0.48 0.62 0.56
BP-14-3 Oil shale 1.31 1.07 0.20 0.19 0.48 0.63 0.57
Samples terpanes Parameters of steranes
H I J K % %
BP-6 0.11 1.55 0.40 0.46 46 17
BP-7-1 0.07 1.57 0.50 0.42 38 22
BP-7-2 0.10 1.56 0.50 0.41 40 24
BP-7-3 0.15 1.51 0.44 0.41 42 16
BP-8 0.26 1.59 0.48 0.44 39 23
BP-9 0.40 1.58 0.49 0.54 37 27
BP-10-1 0.12 1.83 0.49 0.43 38 21
BP-10-2 0.09 1.50 0.46 0.46 36 20
BP-10-3 0.11 2.28 0.47 0.46 35 21
BP-10-4 0.09 1.96 0.38 0.52 36 21
BP-11 0.09 1.74 0.23 0.51 39 27
BP-12-1 0.10 1.61 0.46 0.46 35 21
BP-12-2 0.08 1.95 0.39 0.50 34 23
BP-12-3 0.07 1.69 0.42 0.43 34 19
BP-13 3.11 2.14 0.38 0.53 33 25
BP-14-1 0.08 1.65 0.38 0.48 35 20
BP-14-2 0.08 1.78 0.35 0.48 35 20
BP-14-3 0.08 1.65 0.37 0.50 37 21
Samples Parameters of steranes
A: [C.sub.21.sup.-] /[C.sub.21.sup.+]; B: OEP; C: Pr/Ph
(pristane/phytane); D: Pr/n[C.sub.17] (pristane/normal-[C.sub.17]);
E: Ph/n[C.sub.18] (phytane/normal-[C.sub.18]); F: Ts/(Ts+Tm) (Ts:
18[alpha](H), 22, 29, 30-trisnorneohopane; Tm: 17[alpha](H), 22, 29,
30-trisnorhopane); G: [C.sub.32]Hop 22S/(22S+22R) (17[alpha](H),
21[beta](H)-bis-homohopane (22S)/[ 17[alpha](H),
21[beta](H)-bishomohopane (22S)+ 17[alpha](H),
21[beta](H)-bishomohopane (22R)] of [C.sub.32] homohopane); H: G
index (gammacerane/[C.sub.30] hopane); I: [C.sub.25] tri/[C.sub.26]
tri ([C.sub.25] tricyclic terpanes/[C.sub.26] tricyclic terpanes);
J: [C.sub.29]St 20S/(20S+20R) (5[alpha] (H), 14[alpha] (H),
17[alpha](H)-20S/[5[alpha](H), 14[alpha] (H), 17[alpha]
(H)-20S+5[alpha] (H), 14[alpha](H), 17[alpha] (H)-20R] of
[C.sub.29] sterane); K: [C.sub.29]St
[beta][beta]/([alpha][alpha]+[beta][beta]) (C29-regular sterane
20[alpha][beta][beta]R+20[alpha][beta][beta]S) isomer ratio.
M. l*--micritic limestone.