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AUTHORS
Cari L. Johnson � Department of Geologicaland Environmental Sciences, Building 320, StanfordUniversity, Stanford, California, 94305-2115; currentaddress: Department of Geology and Geophysics,University of Utah, 135 South 1460 East, BrowningBuilding, Salt Lake City, Utah, 84112-0011;cjohnson@mines.utah.edu
Cari Johnson is an assistant professor at theUniversity of Utah. She received geology degreesfrom Carleton College (B.A., 1996) and StanfordUniversity (Ph.D., 2002), where she also completedpostdoctoral research on sequence stratigraphy ofthe San Joaquin basin. Her dissertation focused onthe sedimentary record of Late Mezosoic extensionin the China–Mongolia border region. She continuesto conduct research in basin analysis, sedimentationand tectonics, and petroleum geology in east-centralAsia and western North America.
Todd J. Greene � Department of Geological andEnvironmental Sciences, Building 320, StanfordUniversity, Stanford, California, 94305-2115; currentaddress: Anadarko Petroleum Corporation, 1201Lake Robbins Drive, The Woodlands, Texas, 77380
Todd Greene attained a B.S. degree in earthsciences from the University of California at SantaCruz (1994) and a Ph.D. in geological sciences atStanford University (2000). His dissertation focusedon tectonics, sedimentology, organic geochemistry,and petroleum systems of the Turpan-Hami basin ofnorthwestern China. He is currently employed byAnadarko Petroleum in Houston, Texas, where he ispart of a regional studies team investigating basinsand play types in the greater Rocky Mountains.
David A. Zinniker � Department of Geologicaland Environmental Sciences, Building 320, StanfordUniversity, Stanford, California, 94305-2115
David A. Zinniker is a Ph.D. candidate in the Depart-ment of Geological and Environmental Sciences atStanford University. His research focuses on molec-ular fossils of plants and algae and their bearingupon ecology, evolution, depositional systems, andpetroleum geology. His future projects include usingmolecular and macromolecular markers to studycurrent ecological processes and events deep ingeologic time.
J. Michael Moldowan � Department of Geolog-ical and Environmental Sciences, Building 320,Stanford University, Stanford, California, 94305-2115
J. Michael Moldowan attained a B.S. degree inchemistry from Wayne State University, 1968, anda Ph.D. in chemistry from the University of Michi-gan in 1972. Following a postdoctoral fellowship inmarine natural products with Professor Carl Djerassi
Geochemical characteristics andcorrelation of oil and nonmarinesource rocks from MongoliaCari L. Johnson, Todd J. Greene, David A. Zinniker,J. Michael Moldowan, Marc S. Hendrix, andAlan R. Carroll
ABSTRACT
New bulk and molecular organic geochemical analyses of source rock
and oil samples from Mongolia indicate the presence of lacustrine-
sourced petroleum systems in this frontier region. Samples of po-
tential source rocks include carbonate, coal, and lacustrine-mudstone
lithologies that range from Paleozoic to Mesozoic in age, and rep-
resent a variety of tectonic settings and depositional environments.
Rock-Eval and total organic carbon data from these samples reflect
generally high-quality source rocks, including both oil- and gas-prone
kerogen types, mainly in the early stages of generation. Bulk geo-
chemical and biomarker data indicate that Lower Cretaceous lacus-
trine mudstone found in core from the Zuunbayan field is the most
likely source facies for the East Gobi basin of southeastern Mon-
golia. Oil and selected source rock samples from the Zuunbayan
and Tsagan Els fields (both in the East Gobi basin) demonstrate geo-
chemical characteristics consistent with nonmarine source environ-
ments and indicate strong evidence for algal input into fresh- to
brackish-water source facies, including elevated concentrations of
unusual hexacyclic and heptacyclic polyprenoids. Despite similar-
ities between Zuunbayan and Tsagan Els oil samples, biomarker
parameters suggest higher algal input in facies sourcing Zuunbayan
oil compared to Tsagan Els oil. Tsagan Els oil samples are also gen-
erated by distinctly more mature source rocks than oil from the
Zuunbayan field, based on sterane and hopane isomerization ratios.
INTRODUCTION
Central and eastern China contain several petroleum-bearing, late
Mesozoic rift basins (e.g., Songliao and Erlian; Figure 1, inset). Var-
ious studies address these Asian lacustrine systems from regional
stratigraphic and source-geochemical perspectives (Yang, 1985; Fu
Copyright #2003. The American Association of Petroleum Geologists. All rights reserved.
Manuscript received January 18, 2002; provisional acceptance August 20, 2002; revised manuscriptreceived November 25, 2002; final acceptance December 17, 2002.
AAPG Bulletin, v. 87, no. 5 (May 2003), pp. 817–846 817
818 Geochemical Characteristics and Correlation of Oil and Nonmarine Source Rocks
and Sheng, 1992; Gao et al., 1997; Lin et al., 2001). Comparatively
little is known about related Mesozoic rift basins in Mongolia (spe-
cifically, the Tamtsag and East Gobi basins; Figure 1), where pe-
troleum systems remain poorly understood and underexplored
(Penttila, 1994; Sladen and Traynor, 2000).
Penttila (1994) estimated as much as 3–6 billion BOE recoverable
hydrocarbon resources in Mongolia, although reserve calculations are
difficult to constrain in this poorly known petroleum province. Petro-
leum production in Mongolia is currently limited to the East Gobi
and Tamtsag basins (Figure 1), the latter hosting discoveries in 2001
totaling an estimated 1.5 billion bbl of oil in place (Soco Inter-
national, 2001). Although historic discoveries in Mongolia generally
have been modest, the potential for larger hydrocarbon accumula-
tions exists by analogy to similar basins in China. These include the
largest producing field in China, Daqing (production �1.0 million
bbl/day; United States Department of Energy, 2001), in addition to
smaller accumulations in Erlian basin (e.g., Aershan field with esti-
mated 100 million bbl reserves; Sladen and Traynor, 2000).
The East Gobi basin shares several characteristics with late
Mesozoic rift basins in China. These similarities include the age and
depositional style of nonmarine basin fill, and northeast-southwest
orientation of rift structures (Liu, 1986; Watson et al., 1987). Rifting
began during the Late Jurassic and continued through the Early Cre-
taceous, with widespread deposition of fluvial-lacustrine strata and
periodic bimodal volcanic activity (Traynor and Sladen, 1995; Johnson
et al., 2001). Middle Cretaceous contraction and strike-slip faulting
inverted the East Gobi basin along its margin, forming a regional
angular unconformity overlapped by an Upper Cretaceous postrift
sequence (Figure 2) (Graham et al., 2001). The total original thick-
ness of synrift strata is not known because of erosion during the
basin-inversion event, but more than 2.5 km of sedimentary and
volcanic graben fill is still preserved in the subsurface of the East
Gobi, based on proprietary seismic and well-log data (Johnson, 2002)
and correlative outcrop studies (Graham et al., 2001).
Synrift strata form source, reservoir, and seal units in south-
eastern Mongolia, mainly in inversion-related structural traps (Fig-
ure 2). In the East Gobi basin, the main source rocks appear to be
lacustrine shales of the Lower Cretaceous Tsagantsav Formation
(synrift sequence 3 of Graham et al., 2001), based on previous geo-
chemical studies of source rocks from southeastern Mongolia (Yama-
moto et al., 1998). This formation is widely distributed in eastern
Mongolia and correlates to Lower Cretaceous lacustrine shale in the
Nilga and Tamtsag basins as well (Badamgarav et al., 1995; Neves
et al., 2000). The overlying Zuunbayan Group (synrift sequence 4,
Figure 2) is generally more sand rich, although fine-grained lacus-
trine units are also present (Jerzykiewicz and Russell, 1991). Pe-
troleum reservoirs mainly occur in fluvial to perilacustrine (deltaic)
sandstone of the Lower Cretaceous strata (Johnson et al., 2000)
and are commonly limited in quality by abundant lithic grains derived
from synrift volcanic activity, in addition to associated porosity-
reducing zeolite cements. Particularly in Mongolia, outcropping synrift
at Stanford University, he joined Chevron’s BiomarkerGroup in 1974. Moldowan joined the Department ofGeological and Environmental Sciences of StanfordUniversity as professor (research) in 1993.
Marc S. Hendrix � Department of Geology,University of Montana, Missoula, Montana, 59812
Marc S. Hendrix received geology degrees fromWittenberg University (B.A., 1985), the Universityof Wisconsin, Madison (M.S., 1987), and StanfordUniversity (Ph.D., 1992). He completed postdoctoralresearch at Stanford in 1994 and since has been aprofessor of geology at the University of Montana,Missoula. His research interests include sedimentarybasins and paleoclimate studies, particularly inwestern North America and central Asia.
Alan R. Carroll � Department of Geology andGeophysics, University of Wisconsin, Madison, 1215W. Dayton St., Madison, Wisconsin, 53706
Alan Carroll conducts research on large lake basinsin Asia and the western United States, focusing ontheir tectonic setting, sequence stratigraphy, andpetroleum potential. He worked for three years asan exploration geologist for Sohio, and five years forExxon Production Research. He is currently an asso-ciate professor at the University of Wisconsin.
ACKNOWLEDGEMENTS
We thank D. Badamgarav, G. Badarch, R. Barsbold,D. Janchiv, and our other colleagues at the MongolianAcademy of Sciences, Institute of Geology and Min-eral Resources, the Petroleum Authority of Mongolia,and the Mongolian Paleontological Institute for theirscientific and logistic support. Funding for this studywas provided by Roc Oil, the Stanford GraduateFellowship, the International Research and ExchangeBoard, the Stanford-Mongolia Industrial Affiliatesprogram, and by National Science Foundation grantsEAR-9708207 and EAR-961455 to S. Graham and M.Hendrix, respectively. S. Graham was a principaladvisor on this and related projects in Mongolia andoffered much insight throughout this study. Col-leagues at various labs assisted with sample analysis,including K. K. Bissada (Houston Advanced ResearchCenter), H. Hada (Micropaleoconsultants), andZhengzheng Chen, D. Mucciarone, and F. Fago atStanford University. Additional bulk geochemicalanalyses were completed at ExxonMobil UpstreamResearch (formerly EPRC). We thank P. Albrecht andP. Adam for discussion and supporting data onpolycyclized polyprenoids and E. Chang (StanfordUniversity) for the Chinese oil samples. J. Amory,M. Beck, L. Lamb, R. Lenegan, D. Sjostrom, E. Sobel,and L. Webb provided additional assistance in thefield. Reviews by M. Fowler, K. Peters, and Wan Yanggreatly improved this manuscript.
Johnson et al. 819
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fluvial-lacustrine facies have only recently been described
in detail (Graham et al., 2001), and there remains almost
no English-language published literature discussing sub-
surface data (Johnson, 2002).
The organic geochemistry database for Mongolian
oil and source rocks is also limited. Sladen and Traynor
(2000) reported Rock-Eval and total organic carbon
(TOC) data from Paleozoic–Mesozoic source rocks, as
well as oil data suggesting geochemical oil-source cor-
relation to low-maturity Lower Cretaceous lacustrine
mudstones in southeastern Mongolia, including com-
bustible oil shales. Palynological evidence for green
algae (including Botryococcus), and the presence of
b-carotane in source rock extracts indicate algal input in
slightly saline to freshwater lakes with anoxic bottom
waters throughout the synrift sequences (Neves et al.,
2000; Sladen and Traynor, 2000). Yamamoto et al. (1993,
1998) also reported geochemical evidence for bloom-
ing autotrophic prokaryotes and thermal stratification
of Cretaceous lakes with anoxic lake-bottom conditions
in the East Gobi and Nilga basins. Similarly, dinoflag-
ellate blooms signaling periods of high nutrient flux
were common in lakes of the Tamtsag basin (Neves
et al., 2000) and in China (Wang Renhou et al., 1996;
Wan et al., 1997) during the Early Cretaceous. Most of
these interpretations are based on spore/pollen analyses,
Rock-Eval data, and whole-rock geochemistry, lacking
detailed biomarker data.
The purpose of this study is twofold. First, we pres-
ent the results of reconnaissance sampling of a range
of source rocks from throughout Mongolia. Bulk geo-
chemical analyses of this sample suite demonstrate the
presence of a variety of potential source rocks, but strong-
ly suggest that known occurrences of oil in southeastern
Mongolia are sourced by Lower Cretaceous lacustrine
mudstone. We investigate this correlation further in the
second part of the study, by examining detailed source-
rock-to-oil relationships in the Tsagan Els and Zuun-
bayan fields of the East Gobi basin.
METHODS
Our database includes oil and source rock samples col-
lected from 1992 to 2000 during fieldwork in Mongo-
lia (Table 1). Sample preparation and analyses were
performed at several laboratories, although the major-
ity of molecular data presented here were collected at
Stanford University’s Molecular Organic Geochemis-
try Laboratory. Source rock samples were evaluated by
Rock-Eval and TOC analyses using standard proce-
dures (Table 2). For selected source rock samples, sol-
uble bitumens were extracted from rock powders using
a Soxhlet apparatus and a mixture of methanol and tol-
uene solvents. Samples collected in 1992–1993 (sample
numbers beginning with 92 or 93, Table 1), were ex-
tracted and analyzed using standard (nC12 and higher)
gas chromatography at ExxonMobil Upstream Research
(formerly EPRC). Subsequently collected samples were
extracted and analyzed by gas chromatography with
flame ionization detection (GC-FID) at Stanford Uni-
versity using a Hewlett-Packard 5890A gas chromato-
graph. Other conventional organic geochemical analyses
(stable carbon isotope, sulfur, wax, etc.) were completed
at the Houston Advanced Research Center and at Stan-
ford University.
All reported rock extracts and oil samples were
separated by high-performance liquid chromatography
(HPLC) into saturate and aromatic fractions at Stan-
ford University, following procedures outlined by Peters
and Moldowan (1993). Saturate cuts were further pre-
pared using molecular sieves (silicalite) to remove all
of the n-alkanes and increase the signal of more di-
agnostic biomarkers. Saturate and aromatic fractions
were analyzed on a Hewlett-Packard 5890 Series II-Trio
1 VG Masslab gas chromatograph–mass spectrometer
(GCMS) system. A Hewlett-Packard 5890 Series II-
Micromass Autospec Q hybrid GCMS system was used
for further sterane analyses using MRM-GCMS (meta-
stable reaction monitoring), in addition to scan runs for
analysis of hexacyclic and heptacyclic cyclic polyprenoids.
SOURCE ROCK SAMPLE DESCRIPTION
More than 75 potential source rocks ranging in age
from Riphean–Cambrian to Cretaceous, were sampled
between 1992 and 1999. The source rocks are mainly
from outcrops in Mongolia spanning some 800,000
km2 of sampling area (Figure 1), but also include four
subsurface core samples (ZB core, Table 1). Lithologies
include shale, calcareous mudstone, coal, coaly mudstone,
and carbonate (Table 2). Ages are mainly based on pub-
lished and unpublished mapping by Mongolian agencies
Johnson et al. 821
Figure 2. Overview of Mesozoic tectonostratigraphic units in southeastern Mongolia. Sequence-stratigraphic nomenclature of Traynor and Sladen(1995), Graham et al. (2001), and Johnson (2002) are shown, along with interpreted tectonic settings and local formation names. The total thicknessof preserved synrift deposits in the subsurface is approximately 2.5–3 km as estimated from seismic reflection profiles and velocity models.
(e.g., Yanshin, 1989; Badarch, 1999, personal commu-
nication), in addition to spore/pollen analyses, vertebrate
and invertebrate faunal assemblages, and 40Ar/39Ar data
where available (Jerzykiewicz and Russell, 1991; Gra-
ham et al., 2001).
Our source rock sample suite encompasses a range
of tectonostratigraphic units representing the geologi-
cally diverse history of Mongolia. The oldest samples
are Riphean–Cambrian carbonates from northern Mon-
golia (MO and WH localities; Figure 1), which formed
on carbonate platforms of the south-facing Siberian pas-
sive margin (megasequence 1 of Traynor and Sladen,
1995). These rocks predate assembly of the present-
day Mongolian basement, which occurred mainly during
the Paleozoic through amalgamation of several volcan-
ic arcs and related basins (Lamb and Badarch, 1997).
Carboniferous–Permian coal and coaly mudstone sam-
ples (TT, SJ localities) immediately postdate these
Paleozoic collisions and represent the beginning of non-
marine deposition in central Mongolia (Traynor and
Sladen, 1995; Amory, 1996).
Triassic and Lower Jurassic samples from western,
central, and southern Mongolia (samples NU, JL, CM,
DZ, and SO) formed in lakes and swamps of foreland
and intermontane basins associated with continuing col-
lisions along the margins of central Asia (megasequence
3 of Traynor and Sladen, 1995; Hendrix et al., 2001;
Sjostrom et al., 2001). In the East Gobi basin, a Lower
to Middle Jurassic prerift section is represented by the
Khamarkhavoor Formation (Figure 2), which includes
thin coal seams and palustrine shale (Graham et al.,
2001). Samples from this unit were not analyzed in the
present study, but future analyses may address the po-
tential for a Jurassic, prerift source in the East Gobi basin.
This period of early Mesozoic contractile tectonism
ended with widespread uplift and erosion during the
Middle Jurassic, followed by Late Jurassic–Early Cre-
taceous extension in eastern and southeastern Mongo-
lia. Upper Mesozoic coal and lacustrine shale samples
from the East Gobi and related basins are part of this
intracontinental rift sequence (BT, NL, SH, TH, ZB,
and UB samples). SH samples are from the type Shin-
hudag section outcropping in the Nilga basin, north of
the East Gobi (Figure 1). The locality has more than
100 m of weathered marl and laminated mudstone,
and is part of the Zuunbayan Group, a late synrift se-
quence (Lower Cretaceous; Badamgarav et al., 1995).
TH samples are from the synrift section deposited on
822 Geochemical Characteristics and Correlation of Oil and Nonmarine Source Rocks
Table 1. List of Sample Abbreviations, Locality Names, and Location*
Sample Locality Latitude (N) Longitude (E)
Source Rocks97-SH-(02–13) Shinhudag 44.71 107.93
98-TH-(314–316) Tavan Har 44.03 109.37
ZB-(1716–1978) Zuunbayan core (SWZB-310b well) 44.25 109.55
92-UB-(4–15) Ulaan Bataar 47.46 107.18
93-NL-(3) Nilga basin 44.80 106.95
94-BT-(1–3) Bayan Tolgoy 45.70 101.54
92-JL-(6–9) Jargalant 47.30 92.37
92-CM-(3–22) Chandaman 45.22 97.53
92-DZ-(2–6) Dzinst 44.34 99.13
93-SO-(1–209) Sayan Obo 45.73 105.18
92-NU-(48–52) Noyon Uul 43.14 101.55
93-TT-(201–302) Tsogt Tsitsee 43.62 105.47
92-SJ-(36a) Shin Jeanst 44.22 99.25
93-MO-(2–4) Moron 50.55 101.18
93-WH-(3–4) West Hobsgul 50.55 101.18
Oil SamplesTE-(A1-25) Tsagan Els field 44.00 109.75
ZB-(310b; 163251a–b) Zuunbayan field 44.25 109.90
ER-(1846) Erlian basin (Saihantala sag) 42.25 110.50
DQ-(2198) Daqing (Yushuling field) 45.75 125.50
*Sample abbreviations based on last two digits of sampling year, two-letter locality abbreviation, and sample number. Locality names are based on local towns,landmarks, or formation names. Sample locations are in decimal degrees latitude and longitude.
the Tavan Har basement structure, about 50 km south-
west of the Zuunbayan field. The section includes
about 300 m of oil shale overlain by volcanic ash and
basalt units, and can be tied to the Tsagantsav Forma-
tion (Lower Cretaceous) by proprietary regional seis-
mic reflection profiles. UB samples were all collected
from an open-pit coal mine about 15 km east of Ulaan
Bataar. Exposed strata in the mine are reportedly of
Albian–Aptian age (D. Badamgarav, 1992, personal
communication) and include coal, organic-rich clay-
stone, and sandstone. Abundant climbing ripples and
soft-sediment deformation in the sandstone beds sug-
gest they were deposited rapidly, possibly as crevasse
splay deposits in a fluvial overbank or swamp setting
(Farrell, 2001). BT samples were collected from an open-
pit coal mine in the centralGobi basin.This coal is mapped
as Cretaceous (Yanshin, 1989), although no published
age data are available. The NL samples are from an ex-
humed oil field that is presently being quarried for
tar sand in the Nilga basin, about 200 km southeast
of Ulaan Bataar. Source rock samples from this basin
include laminated, organic-rich shale.
ZB core samples are taken from conventional 6-cm-
diameter core of the ZB-310b well in the southwest
Zuunbayan field. Over 600 m of Lower Cretaceous
fluvial-lacustrine facies comprise the Zuunbayan core
(Graham et al., 2001). A 125-m-thick section of the
core (unit 2, Figure 3) consists of finely laminated
mudstone and micrite, dolomitic breccia, and calcar-
eous siltstone (described in Johnson, 2002). These fine-
grained units are interbedded with grainstone and thin,
normally graded sandstone beds interpreted as distal
lacustrine turbidites (Grabowski and Pevear, 1985).
This lacustrine sequence has been mapped in both the
Zuunbayan and Tsagen Els subbasins based on well-log
and seismic reflection character (A. Hall, 2000, person-
al communication). Evidence for anoxic conditions at
the lake bottom includes framboidal (biogenic) pyrite,
high %TOC, dominance of light-colored amorphous
organic constituents, carbonate precipitation, and a pau-
city of trace fossils relative to the rest of the core (John-
son, 2002). Abundant fish remain, possible algal cysts,
and conchostrachan and ostracod valves attest to better
oxygenation in the upper parts of the water column. The
lower half of the lacustrine section (depths 605–550 m)
is dominated by laminated micrite and dolomitic breccia
units (thought to be subaqueously precipitated; Wolf-
bauer and Surdam, 1974; Johnson, 2002), and generally
lacks trace and invertebrate fossils. The upper section
(544–468-m depth) contains more of these fossils
(mainly gastropods, ostracods, and conchostrachans)
in poorly laminated calcareous siltstone, having local
traction-current structures such as thin, normally grad-
ed, rippled beds. The lower section is interpreted as an
anoxic lake-bottom sequence in a stratified lake, which
includes samples ZB-1978 and ZB-1933 (Powell, 1986).
The upper half, which includes sample ZB-1740, appears
to have better oxygenation resulting from more circula-
tion at the lake bottom, representing a nonstratified lake
or possibly more marginal facies (Powell, 1986). Sample
numbers represent depth below KB (4 m) in feet (con-
verted to meters on Figure 3).
SOURCE ROCK BULK GEOCHEMISTRY
Rock-Eval pyrolysis indicates a suite of generally high-
quality source rocks (Table 2), excluding the Riphaen–
Cambrian strata. TOC ranges from 1.5 to 15% for shale
and 40 to 75% for coal and coaly mudstone samples.
More than 75% of the samples have S1 and S2 values
greater than 0.5 and 10, respectively, also indicating
good to very good quality source rocks (Peters, 1986).
Source rock maturities are mainly immature to mid-
dle oil window, although the Triassic–Jurassic NU
and Permian TT samples approach peak oil window to
overmature based on Tmax, PI, and Ro values (Tables 2,
3; Peters and Moldowan, 1993). HI-versus-OI values
(Figure 4) indicate dominantly type I and type II (oil-
prone) kerogen, but also include type III (gas-prone)
kerogen in some of the lower Mesozoic coal samples
(Tissot et al., 1974). Visual maceral analysis confirms a
range of oil-prone liptinite (from algal and waxy-plant
debris) in the Triassic–Jurassic oil shales (NU sam-
ples), whereas gas-prone vitrinite and inertinite (type
IV nongenerative kerogen of Demaison et al., 1983)
dominate the coal samples (JL, CM, and DZ samples;
Table 3). Gas chromatographic data were collected
from whole-rock extracts for selected Mesozoic sam-
ples (Table 4). Maximum n-alkane peaks are mainly
between nC15–nC25 (Figure 5), show a rapid falloff of
higher n-alkanes (>nC29), and a slight to pronounced
odd-over-even preference, particularly in the Lower
Cretaceous samples.
The source rocks form five main groups reflecting
distinct ages, lithofacies, geographic distribution, kero-
gen type, and maturity (Table 5). Lower Cretaceous
rocks from central and southern Mongolia (group 1)
include TOC values of 1.5–30% for mudstone and
oil shale and greater than 45% for coaly samples. HI-
versus-OI ratios indicate variable kerogen type in group
1 (Figure 4) (Peters, 1986; Tissot et al., 1974). SH and
Johnson et al. 823
824 Geochemical Characteristics and Correlation of Oil and Nonmarine Source Rocks
Table 2. Rock-Eval plus TOC Data for Mongolian Source Rock Samples*
Age Sample Lithology Lab %TOC S1 S2 S3 PI Tmax OI HI S2/S3 S1/TOC
Late Cretaceous 97-SH-02 shale 1 9.83 0.76 63.04 5.49 0.01 444 56 641 11.48 7.73
97-SH-03 shale 1 5.72 0.40 25.36 4.39 0.02 433 77 443 5.78 6.99
97-SH-04 shale 1 6.70 0.58 40.12 4.25 0.01 439 63 599 9.44 8.66
97-SH-05 shale 1 7.84 0.90 43.56 5.55 0.02 441 71 556 7.85 11.48
97-SH-07 shale 1 4.60 0.41 25.74 3.91 0.02 437 85 560 6.58 8.91
97-SH-09 shale 1 8.39 1.17 57.78 4.16 0.02 443 50 689 13.89 13.95
97-SH-11 shale 1 6.56 0.93 45.04 3.32 0.02 438 51 687 13.57 14.18
97-SH-12 shale 1 14.60 1.50 132.40 6.10 0.01 446 42 907 21.70 10.27
97-SH-13 shale 1 7.10 0.53 56.14 3.75 0.01 440 53 791 14.97 7.46
98-TH-314 shale 2 1.54 0.32 4.98 0.08 0.06 437 5 323 62.25 20.78
98-TH-316 shale 2 2.30 0.51 10.09 0.20 0.05 433 8 438 50.45 22.21
ZB-1716 (core) mudstone 3 1.80 0.25 7.57 0.40 0.03 438 22 421 18.93 14.00
ZB-1740 (core) mudstone 3 2.03 0.35 9.13 0.48 0.04 439 24 450 19.02 17.00
ZB-1933 (core) mudstone 3 4.23 1.54 24.67 0.71 0.06 434 17 583 34.75 36.00
ZB-1978 (core) mudstone 3 2.00 0.31 8.46 0.44 0.04 438 22 423 19.23 16.00
92-UB-4 coal 4 51.77 0.70 54.92 15.43 0.01 419 30 106 3.56 1.35
92-UB-10 coaly mudstone 4 44.77 2.44 122.35 9.54 0.02 426 21 273 12.82 5.45
92-UB-12 coal 4 54.27 0.82 74.97 15.27 0.01 411 28 138 4.91 1.51
92-UB-15 carbonate 4 10.47 0.28 21.72 2.64 0.01 425 25 207 8.23 2.67
93-NL-3 shale 5 2.65 0.11 7.96 1.87 0.01 434 71 300 4.26 4.15
94-BT-1 coal 5 59.22 2.53 196.40 9.05 0.01 428 15 332 21.70 4.27
94-BT-2 coal 5 56.75 3.15 236.80 1.78 0.01 425 3 417 133.03 5.55
94-BT-3 shale 5 29.94 2.89 144.90 2.12 0.02 432 7 484 68.35 9.65
Lower–Middle
Jurassic 92-JL-6 coaly mudstone 4 48.89 1.01 35.56 40.45 0.03 422 83 73 0.88 2.07
92-JL-9 coaly mudstone 4 44.43 0.83 17.25 36.51 0.05 422 82 39 0.47 1.87
92-CM-3 coal 4 64.54 0.87 32.23 22.46 0.03 429 35 50 1.43 1.35
92-CM-10 coal 4 61.27 1.47 41.59 21.02 0.03 427 34 68 1.98 2.40
92-CM-12 calcareous mudstone 4 33.23 1.86 38.29 13.20 0.05 428 40 115 2.90 5.60
92-CM-17 coal 4 55.49 2.85 44.62 14.54 0.06 428 26 80 3.07 5.14
92-CM-20 coal 4 59.85 1.51 39.64 21.23 0.04 427 35 66 1.87 2.52
92-CM-22 calcareous siltstone 4 11.03 0.75 17.44 2.68 0.04 437 24 158 6.51 6.80
92-DZ-2 calcareous siltstone 4 2.46 0.16 2.95 0.63 0.05 436 26 120 4.68 6.50
92-DZ-6 coal 4 52.47 0.74 32.43 23.75 0.02 432 45 62 1.37 1.41
93-SO-1 shale 5 13.23 1.02 54.19 1.60 0.02 429 12 410 33.87 7.71
93-SO-2 shale 5 14.10 1.18 60.27 2.27 0.02 429 16 427 26.55 8.37
93-SO-3 shale 5 22.64 2.26 97.17 2.31 0.02 427 10 429 42.06 9.98
93-SO-201 coaly mudstone 5 49.65 1.99 209.35 5.87 0.01 421 12 422 35.66 4.01
93-SO-207 coal 5 63.24 1.52 192.66 8.28 0.01 423 13 305 23.27 2.40
93-SO-208 coaly mudstone 5 43.42 2.38 251.17 2.50 0.01 434 6 578 100.47 5.48
93-SO-209 coal 5 55.41 2.56 238.79 3.48 0.01 429 6 431 68.62 4.62
Triassic–Jurassic 92-NU-48B shale 4 3.36 0.13 18.10 0.28 0.01 443 8 539 64.64 3.87
92-NU-49 shale 4 2.92 0.24 18.06 0.34 0.01 444 12 618 53.12 8.22
92-NU-50 shale 4 3.01 0.23 19.52 0.26 0.01 444 9 649 75.08 7.64
92-NU-51 shale 4 2.68 0.22 16.01 0.31 0.01 441 12 597 51.65 8.21
92-NU-52 shale 4 3.48 0.20 17.28 0.35 0.01 441 10 497 49.37 5.75
NL samples from the Nilga basin have relatively high
HI and OI values, whereas other source rocks from
central and southern Mongolia have lower OI values
and variable HI values ranging from type I and II (ZB,
TH, and BT samples) to near type III (gas-prone) ker-
ogen in the UB coal samples (which also generally show
a predominance of vitrinite macerals, Table 3). Tmax
values in group 1 range from 411 to 444 (Table 2),
indicating immature to early oil window maturity levels.
PI values are consistent with this interpretation, ranging
from 0.01 to 0.02 for most group 1 samples and slightly
higher (0.03–0.06) for ZB and TH samples from the
East Gobi basin. Similarly, a high carbon preference in-
dex for SH and TH outcrop samples is likely the result
of lower thermal maturities in these outcrops along the
basin margins (Figure 6) (Peters and Moldowan, 1993).
Lower Mesozoic samples from central and western
Mongolia consist of shale, coaly mudstone, and coal li-
thologies having TOC values ranging from 2 to 65%.
These Triassic to Lower Jurassic samples form two
groups distinguished by kerogen type and maturity
(Table 5): Lower to Middle Jurassic JL, CM, and DZ
samples (group 2) contain predominantly vitrinite
and intertinite macerals, and plot within the type II
and type III (liquid to slightly gas-prone) range on a
modified Van Krevelen diagram (Figure 4). Triassic to
Lower Jurassic NU and SO samples (group 3) are liquid-
source prone based on maceral analysis (‘‘plant tissue’’
Johnson et al. 825
Age Sample Lithology Lab %TOC S1 S2 S3 PI Tmax OI HI S2/S3 S1/TOC
Permian 93-TT-201 coal 4 69.1 6.31 173.6 1.44 0.04 453 2.1 251.3 121 0.09
93-TT-202 coal 4 62.6 5.61 145.7 1.1 0.04 447 1.8 232.8 132 0.09
93-TT-204 coaly mudstone 4 20.9 1.5 51.1 0.86 0.03 452 4.1 244.4 59 0.07
93-TT-205 coal 4 66.6 3 143.8 1.32 0.02 446 2.0 216.0 109 0.05
93-TT-206 coal 4 72.7 5.71 173.9 0.86 0.03 452 1.2 239.2 202 0.08
93-TT-207 coal 4 68.2 7.07 179.8 1.01 0.04 452 1.5 263.7 178 0.10
93-TT-208 coal 4 73.2 5.53 182.1 1.27 0.03 450 1.7 248.8 143 0.08
93-TT-209 coal 4 68.7 7.31 179.6 0.91 0.04 453 1.3 261.5 197 0.11
93-TT-210 coal 4 66.9 5.38 147.4 0.53 0.04 448 0.8 220.4 278 0.08
93-TT-211 coal 4 72.3 5.56 182.9 0.74 0.03 451 1.0 252.9 247 0.08
93-TT-212 coal 4 74.6 4.63 175.9 1.23 0.03 454 1.6 235.6 143 0.06
93-TT-213 coal 4 67.4 6.79 111.6 0.96 0.06 447 1.4 165.7 116 0.10
93-TT-214 coal 4 70.3 5.75 128.4 1.5 0.04 453 2.1 182.8 86 0.08
93-TT-215 coal 4 64.6 5.15 153.3 0.86 0.03 448 1.3 237.3 178 0.08
93-TT-216 coal 4 76.4 7.42 207.7 0.52 0.04 449 0.7 271.8 399 0.10
93-TT-217 coal 4 59.2 4.2 152.9 0.7 0.03 448 1.2 258.2 218 0.07
93-TT-218 coal 4 70.0 4.88 143.6 1.33 0.03 446 1.9 205.1 108 0.07
93-TT-219 coal 4 62.4 5.2 108.0 1.09 0.05 447 1.7 173.2 99 0.08
93-TT-220 coal 4 64.0 4.43 104.9 1.05 0.04 450 1.6 163.8 100 0.07
93-TT-301 coal 4 56.7 3.74 110.1 0.71 0.03 463 1.3 194.3 155 0.07
93-TT-302 coal 4 65.7 5.03 145.8 0.55 0.03 455 0.8 221.9 265 0.08
Devonian–
Carboniferous 92-SJ-36A shale 5 1.68 0.00 0.19 0.47 0.00 441 28 11 0.40 0.00
Cambrian 93-WH-3D carbonate 4 0.75 0.02 0.76 0.12 0.03 434 16 101 6.33 2.67
93-WH-4B carbonate 4 1.19 0.03 2.43 0.09 0.01 429 8 204 27.00 2.52
Riphean 93-MO-2F carbonate 4 0.65 0.01 0.34 0.07 0.03 438 11 52 4.86 1.54
93-MO-3G carbonate 4 0.58 0.01 0.72 0.13 0.01 435 22 124 5.54 1.72
*See Peters and Moldowan (1993) for discussion of analytical procedures. Locations are shown in Table 1. Laboratories are denoted as follows: 1 = Petrobras; 2 =Houston Advanced Research Center; 3 = Humble; 4 = ExxonMobil Upstream Research; 5 = Core Laboratories. TOC = weight percent organic carbon; S1, S2 =milligrams of hydrocarbons/gram of rock; S3 = milligrams of carbon dioxide/gram of rock; T max = temperature (jC). HI = S2 � 100/TOC; OI = S3 � 100/TOC; PI =S1/(S1 + S2); S1/TOC = S1 � 100/TOC.
Table 2. Continued
Table 3) and a modified Van Krevelen plot (type I highly
liquid-prone field, Figure 4). Groups 2 and 3 are also
distinguishable by maturity differences. Although Tmax
values range from 421 to 437 in both groups, JL, CM,
and DZ samples (group 2) have higher PI values than
group 3 NU and SO samples (0.02–0.06 versus 0.01–
0.02, respectively), indicating slightly higher maturity
(early to peak oil window) in group 2. The lower Meso-
zoic samples are also distinguished by high pristane/
phytane ratios in the group 2 samples (Figure 6) relative
to all other source rocks, indicating higher maturity and/
or more oxic environments (Peters and Moldowan, 1993).
826 Geochemical Characteristics and Correlation of Oil and Nonmarine Source Rocks
Figure 3. Logged coresection showing three ZBcore source rock samples.Note that samples ZB-1933 and ZB-1978 arefrom microlaminatedmicrite units interpretedas anoxic deposits in astratified lake, versussample ZB-1740, which isinterpreted as part of abetter oxygenated system(either more marginalfacies or a nonstratifiedlake; Johnson, 2002).Core sample numbersrepresent depth in feetbelow kelly bushing (KB)(+4 m), converted tometers-depth in the corelog.
Permian coal from central Mongolia (group 4) is
a type I (Figure 4), highly liquid-prone source (TOC
generally 50–70%). Maturity indicated by Tmax (441–
463) and PI values (0.02–0.06) is in the peak oil window
range. By comparison, pre-Permian carbonate and shale
samples from central and northern Mongolia (group 5)
have low TOC values (0.58–1.68), show a wider range
of kerogen types (Figure 4) (types I–IV of Tissot et al.,
1974; Demaison et al., 1983), and are also likely mature
(Tmax 429–441), although PI values are low.
This survey of bulk geochemical data indicates
several additional prospective source rock groups in
Mongolia, including several pre-Cretaceous units that
could source undiscovered hydrocarbon accumula-
tions. Lower Cretaceous organic-rich shale is widely
distributed in and around the East Gobi basin both in
outcrop and in the subsurface, whereas older (Paleozoic–
lower Mesozoic) source facies are mainly limited to
central and western Mongolia (Figure 1; Graham et
al., 2001). One exception is the Lower to Middle
Jurassic Khamarkhavoor Formation, which crops out
only rarely in the East Gobi basin and may be anal-
ogous to lower Mesozoic lacustrine oil shale from
Noyon Uul in southwestern Mongolia (Table 5, group
3) (Hendrix et al., 1997; Graham et al., 2001). The
Khamarkhavoor Formation was not sampled in this
study, but it may constitute a prerift source (Figure 2).
Lower Cretaceous source rocks of group 1 (Table 5)
are generally interpreted as the main source of oil in
the East Gobi basin (Yamamoto et al., 1993, 1998;
Traynor and Sladen, 1995; Sladen and Traynor, 2000).
Detailed biomarker analyses of select oil and source
rock samples completed in the second part of this study
confirm and further characterize this inferred correlation.
OIL GEOCHEMISTRY
Six Mongolian oil samples (including extracts from
the ZB tar sand) were analyzed for bulk and molecular
organic geochemistry. The Mongolian samples are from
the Tsagan Els (TE samples) and Zuunbayan (ZB sam-
ples) fields, which are located on separate structures
(about 25 km apart) in the Zuunbayan subbasin in
southeastern Mongolia (Figure 1, inset). Like most
nonmarine, Mesozoic-sourced oil in the region, oil
samples from the East Gobi basin tend to be waxy
(�20–30% paraffinic), having high pour points
(10–30jC; Table 6; Chen et al., 1994; Traynor and
Sladen, 1995; Dou et al., 1998; A. Hall, 2000, personal
communication). Two oil samples from lacustrine-
sourced Early Cretaceous basins in China (Erlian and
Johnson et al. 827
Figure 4. HI versus OI (modified VanKrevelen) plot indicating hydrocarbon-generative types of source rocks (Peters,1986). Type I = highly oil prone, type II =oil prone, type III = gas prone. See Table2 for data.
828 Geochemical Characteristics and Correlation of Oil and Nonmarine Source Rocks
Tab
le3
.Vi
sual
Ker
ogen
Sum
mar
yw
ith%
Org
anic
Con
stitu
ents
Sam
ple
Age
Am
orph
ous
Type
3
(Fin
ely
Dis
sem
inat
ed)
Trile
teSp
ores
and/
orPo
llen
Plan
tTi
ssue
-
Mem
bran
ous
Deb
ris
Fung
al
Deb
ris
Vitr
inite
(Ang
ular
-Str
uctu
red)
Iner
tinite
(Inc
lude
sPy
rite
)A
vera
ge%
Ro
92-U
B-4
Low
erC
reta
ceou
s8
6231
0.39
92-U
B-10
Low
erC
reta
ceou
s8
867
170.
36
92-U
B-12
Low
erC
reta
ceou
s8
6231
0.35
92-U
B-15
Low
erC
reta
ceou
s33
633
617
60.
37
92-J
L-6
Low
erto
Mid
dle
Jura
ssic
1080
100.
41
92-J
L-9
Low
erto
Mid
dle
Jura
ssic
973
180.
43
92-C
M-3
Low
erto
Mid
dle
Jura
ssic
77
5729
0.77
92-C
M-1
0Lo
wer
toM
iddl
eJu
rass
ic7
757
290.
76
92-C
M-1
2Lo
wer
toM
iddl
eJu
rass
ic8
867
170.
62
92-C
M-1
7Lo
wer
toM
iddl
eJu
rass
ic6
650
380.
74
92-C
M-2
0Lo
wer
toM
iddl
eJu
rass
ic7
5340
0.72
92-C
M-2
2Lo
wer
toM
iddl
eJu
rass
ic42
1121
215
0.79
92-D
Z-2
Low
erto
Mid
dle
Jura
ssic
633
4712
0.93
92-D
Z-6
Low
erto
Mid
dle
Jura
ssic
862
310.
65
92-N
U-4
8bTr
iass
ic–
Jura
ssic
8911
0.86
92-N
U-4
9Tr
iass
ic–
Jura
ssic
8010
100.
65
92-N
U-5
0Tr
iass
ic–
Jura
ssic
973
99
0.93
92-N
U-5
1Tr
iass
ic–
Jura
ssic
678
817
0.69
92-N
U-5
2Tr
iass
ic–
Jura
ssic
8010
100.
78
92-S
J-36
aD
evon
ian
–C
arbo
nife
rous
5714
295.
11
Daqing/Songliao) were included in the GCMS analyses
for comparison (Figure 1). The Erlian basin sample is
from the Saihantala sag, and the Daqing sample is from
the Yushuling oil field (Table 1). Both oils are believed
to have originated from Lower Cretaceous lacustrine
units analogous to those in the East Gobi basin (Yang
et al., 1985; Dou et al., 1998).
Petroleum Source Facies Indicators
All oil samples show similar GC patterns, with the
presence of high-molecular-weight n-alkanes indicating
algal or higher plant input (Peters and Moldowan, 1993),
although the n-alkanes drop off in abundance after nC23
(Figures 7, 8). Whole oil d13C (versus PDB [Peedee
Johnson et al. 829
Table 4. Ratios from Pyrolysis-GC Analyses for Selected Source Rock and Oil Samples*
Sample CPI (1) CPI (2) Pr/Ph Pr/nC17 Ph/nC18
nC17
Anomaly
Presence of
b-carotane?
Lower Cretaceous core samples ZB-1978 1.75 2.07 0.96 0.58 0.71 1.11 y?
ZB-1740 2.07 2.23 0.54 0.59 1.36 1.01 n
ZB-1933 1.18 1.22 0.87 0.34 0.40 1.03 y?
Other Lower Cretaceous samples 97-SH-4 1.18 1.70 0.89 1.31 0.62 0.69 y?
97-SH-9 1.38 2.08 0.25 0.83 8.94 2.42 y
97-SH-13 1.95 2.06 0.16 1.30 11.50 1.42 y?
97-TH-316 3.11 4.11 0.29 0.40 0.92 1.18 y
92-UB-4 2.82 2.64 1.96 1.88 0.76 0.95 y
92-UB-10 3.73 3.56 1.25 1.36 0.95 1.08 n
92-UB-12 4.93 4.55 1.99 3.89 1.19 0.84 n
92-UB-15 4.89 4.11 0.51 0.49 1.23 1.33 n
Jurassic samples 92-JL-9 1.38 1.70 3.00 1.03 0.22 0.96 n
92-CM-3 1.41 1.40 10.29 7.22 0.61 1.02 n
92-CM-10 1.40 1.29 9.97 3.63 0.31 1.01 n
92-CM-12 1.44 1.30 9.38 4.26 0.36 0.98 n
92-CM-17 1.43 1.23 8.88 2.57 0.25 1.00 n
92-CM-20 1.36 1.09 7.86 1.58 0.18 1.03 n
92-CM-22 1.30 1.45 4.25 1.27 0.30 1.07 n
92-DZ-2 1.07 1.17 4.65 2.26 0.39 0.93 n
92-DZ-6 1.30 0.75 7.43 0.67 0.07 1.01 n
Triassic–Lower Jurassic samples 92-NU-48B 1.29 1.65 1.36 0.54 0.35 0.99 y
92-NU-49 1.59 2.56 0.74 0.51 0.59 0.93 y
92-NU-50 1.46 2.83 0.97 0.40 0.43 1.06 y
92-NU-51 1.24 1.75 0.85 1.04 0.97 1.01 y
92-NU-52 1.10 1.01 0.80 0.47 0.55 1.01 y
Oil samples ZB-310b 1.11 1.15 1.10 0.19 0.16 1.03 y
ZB oil 163251A 1.20 1.25 0.86 0.43 0.48 1.04 y
ZB tar 163251B 1.13 1.18 1.03 0.46 0.44 1.03 y
TE-25 1.11 1.07 1.17 0.16 0.13 0.98 y
TE-A1 1.11 1.15 1.10 0.19 0.16 1.03 y
TE-A2 1.09 1.05 1.11 0.17 0.16 1.09 y
ER-1846 1.18 1.20 0.79 0.32 0.43 1.05 n
DQ-2198 1.10 1.09 1.15 0.27 0.25 1.04 n
*Ratio Calculation SourceCPI(1) [(nC(25 + 27 + 29 + 31 + 33))/(nC(26 + 28 + 30 + 32 + 34)) +
(nC(25 + 27 + 29 + 31 + 33))/(nC(24 + 26 + 28 + 30 + 32))]/2 Bray and Evans (1961)CPI (2) [2nC29/(nC28 + nC30)] Bray and Evans (1961)nC17 anomaly [2nC17/(nC16 + nC18)] Yamamoto et al. (1998)b-Carotane identification based on GC data only (see Appendix for GCMS results)
belemnite]) isotope measurements of three oil samples
from the two Mongolian fields yield similar ratios near
�31x(Table 7), suggesting that a similar source rock
for each of the Mongolian oil groups. Recycling of 13C-
depleted carbon by organisms living in stratified lakes
may cause these unusually negative values (Scholl et al.,
1994). Distinctions between the oil groups are indicated
by differences in pristane/phytane ratios,which are slightly
greater than 1 (1.1–1.7) for the Tsagan Els and Daqing oil
samples and slightly lower (0.8–1.1) for the Zuunbayan
and Erlian oil samples (Table 4). Oil from the Zuun-
bayan field also tends to be less waxy, having a lower
pour point than those at Tsagan Els (Table 6), suggesting
some variation in facies and/or maturity of source rocks.
Conventional biomarker ratios (Appendix) are
consistent with GC data, which suggest similar lacus-
trine source rock facies for the Mongolian oil accu-
mulations. Prokaryote-derived hopanes are the most
abundant biomarker group and are detected as major
peaks even on sterane transitions (Figure 9), whereas
830 Geochemical Characteristics and Correlation of Oil and Nonmarine Source Rocks
Figure 5. Example gaschromatograms for ex-tracted whole-rock sam-ples ZB-1978 (a: Zuunba-yan core) and 92-NU-48b(b: Noyon Uul) showingtypical fingerprints forMesozoic source rocksanalyzed in this study.
Johnson et al. 831
Tab
le5
.C
hara
cter
istic
sof
Sour
ceRo
ckG
roup
sof
Mon
golia
Gro
upA
geLo
catio
nLi
thol
ogy
Cha
ract
eris
tics
1Lo
wer
Cre
tace
ous
East
Gob
iba
sin,
Ula
anBa
taar
basi
n,
Nilg
aba
sin
(ZB,
UB,
SH,
TH,
NL
sam
ples
)
Coa
lan
dla
cust
rine
mud
ston
eTO
Cva
lues
1.5
–30
%fo
rm
udst
one
and
oil
shal
e;>
45%
for
coal
-ric
hsa
mpl
es
Vari
able
kero
gen
type
:m
ainl
yty
peI–
IIke
roge
n
(oil
pron
eto
high
lyoi
lpr
one)
;U
Bsa
mpl
esar
e
near
type
IIIan
dsh
owpr
edom
inan
ce
ofvi
trin
itean
din
ertin
ite(g
aspr
one)
CPI
(1)
vari
able
(1–
5);
high
est
inTH
/UB
sam
ples
Pr/P
hra
tios
0.25
–1.
99
Imm
atur
eto
earl
yoi
lw
indo
w
2Lo
wer
toM
iddl
eJu
rass
icW
este
rnan
dce
ntra
lM
ongo
liaC
oal
and
coal
ym
udst
one
Type
III–
IVke
roge
n(g
aspr
one
toin
ert)
(JL,
CM
,D
Zsa
mpl
es)
Pred
omin
ance
ofvi
trin
itean
din
ertin
ite
CPI
(1)
valu
es1.
0–
1.44
Hig
hPr
/Ph
ratio
s(3
–10
)
Earl
yoi
lw
indo
wto
peak
oil
win
dow
3Tr
iass
ic–
Jura
ssic
Cen
tral
and
sout
hwes
tern
Mon
golia
Lacu
stri
nem
udst
one
Type
Ike
roge
n(o
ilpr
one)
(NU
,SO
sam
ples
)Pr
edom
inan
ceof
liptin
ite(a
lgal
,w
axy
plan
tde
bris
)
CPI
(1)
valu
es1.
3–
1.6
Pr/P
hra
tios�
1(0
.75
–1.
36)
Earl
yoi
lw
indo
w
4Pe
rmia
nC
entr
alM
ongo
lia(T
Tsa
mpl
es)
Coa
lTy
peI
kero
gen
(oil
pron
e)
GC
data
n/a
Peak
oil
win
dow
5C
arbo
nife
rous
;
Riph
ean
–C
ambr
ian
Nor
ther
nan
dw
este
rnM
ongo
lia
(SG
,M
O,
WH
sam
ples
)
Car
bona
teK
erog
enty
peva
riab
le
(I–
IV;
oil
toga
spr
one
plus
iner
t)
GC
data
n/a
Mat
ure
toov
erm
atur
e(g
asw
indo
wto
nong
ener
ativ
e)
C30 24-n-propylcholestanes are absent, consistent with
a nonmarine source (Moldowan et al., 1990). Indicators of
salinity and/or water column stratification in the source
facies include the presence of b-carotane, g-carotane, and
gammacerane (Figure 9; Appendix) (Fu et al., 1990),
which are notably higher in the Zuunbayan oil than the
Tsagan Els oil.
Several biomarker parameters suggest significant
algal input to the source rock depositional environ-
ment. Ternary plots of C27, C28, and C29 regular ste-
ranes and monoaromatic steroids (Figure 10) suggest a
similar lacustrine source with algal input in Tsagan Els,
Zuunbayan, and Erlian samples (the Daqing oil plots
slightly out of this field with even higher C27 sterane
and steroids; Moldowan et al., 1985; Peters and Mol-
dowan, 1993) (Figure 10). The C26 steranes (24-
norcholestanes) and related C26 diasteranes (24-
nordiacholestanes) are likely derived from diatom
precursors (Moldowan et al., 1991; Holba et al., 1998a).
Their ratios to the nontaxa-specific C26 steranes, 27-
norcholestanes and 27-nordiacholestanes (NCR and
NDR, respectively; Holba et al., 1998a; Appendix),
are in the low range of values expected for Lower Cre-
taceous, nonmarine-sourced oil and contrast with
the higher values common in Tertiary nonmarine oil
(e.g., Holba et al., 1998b, Ritts et al., 1999). Although
C30 4-methyl steranes occur in both freshwater lacus-
trine and marine sediments, the presence of elevated
832 Geochemical Characteristics and Correlation of Oil and Nonmarine Source Rocks
Table 6. Characteristics of Oil Samples from Cretaceous-Sourced Lacustrine Basins in China and Mongolia*
Sample Locations jAPI Density (g/cm3) Viscosity at Surface (cp) Paraffin Analysis Pour Point (jC)
Tsagan Els field, East Gobi basin �30 0.872–0.878 4.7–38 average = 35.1% 36–38
Zuunbayan field, East Gobi basin �30 0.848–0.917 4.8–130 average = 20.5% 12.3–21
Jirgalangtu depression, Erlian basin n/a 0.8468–0.942 n/a 13.25% 28
Saertu pool, Daqing, Songliao basin n/a n/a 12.0–99 21–29% 22–34
*Tsagan Els and Zuunbayan (TE and ZB) data are from several samples reported in Shirokov and Kopytchenko (1983), in addition to previously unpublished industrydata (A. Hall, 2001, personal communication). Erlian basin oil data are from two oil samples described by Dou et al. (1998) in the Jirgalangtu depression. Daqingdata is from Saertu pool samples reported by Yang (1985).
Figure 6. Crossplotof pristine/phytane ratioversus carbon preferenceindex (CPI-1, see Table 4for calculation of this pa-rameter). Ellipses showgeneral source rockgroupings discussed inthe text. K1 = Lower Cre-taceous; Tr–J = Triassic–Jurassic. See Table 1 forsample location and in-formation.
4a-methyl-24-ethylcholestane suggests a strong affilia-
tion with lacustrine sediments (Murray et al., 1994). We
also note the high relative abundance of C30 dinosteranes
(4a,23,24-trimethylcholestanes) and triaromatic dino-
steroids, which is additional evidence for dinoflagellate-
algae contribution in the source facies (Figure 11a, b)
(Moldowan et al., 1996; 2001).
Zuunbayan and Tsagan Els oil samples also contain
C30 tetracyclic polyprenoids (TPP), which were recog-
nized by Holba et al. (2000) as indicators of algal-rich,
Johnson et al. 833
Figure 7. Gas chroma-tographs for whole-oilsamples ZB-310b (a) andTE-A1 (b), showing simi-lar fingerprints with high-er pristine/phytane valuesrelative to nC17 for theZuunbayan (ZB) oil.
fresh- to brackish-water lacustrine environments. The
TPP ratio (Holba et al., 2000), allied with other bio-
marker parameters, differentiates oil and source rocks
from lacustrine, marine, and mixed depositional envi-
ronments. Green algae commonly found in freshwater
environments are presumed to be the dominant source
of TPP (Holba et al., 2000). The Zuunbayan and Tsa-
gan Els oil samples plot in the Lacustrine I field, char-
acteristic of Cretaceous or younger, algal-lacustrine-
sourced oil (Figure 11c).
Although both groups of Mongolian oil (TE and ZB)
overlap on regular and aromatic steroid ternary plots,
certain parameters suggest derivation from slightly dif-
ferent source facies. The main difference in the two oil
groups appears to be varying amounts of algal-derived
biomarker indicators. In addition, the Zuunbayan sam-
ples have lower pristane/phytane ratios and lower
n-alkane concentrations than the Tsagan Els samples.
The Tsagan Els oil also contains lower but detectable
amounts of b-carotane, gammacerane, triaromatic dino-
steroids, and C30 dinosteranes (Appendix; Figure 11).
Tricyclic and tetracyclic terpane ratios, commonly used as
correlation parameters (Peters and Moldowan, 1993),
also indicate distinct oil groups between the two fields
(Figure 12). Thus, the lacustrine-sourced Mongolian
oil samples show subtle source-facies variations, with
greater algal and dinoflagellate input into the Zuunba-
yan oil source. These variations could reflect different
lacustrine source intervals with varying degrees of algal
input or lateral facies changes from offshore to mar-
ginal lacustrine environments.
Hexacyclic and Heptacyclic Polyprenoids
All of the Mongolian oil samples contain elevated con-
centrations of unusual hexacyclic and heptacyclic al-
kanes. These compounds are most abundant in the TE
834 Geochemical Characteristics and Correlation of Oil and Nonmarine Source Rocks
Figure 8. Plot comparing normalized n-alkane distribution for Mongolian and Chinese oil samples showing similar patterns, withthe presence of high-molecular weight n-alkanes indicating algal or higher plant input (Peters and Moldowan, 1993).
Table 7. Stable 13C Isotope Values for Select Oil and Source
Rock Samples
Sample Number d13C versus PDB (x)
Oil SamplesTEA-1 oil �30.70
TE-25 �30.56
SWZB-310b oil �31.21
Source Rock SamplesZB-1933 �30.96
ZB-1740 �31.19
ZB-1978 �30.61
97-SH-4 �26.25
98-TH-316 �29.69
oil, where they form some of the largest peaks on the m/z217 and TIC (total ion count) chromatograms in saturate
fractions with n-alkanes removed (branched and cyclic
fractions, Figure 9). Mass spectra from full-scan GCMS
confirms that these are six- and seven-ring (as much as
40-carbon) polyprenoids (Figure 13). These compounds
have been observed in only a few previous studies, in-
cluding the ostracod zone of the Western Canada sedi-
mentary basin (Li et al., 1996) and the Aquitaine basin of
France and northern Spain (Grosjean et al., 2000).
Cyclized polyaromatic polyprenoids presumed to be
related to these saturated compounds are also found in
aromatic fractions of the Eocene Messel shale in Ger-
many (Poinsot et al., 1995) and in western Canada (Li
et al., 1997). Although little is known about the global
occurrence of polyprenoids (Grosjean et al., 2000, 2001),
their abundance in these basins and association with
abundant four-ringed polyprenoids (TPP) appear to in-
dicate fresh- to brackish-water lacustrine source rock
environments. Interestingly, source facies in the East
Gobi, Western Canada, and Aquitaine basins are mainly
Early Cretaceous or younger, suggesting the possibility of
an age-sensitive biomarker. Li et al. (1996) reported at
least three isotopically distinct groups based on d13C
ratios of tri-, tetra-, and pentacyclic alkanes in extracts
from western Canada, suggesting derivation from dif-
ferent groups of organisms or different biosynthetic path-
ways in a single group.
Grosjean et al. (2000, 2001) offered preliminary
structural analysis of some of these isolated com-
pounds, which also occur in the East Gobi oil (Figure
13). Further isolation, structural characterization, and
confirmation of these six- to seven-ring polyprenoids
will help to elucidate their usefulness as source rock
environmental indicators (work is in progress in col-
laboration with P. Albrecht et al., L’Universite Louis
Pasteur, Strasbourg). Although their biological precur-
sor is unknown, these compounds represent a highly
specific correlation tool that may represent a new class
of biolipids (Grosjean et al, 2000, 2001). The six- to
seven-ring polyprenoid compounds have very late elu-
tion times (Figures 9, 13), which may be undetected
by some GCMS and MRM-GCMS time-temperature
protocols not optimized for their detection. Our pre-
liminary analyses of two oil samples from the Erlian
and Songliao basins did not reveal these compounds,
but further organic geochemical studies of other Early
Cretaceous lacustrine basins in the China–Mongolia
border zone specifically targeted toward these poly-
cyclic polyprenoids may reveal additional information
about their distribution, origin, and chemical structure.
Maturity Indicators
Biomarker parameters also suggest differences in matu-
rity between the Zuunbayan and Tsagan Els oil samples.
Several sterane and terpane isomerization parameters
(including C29 sterane aaa20S/20R, C31 homohopane
(S/R), Ts/Tm, and moretane indices) consistently in-
dicate that TE oil is more mature than the ZB oil (Fig-
ure 14). Likewise, the Erlian and Daqing samples ap-
pear to originate from more mature source rocks than
the Zuunbayan oil, with Erlian showing similar group-
ings to the Tsagan Els samples and Daqing generally
plotting on its own. These differences suggest at least
two oil-generating source rock maturities, reflecting
either different source rock intervals or two periods of
oil generation. The Zuunbayan field lies adjacent to a
major strike-slip fault active since at least the Late
Cretaceous, whereas the Tsagan Els field occupies a
midbasin position several kilometers away from this
fault. Thus, higher maturity in the Tsagan Els oil could
be the result of deeper burial away from this structure.
Alternatively, as discussed previously, the differences
in both maturity and facies parameters between Zuun-
bayan and Tsagan Els oil groups suggest that they could
originate from different lacustrine intervals with sepa-
rate thermal histories.
OIL – SOURCE ROCK CORRELATION
Biomarker analyses were completed to facilitate oil–
source rock correlation of selected source rocks from
the East Gobi region (SH, TH, and ZB samples; Figure
1). Lower Cretaceous samples were selected as the main
focus of this study based on their widespread distribu-
tion in the East Gobi basin, bulk geochemical param-
eters indicating a possible oil-source correlation (Figure
4; Table 5), and previous work (Yang et al., 1985; Ya-
mamoto et al., 1993; 1998; Traynor and Sladen, 1995;
Dou et al., 1998; Sladen and Traynor, 2000) suggesting
that synrift lacustrine facies are the main source units
in late Mesozoic basins of China and Mongolia.
SH and TH samples are too immature (e.g., Figure
14b) for meaningful correlation tests using most bio-
marker parameters. However, SH samples are unlikely
to be related to the Mongolian oils because of their
significantly less negative d13C isotope values (Table 7).
Pyrolysis experiments were attempted to model be-
havior of these rocks at increased maturity, but these
failed to produce a convincing correlation. Based on
d13C isotope ratios, samples from the Zuunbayan core
Johnson et al. 835
(Table 7) provided a much more convincing link with
the Zuunbayan and Tsagan Els oil groups.
Two of the three Zuunbayan core samples (ZB-1740,
1978) are relatively immature (Figure 14), whereas sam-
ple ZB-1933 consistently plots close to the Zuunbayan oil
using a variety of independent sterane and terpane isom-
erization ratios (Figure 14; Appendix, ratios B, C, D, G,
O, and P). Because sample ZB-1933 is bracketed by the
other two samples in depth (Table 2), it is not expected
to have an anomalously high maturity level. Sample
Johnson et al. 837
Figure 10. Ternary plots of regularsteranes and monoaromatic steroids forMongolian oil and selected source rocks.(a) Percentages of C27-C28-C29 aaa20Rsteranes measured by GCMS analysis ofm/z 217 peak heights of the saturatefraction. (b) Percentage of monoaromaticsteroids calculated by measuring peakheights of all six isomeric compounds ofC27, C28, and C29 MA steroids on GCMSm/z 253 analyses of the aromatic fraction(as described in Peters and Moldowan,1993). Note tight grouping of oil sampleson both diagrams, with more scatteramong the Chinese oils and Mongoliansource rocks. See Appendix for data.
Figure 9. Example GCMS mass chromatograms for oil samples ZB-310b and TE-A2, showing m/z 217, 191, and TIC. All graphs shown atsame time interval (60–100 min). Note predominance of late-eluting peaks (polyprenoids), particularly in the TE (Tsagan Els) sample. Dots onm/z 217 graphs denote regular sterane isomers identified as peak numbers 6–17 (from left to right) by Peters and Moldowan (1993, p. 85).
838 Geochemical Characteristics and Correlation of Oil and Nonmarine Source Rocks
Figure 11. (a, b) Dinosterane anddinosteroid index crossplots show-ing distinct groups of TE versus ZBoil samples (see Appendix for ratiocalculations). Note that ZB-1740core sample plots closer to theTE oils, implying less algal inputcompared to the ZB oils and othercore samples. (c) Crossplot of tet-racyclic polyprenoid ratio (TPP ofHolba et al., 2000) versus biomar-ker indicators for nonmarine dino-flagellate algae (20R-4amethyl/20R-24ethyl index), showing fields ofHolba et al. (2000). The Mongolianoil and core source rock sampleshave similarly high TPP ratios, andplot in the Lacustrine I field charac-teristic of oils derived from Creta-ceous or younger, algal-rich sourcerocks (Holba et al., 2000). SeeAppendix for ratio calculations.
ZB-1933 also has a lower Tmax value (indicating more
labile carbon), twice %TOC, and much larger S1, S2, and
production index values compared to the other two ZB
core samples (Table 2). We interpret this as evidence
for minor contamination by oil migration in this sample.
Two samples from the laminated mudstone facies
of the Zuunbayan core (ZB-1978 and ZB-1933) contain
higher biomarker ratios reflecting dinosterol derivatives
and indicate more dinoflagellate input relative to sam-
ple ZB-1740 (Figure 11a, b). Tsagan Els oil samples plot
closer to the ZB-1740 core sample as well, suggesting a
possible correlation between the TE oil and facies with
less algal input. Based on tetracyclic polyprenoid ratios
versus an algal-terrigenous sterane ratio, both oil groups
and the ZB core samples plot together in the ‘‘Lacus-
trine I’’ field, which is characteristic of algal-rich, Cre-
taceous or younger samples (Figure 11c, Holba et al.,
2000). Perhaps the best evidence for rock-oil correla-
tion between the Zuunbayan lacustrine core facies and
the Tsagan Els/Zuunbayan oil groups is the presence
of unusual six- and seven-ring polycyclic polyprenoid
compounds in both core and oil samples. The cyclized
alkanes were not found in any other source rock samples
and likely represent a highly specific correlation tool.
CONCLUSIONS
Outcrop samples from Mongolia reveal numerous high-
quality potential source rocks ranging from Paleozoic to
Mesozoic in age. The extent to which pre-Cretaceous
rocks may source unrecognized petroleum systems in
central and western Mongolia is poorly understood.
Our data indicate that currently exploited hydrocarbon
accumulations in the East Gobi basin most likely orig-
inated from Lower Cretaceous lacustrine facies, as re-
ported for neighboring basins in China (Yang, 1985;
Dou, 1997). Stratigraphic evidence indicates long-
lived lacustrine systems throughout the rifting phase
(more than 30 m.y.) in the China–Mongolia border
region (Lin et al., 2001; Sladen and Traynor, 2000).
Based on core samples from the Zuunbayan field, these
lakes contained fresh- to brackish-water bodies that re-
peatedly expanded and contracted during rifting (Gra-
ham et al., 2001). Lake margin shifts may also have
been linked to periods of thermal stratification and an-
oxic lake-bottom conditions alternating with periods of
better oxygenation and mixing of the water column,
which could account for source facies variation indi-
cated by geochemical parameters discussed in this study.
Bulk geochemistry, isotope, and biomarker data for
oil from the East Gobi basin support the link to Lower
Cretaceous lacustrine source facies. The oil samples show
a predominance of hopanes over steranes. In addition,
terpane and sterane parameters (including a lack of C30
4-desmethyl steranes and lower abundances of C28
[relative to C27 and C29] regular steranes and mono-
aromatic steroids) suggest a link to a terrigenous source.
Hypersaline indicators, suchashighgammacerane/hopane
and C34 or C35 homohopane/hopane ratios, are not pres-
ent. Dinoflagellate-derived dinosteroid and aromatic dino-
steroid parameters also point to significant algal influence,
Johnson et al. 839
Figure 12. Crossplotof tricyclic and tetracyclicterpane parametersshowing distinct groupsof TE versus ZB oil, withZB core samples plottingin between. Note outlyingSH and TH samples sug-gesting poor correlationwith TE and ZB samples.
as well as bacteria-derived hopanes and minor higher
plant input. In addition to standard biomarker param-
eters, oil and source rocks from the East Gobi basin
contain unusually high concentrations of six- and seven-
ring cyclized alkanes. These polyprenoid compounds oc-
cur in only a few nonmarine basins worldwide, where
they are thought to indicate fresh- to brackish-water la-
custrine deposition (Li et al., 1996; Grosjean et al., 2000).
840 Geochemical Characteristics and Correlation of Oil and Nonmarine Source Rocks
Figure 13. (a) Mass chromatogram from GCMS-MSscan run of polyprenoid compounds of oil sample TE-A1.Regular polyprenoids (no demethylation on ring system)are signified by two numbers: the number of carbonatoms/number of rings (e.g., 34/6 = 34 carbons, 6 rings).Structures missing methyl groups on their ring systemare additionally signified by a ‘‘�.’’ (b, c) Mass spectra forpeaks 1 and 2 (labeled in [a], respectively), showingmolecular ions of each peak. Structures were identifiedby Grosjean et al. (2000), for the same compounds in anoil sample from Spain.
Although the oil samples we analyzed appear to
originate from a similar nonmarine source rock type, they
form two distinct groups based on both maturity and
source parameters. Oil from the Zuunbayan field has
higher concentrations of b-carotane and dinoflagellate-
derived dinosteranes, indicating more algal input to
its source facies compared to that from Tsagan Els oil.
Tsagan Els oil correlates well with ZB-1740, a core
sample thought to have formed in more oxygenated
water conditions than the laminated micrite (ZB-1933
and ZB-1978), which correlate well with the Zuunba-
yan oil. Thus, subtle facies differences resulting from
different water chemistry resulted in distinct oil groups
as defined by biomarker parameters. These facies dis-
tinctions may reflect separate source units, or lateral
facies variations in a single source unit.
Tsagan Els oil was generated at higher maturity than
the Zuunbayan oil, as indicated by sterane and hopane
isomerization parameters. Burial history in the East Gobi
subbasins is obscured by activity along the Zuunbayan
fault, a major basin-partitioning strike-slip fault which
is nonetheless poorly constrained in terms of timing and
magnitude of offset (Graham et al., 2001; Johnson, 2002).
Independent thermal histories between the Zuunba-
yan and Tsagan Els fields may result from differential
burial of a given source unit along this fault (including
lateral facies transitions), or could reflect entirely unique
source units having similar geochemical signatures.
Johnson et al. 841
Figure 14. Biomarker param-eter crossplots highlightingmaturity differences and oilgroupings. See Appendix forratio calculations. (a) Crossplotof C29 isomerization ratiosshowing increasing maturityfrom ZB core samples, to ZB oil,to TE oil and the Chinese oil.(b) Crossplot of terpane matu-rity parameters indicating dis-tinct oil and source rock groups.Note that one of the ZB coresamples (ZB-1933), plottingclosest to the ZB oil, is unusuallymature compared to the othercore samples and is likely con-taminated by migrated oil.
842 Geochemical Characteristics and Correlation of Oil and Nonmarine Source Rocks
TERPANES Sample Number A B C D E F G H I J K
Oil Samples TE-A-1 0.02 0.63 0.05 0.05 0.18 0.34 0.47 0.16 0.14 Y YTE-A-2 0.02 0.64 0.05 0.05 0.24 0.36 0.45 0.12 0.13 Y YTE-25 0.02 0.63 0.05 0.04 0.20 0.34 0.53 0.19 0.09 Y Y
ZB-310b 0.04 0.57 0.11 0.13 0.08 0.63 0.33 0.11 0.23 Y Y93-ZB-101 0.09 0.62 0.10 0.11 0.10 0.75 0.29 0.05 0.36 n/a Y93-ZB-103 0.08 0.64 0.10 0.12 0.02 0.76 0.30 0.07 0.29 n/a Y93-ZB-204 0.08 0.66 0.10 0.11 0.05 0.78 0.32 0.03 0.46 n/a Y
ER-1848 0.01 0.59 0.05 0.05 0.17 0.40 0.59 0.02 0.34 Y NDQ-2198 0.19 0.33 0.06 0.04 0.14 0.54 0.79 0.36 0.21 Y N
Source Rock Samples 97-SH-4 0.07 0.11 0.14 0.65 0.06 0.81 0.07 0.06 0.06 Y N97-SH-9 0.08 0.09 0.72 0.72 0.15 0.87 0.04 0.24 0.03 Y N97-SH-13 n/a n/a n/a n/a 0.26 0.86 n/a 1.00 0.06 N N97-TH-316 0.14 0.09 0.64 0.70 0.27 0.37 0.04 0.05 0.61 N N
ZB-1740 0.00 0.33 0.11 0.32 0.28 0.53 0.02 0.01 0.36 N NZB-1933 0.04 0.51 0.10 0.14 0.14 0.48 0.32 0.21 0.17 Y NZB-1978 0.00 0.29 0.15 0.28 0.27 0.54 0.15 0.02 0.28 Y N
STERANES Sample Number L M N O P Q R S T U V
Oil Samples TE-A-1 28.44 22.00 49.56 0.46 0.44 0.57 0.21 0.12 0.19 0.85 0.85TE-A-2 27.53 22.35 50.12 0.45 0.45 0.57 0.21 n/a n/a n/a n/aTE-25 30.09 26.23 43.67 0.50 0.51 0.54 0.16 n/a n/a n/a n/a
ZB-310b 34.50 24.53 40.97 0.27 0.21 0.84 0.54 0.15 0.17 0.75 0.8093-ZB-101 27.08 21.68 51.24 0.31 0.23 n/a n/a n/a n/a n/a n/a93-ZB-103 28.92 22.36 48.72 0.33 0.24 n/a n/a n/a n/a n/a n/a93-ZB-204 27.85 22.20 49.95 0.35 0.26 n/a n/a n/a n/a n/a n/a
ER-1848 34.25 14.86 50.89 0.48 0.46 n/a n/a n/a n/a n/a n/aDQ-2198 52.18 15.67 32.15 0.57 0.64 n/a n/a n/a n/a n/a n/a
Source Rock Samples 97-SH-4 17.98 23.47 58.55 0.05 0.00 0.68 0.21 n/a n/a n/a n/a97-SH-9 38.45 25.38 36.17 0.04 0.00 0.50 0.08 n/a n/a n/a n/a97-SH-13 36.85 9.75 53.41 0.00 0.00 0.00 n/a n/a n/a n/a n/a97-TH-316 60.27 13.28 26.45 0.01 0.00 0.86 0.31 n/a n/a n/a n/a
ZB-1740 32.77 13.90 53.33 0.00 0.18 0.69 0.33 0.19 0.14 0.89 0.69ZB-1933 36.30 21.71 41.99 0.24 0.20 0.88 0.60 0.12 0.13 0.72 0.77ZB-1978 32.63 12.73 54.64 0.03 0.14 0.88 0.47 0.08 0.08 0.79 0.49
AROMATICS Sample Number W X Y Z AA AB AC AD
Oil Samples TE-A-1 0.88 0.79 0.48 0.64 0.42 31.67 24.56 43.77TE-A-2 0.87 0.75 0.45 0.64 0.31 31.31 25.33 43.36TE-25 0.85 0.75 0.43 0.59 0.32 31.55 26.62 41.84
ZB-310b 0.97 0.94 0.76 0.89 0.67 29.07 24.28 46.65
ER-1848 0.93 0.87 0.59 0.80 0.54 28.20 25.66 46.14DQ-2198 0.84 0.93 0.55 0.51 0.68 39.87 30.44 29.69
Source Rock Samples ZB-1740 0.87 0.83 0.33 0.63 0.38 27.68 30.85 41.47ZB-1933 0.96 0.94 0.53 0.91 0.73 26.48 23.86 49.67ZB-1978 0.97 0.98 0.77 0.86 0.90 29.99 29.25 40.76
APPENDIX: TABLE OF SELECT BIOMARKER RATIOS (SEE KEY FOR EXPLANATION)
Johnson et al. 843
Ratio Index Source of Data Calculation
TERPANESA Gammacerane index GCMS m/z 191 gammacerane
gammacerane þ C30 hopane
B C31 homohopaneisomerization index
GCMS m/z 191 C31 ab 22SC31 ab 22S þ C31 ab 22R homohopanes
C C29, C30 moretane index GCMS m/z 191 C29 þ C30 moretaneðC29 þ C30 moretaneÞ þ ðC29 þ C30 hopaneÞ
D C29, Moretane index GCMS m/z 191 C29 moretaneC29 moretane þ C29 hopane
E C19, C23 tricyclic index GCMS m/z 191 C19 tricyclicC19 þ C23 tricyclics
F C26, C25 tricyclic index GCMS m/z 191 C26 tricyclicC26 þ C25 tricyclics
G Ts/Tm index GCMS m/z 191 TsTs þ Tm
H C21 tricyclic versus C30
hopane indexGCMS m/z 191 C21 tricyclic
C21 tricyclic þ C30 hopane
I C24 tetracyclic versus C21
tricyclic indexGCMS m/z 191 C24 tetracyclic
C24 tetra þ C21 tricyclic
J Presence of b-carotane GCMS m/z 125 yes/noK Presence of oleanane GCMS m/z 191 yes/no
STERANESL % C27 steranes GCMS 217 100�C27 regular steranes
ðC27 þ C28 þ C29Þ regular steranes
M % C28 steranes GCMS 217 100�C28 regular steranesðC27 þ C28 þ C29Þ regular steranes
N % C29 steranes GCMS 217 100�C29 regular steranesðC27 þ C28 þ C29Þ regular steranes
O C29 20S/Rstereoisomerization ratio
GCMS 217 C29aaa 20S20S þ 20R
P C29 regular steranes abb/aaastereoisomerization ratio
GCMS 217 C29 abb ð20S þ 20RÞabb ð20S þ 20RÞ þ aaa ð20S þ 20RÞ
Q C30 dinosteranes vs 3b methyl(4methyl steranes)**
MRM GCMS 414 !231 transition SUMðD1 � D4 þ 4a-methylÞðSUMðD1 � 4 þ 4a-methyl þ 3b-methylÞdinosterane
R C30 dinosterane (4th dinosterane)vs 3b methyl
MRM GCMS 414 !231 transition D4 dinosteraneðD4 þ 3b-methylÞ
S Nordiacholestane ratio (NDR) MRM GCMS 358 !217 transitionpeak areasy
24 nordiacholestanes24 nor þ 27 nordiacholestanes
T Norcholestane ratio (NCR) MRM GCMS 358 !217 transitionpeak areasy
24 norcholestanes24 nor þ 27 norcholestanes
U C30 4a-methyl/C29 24ethyl-cholestane MRM GCMS 414 !217 transitionpeak areasyy
C29aaa 20R steraneC29aaa20R sterane þ 4a-methyl dinosterane
V Tetracyclic polyprenoid ratio MRM GCMS 414 !259 transition,peak areas+ sum 27-norcholestanesz
2 � C29 tetracyclic polyprenoid peak A2 � peak A þ C27 norcholestanes
AROMATICSW Triaromatic dinosteroid
vs 4a - methyl indexGCMS m/z 245 peak areas SUMðD1 � D6 dinosteroidsÞ
SUMðD1 � D6Þ þ 4SR
X Triaromatic dinosteroidvs 3b - methyl index
GCMS m/z 245 peak areas SUMðD1 � D6 dinosteroidsÞSUMðD1 � D6Þ þ 3SR
Y All triaromatic dinosteroids GCMS m/z 245 peak areas SUMðD1 � D6 dinosteroidsÞSUMðD1 � D6Þ þ all SR=CR
Z Sixth triaromatic dinosteroidsvs 4SR
GCMS m/z 245 peak areas D6 dinosteroids4SR þ D6
AA Fifth triaromatic dinosteroidsvs 4SR
GCMS m/z 245 peak areas D5 dinosteroids3SR þ D5
Key to Appendix*
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Ratio Index Source of data Calculation
AB %C27 monoaromatic steroidszz GCMS m/z 253(six isomers each)
100�C27 monoaromatic steroidsðC27 þ C28 þ C29 MA steroidsÞ
AC %C28 monoaromatic steroids GCMS m/z 253(six isomers each)
100�C28 monoaromatic steroidsðC27 þ C28 þ C29 MA steroidsÞ
AD %C29 monoaromatic steroids GCMS m/z 253(six isomers each)
100�C29 monoaromatic steroidsðC27 þ C28 þ C29 MA steroidsÞ
* Ratios from peak heights unless otherwise noted.** C30 4a-methyl sterane measurements include D3 (third dinosterane) peak.y see Holba et al., 1998a.yy see Holba et al., 2000.z Peters and Moldowan, 1993.zz Murray et al., 1994.
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