Directory UMM :Data Elmu:jurnal:O:Organic Geochemistry:Vol31.Issue12.Dec2000:
Organic Geochemistry 31 (2000) 1475±1493
www.elsevier.nl/locate/orggeochem
Brunei Darussalam
Characteristics of selected petroleums and source rocks
J. Curiale a,*, J. Morelos a,1, J. Lambiase b, W. Mueller c,2
a
Unocal Corporation, 14141 Southwest Freeway, Sugar Land, TX 77478, USA
Universiti Brunei Darussalam, Petroleum Geoscience, Bandar Seri Begawan BE1410, Negara, Brunei
c
Unocal Borneo Utara Ltd, Locked Bag #76, Bandar Seri Begawan BS8611, Negara, Brunei
b
Abstract
The development of three Tertiary deltaic complexes has resulted in the deposition of up to 10 km of sandstones and
shales comprising the sources and reservoirs for crude oils that occur onshore, near-oshore and, with future
exploration eorts, those likely to be encountered in deepwater reservoirs north of the Brunei coastline. We examined a
series of oshore oils and onshore rock samples in Brunei Darussalam (a) to delineate oil family groups and their
source rock characteristics, and (b) to assess the source potential of the sedimentary sequence with respect to lithology
and depositional setting. Twelve oshore oils and 53 shales, coaly shales and coals were examined. The oils contain
indicators of allochthonous (e.g. bicadinanes, oleananes) and autochthonous (e.g. cholestanes and methylcholestanes)
components in the source organic matter. Predictable geographic variations of this mixed input are clearly evident in
the sample set (e.g. allochthonous input appears to increase in oshore Brunei to the northeast). Although this molecular source signature is relatively clear, migration of these oils from deep (and unidenti®ed) source rocks has resulted
in extensive migration-contamination with respect to the tetracyclic and pentacyclic hydrocarbons. This contamination
has resulted in strong correlations between certain molecular maturity indicators and the present-day temperature of
the reservoirs. Liquid hydrocarbon source rock potential is present in the tidal and coastal embayment facies, and is
greatest in the Miocene coals. Neither the shales nor coaly shales contain signi®cant oil generative potential. The
thermal immaturity of the sample set precludes valid oil±source rock correlations without conducting arti®cial
maturation experiments on the coals. # 2000 Elsevier Science Ltd. All rights reserved.
Keywords: Brunei; Sarawak; Sabah; Malaysia; Allochthonous coaly organic matter; Bicadinanes; Oleanane; Migration-fractionation;
Migration-contamination; Organic facies
1. Introduction
1.1. Background/objectives
Brunei Darussalam occupies a northern portion of
the island of Borneo, sharing that island with parts of
Malaysia and Indonesia. The occurrence of more than
* Corresponding author. Tel.: +1-281-287-5646; fax: +1281-287-5403.
E-mail address: [email protected] (J. Curiale).
1
Current address: 14431 Broadgreen, Houston, TX 77079,
USA.
2
Current address: Pure Resources: 1004 N. Big Spring,
Midland, TX 79701, USA.
10 km of Tertiary sedimentary section, contained in
basins created by depocenters that have moved extensively throughout the Neogene, makes petroleum
exploration particularly challenging (Crevello et al.,
1997). The ®rst exploration well in Brunei was drilled in
1899, and large amounts of petroleum have been produced in the past 70 years. Although eorts during the
®rst ®ve decades of exploration (1911±1960) were concentrated onshore, the past 30 years have seen increasing
oshore exploration and discovery.
Petroleum geochemistry studies of Brunei oils began
indirectly with Grantham (1986), who ®rst noticed a
series of ``resin compounds'' in thermal extracts of fossil
Brunei resins. These compounds were subsequently
identi®ed as bicadinanes, and have since been observed
in several Tertiary oils of southeast Asia (van Aarssen et
0146-6380/00/$ - see front matter # 2000 Elsevier Science Ltd. All rights reserved.
PII: S0146-6380(00)00084-X
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
al., 1990), including the oshore Brunei oils of the present study. The same compounds were observed by
Hitam and Scherer (1993) in both onshore and oshore
Brunei oils, an observation consistent with generation of
low-heterocompound crude from a source facies rich in
angiospermous (resinous) land plant debris (Sandal,
1996). The low-sulfur oils generated from these coals
and coaly shales were later subjected to in-reservoir
biodegradation where burial depths are less than 1500 m.
Source rock studies in Brunei, summarized by Sandal
(1996), have been unsuccessful in identifying substantial
thicknesses of oil-prone section. The scant geological
and geochemical evidence for the origin of the Brunei
oils suggests that terrigenous organic matter deposited
at shelf and slope water depths is the most likely source.
Although such disseminated land plant debris is conventionally considered to be gas-prone, the occurrence
of a substantial net thickness of thin, hydrogen-rich
stringers of allochthonous organic matter within deepwater marine sections is postulated as the primary source
material for the liquid hydrocarbons both onshore and
oshore Brunei (cf. Thompson et al., 1985a).
In this study, we evaluate a series of crude oils and
condensates from oshore Brunei, and a set of shales,
coaly shales and coals from onshore outcrops, using
source rock, carbon isotopic and molecular marker
analysis techniques (Curiale et al., 1999). Our objectives
are to de®ne the character of oshore Brunei oils, to
deduce the depositional setting of the responsible source
rock(s) and the type and variation of organic matter in
these rock(s), and to place this information into an
exploration context in oshore Brunei Darussalam.
1.2. Exploration history in Brunei
Sandal (1996) provides an excellent, detailed history
of petroleum exploration in Brunei Darussalam, with
emphasis on the role of Brunei Shell Petroleum Company (BSP), and much of this section is summarized
from this source. Oil seepages across the Malaysian
border in northern Sarawak, Malaysia, were ®rst reported
in the middle of the 19th century, and subsequent drilling
resulted in the 1910 discovery of the Miri ®eld, which
became the ®rst commercial oil®eld in northwestern
Borneo. Exploration in Brunei Darussalam began in
1899 with a 198 m hole near Bandar Seri Begawan, the
present day capital, and the Belait-2 well was the ®rst to
strike oil. The ®rst commercial oil ®eld was the Seria
®eld, discovered by Shell in 1929.
Exploration oshore Brunei began in the 1950s, and
the ®rst oshore well was drilled in 1957. Since 1965
approximately 70,000 km of 2D seismic have been
acquired in Brunei Darussalam. Since the late 1980s,
seismic acquisition has been mostly 3D, with an estimated 12,000 km2 covering virtually the entire shelf and
slope areas. From 1913 to 1999, operators have drilled
204 exploration wells, including 129 oshore and 75
onshore (Fig. 1). From these activities, 13 commercially
exploitable oil and gas ®elds have been found, as
shown in Fig. 2. The country's current production is in
excess of 150,000 bopd and 1,100 mmcfgpd. Although
BSP is by far the major producer in Brunei, there are
currently three other petroleum concession holders, all
joint ventures of Unocal, Fletcher Challenge and Elf
Aquitaine.
1.3. Stratigraphic framework
The Neogene sediments in Brunei and adjacent
Malaysia consist of up to 10 km of sandstones and
shales assigned to three deltaic complexes that generally
young from east to west (Koopman, 1996; van Borren et
al., 1996). The oldest of the three, the Meligan Delta,
originated in the Paleogene, with deposition of the
Temburong and Meligan Formations continuing into
the early Miocene (Fig. 3). A signi®cant regional
unconformity separates Meligan strata from the overlying Champion Delta middle to late Miocene deposits.
In Brunei, the Champion Delta strata are the prime
petroleum-bearing succession and are represented by the
Setap, Belait, Lambir, Miri and Seria Formations (Fig.
3). The Setap Formation consists of up to 3 km of predominantly shale with thin interbedded sandstones (van
Borren et al., 1996). It ranges from early to middle
Miocene and becomes progressively younger to the
northwest (van Borren et al., 1996). The Setap shales
were deposited in an open marine, relatively distal
environment and represent basinal equivalents of the
more sandy, deltaic facies.
The Belait Formation, a dominantly sandstone succession with interbedded shales and coals, spans the early
to late Miocene and comprises the entire Champion
Delta depositional system in much of Brunei (Fig. 3). It
is a lateral equivalent of the Setap Formation shales in
the early and middle Miocene and of the Lambir, Miri
and Seria Formations in the middle and late Miocene.
Much of the Belait Formation has been interpreted as
coastal and coastal plain deposits from a range of sedimentary environments associated with a relatively large
delta (Wilford, 1961). The sandstones have been described
as mostly ¯uvial (van Borren et al., 1996). The Lambir,
Miri and Seria Formations are lithologically similar to
the Belait Formation but are considered to be more
marine (van Borren et al., 1996). However, recent outcrop
studies indicate that a wide range of coastal and marine
environments is represented in the Belait Formation
(Lambiase et al., 2000). Facies associations suggest that
much of the Belait Formation was deposited in structurally-controlled, tide-dominated coastal embayments
and on open marine coastlines rather than as part of a
delta. This implies that the Champion Delta is a complex depositional system of primarily shallow marine
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
origin, and that there is very little dierence between the
Belait Formation and the Lambir, Miri and Seria Formations (Lambiase et al, 2000). Tidal and shoreface
sandstones dominate the Belait Formation, and ¯uvial
1477
sandstones are rare to absent in outcrop (Lambiase et
al., 2000). Similarly, the exposed coals are closely associated with tidal deposits, and palynological analysis
indicates that these coals contain primarily mangrove
Fig. 1. Exploration drilling history in 5 year segments from 1910 to 1999. Adapted from Sandal (1996); data from various sources,
including Sandal (1996).
Fig. 2. Structural elements oshore Brunei Darussalam. Oil and gas ®elds are also indicated. Adapted from Sandal (1996), and with
contributions from W. Ade and S. Smith.
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Fig. 3. Neogene lithostratigraphy of Brunei (after Sandal, 1996).
debris (M. Simmons, pers. comm.), suggesting deposition
in coastal swamps.
The late Miocene to Quaternary Baram Delta succession is the youngest of the three deltaic systems. In
Brunei, it is represented by the Liang Formation which
unconformably overlies the Belait and Seria Formations
(Fig. 3). A variety of ¯uvial, tidal and shoreface sandstones and shales occur within the Liang Formation
(Abdullah Ibrahim, 1998).
2. Methods
2.1. Sample set Ð locations and ages
We examined in molecular and isotopic detail a set of
12 oils sampled from Miocene reservoir sands of six
exploration wells, as part of Unocal's exploration focus
on the oshore region of Brunei (Fig. 2). Well names
and reservoir depths are listed in Table 1. The wells are
located 60±90 km oshore, in water depths of 90±150 m.
Reservoir depths range from 2 to 3 km below mudline, and
the well locations cover a northeast±southwest distance (i.e.
roughly parallel to the coastline) of about 50 km. Oil
samples were subsampled from glass bottles, and had
originally been recovered from the wells from months to
years prior to subsampling for this project. Sample storage
during this time was at ambient temperatures (70±75 F).
In addition, 72 onshore outcrop samples from Brunei
were taken for source rock analyses, and for use as
facies analogs for source rocks in the oshore region.
All were collected from the Belait Formation within the
Berakas Syncline, and all range from middle to late
Miocene (Fig. 4). This sample set represents strata from
two major depositional settings, speci®cally tide-dominated
coastal embayment and continental shelf, of varying
ages that crop out at dierent geographic locations
within the syncline (Fig. 4).
Coastal embayment successions consist of sediments
deposited in several environments including tidal channels,
tidal ¯ats, distributary channels and coastal swamps.
The 45 samples from tide-dominated environments
include shales, coals and coaly shales that were collected
from low energy, muddy facies that are interbedded
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Table 1
General geochemical data, oshore Brunei Darussalam oilsa
Sample
Well Name
Reservoir depth (m)
d13C (%)
n-C13/n-C22
Pristane/phytane
Pristane/n-C17
Phytane/n-C18
1L04239
1L04240
1L04241
1L04242
1L04243
1L04244
1L04245
1L04246
1L04247
1L04248
1L04249
1L04251
Juragan 2
Juragan 2
Laksamana 1
Laksamana 1
BCS 1
BCS 1
Perdana 1
Perdana 1
Perdana Selatan 1
Perdana Selatan 1
Juragan 1
Juragan 1
2729±2740
2890±2940
2171.5
2982.5
n.a.b
n.a.
2762.6
2761±2767
1988.7
n.a.
2825.5±2863.7
2990±3023
ÿ26.97
ÿ27.06
ÿ27.29
ÿ27.21
ÿ26.82
ÿ27.61
ÿ27.58
ÿ27.82
ÿ27.44
ÿ27.20
ÿ27.21
ÿ27.22
2.06
2.12
1.59
1.58
1.78
1.65
1.31
1.21
1.82
1.92
1.43
1.65
4.04
4.09
3.37
3.96
3.95
3.61
3.48
3.42
4.22
4.02
3.42
3.79
1.05
1.04
1.35
1.07
0.98
1.02
1.09
1.09
1.02
0.98
1.08
1.15
0.30
0.29
0.43
0.30
0.26
0.30
0.34
0.33
0.27
0.27
0.34
0.33
a
b
Chromatographic ratios are calculated from peak heights.
n.a., Not available.
Fig. 4. Chronostratigraphic map of the Berakas Suncline area (after James, 1984) showing outcrop localities, number of samples (in
parentheses) and depositional setting for the sample groups.
sandy tidal ¯at and tidal channel strata. These include
subtidal embayment shales that are generally coaly,
coals that accumulated in coastal mangrove swamps,
and shales deposited on muddy tidal ¯ats.
Twenty-seven samples were collected from continental shelf shales and coaly shales that include sedimentary environments ranging from shales interbedded
with lower shoreface sandstones to middle(?) shelf.
Many of these samples contain a signi®cant amount of
terrestrially-derived organic matter, suggesting proximity to a river and/or delta.
2.2. Geochemical analyses
The crude oils examined here were originally collected
during oshore production tests, and maintained at
ambient temperatures prior to analysis. Eorts were
made to collect the rock samples from below the
weathering layer, although the intensity of weathering in
Brunei made this impossible at times. Rock samples
were analyzed for total organic carbon content (LECO
carbon analyzer) and Rock Eval pyrolysis yields
(ramped at 25 C/min to 550 C).
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Whole oil stable carbon isotope, gas chromatographic
(GC) and gas chromatographic±mass spectrometric
(GC/MS) techniques were identical to those reported
previously (Curiale and Stout, 1993; Curiale and Gibling,
1994; Curiale and Bromley, 1996a, b), except where speci®ed otherwise. Isotopic measurements were made on
whole, untopped oils, and are reported in % (per mil)
notation relative to the PDB primary standard. Whole
oil GC analyses were conducted using a J&W 122-1061
column (60 m0.25 mm, id 0.10 mm). The injector temperature was 330 C, and FID temperature was 350 C.
Hydrogen carrier gas was used, and the oven temperature was ramped from ÿ12 C (0 min) to 10 C (0 min) at
2 C/min, and to 350 C (held 25 min) at 5 C/min.
Whole oil GC/MS analyses were conducted with an
HP 5890 gas chromatograph (splitless injection) coupled
to a VG 70 dual sector mass spectrometer set to resolving
power of 5000. Selected ion recording mode was used,
with voltage scanning. Seven masses were monitored,
including 191.18 (pentacyclic triterpanes) and 217.20
(steranes). VG's Opus and OpusQuan software was used
for semi-quantitative determinations, based upon coinjection of 5b-cholane (100 ppm) as an internal standard.
All molecular ratios presented here are based on peak
heights, using speci®c mass chromatograms as indicated
in the tables and ®gures.
3. Crude oil characteristics
3.1. Eects of source rock organic matter type
The n-alkane and isoprenoid distributions for all oils
are very similar (see Fig. 5, consisting of two sub-®gures, each showing six GC traces) Ð all samples are
paranic, with depleted light ends and pristane/phytane
ratios (measured from peak height) of 3.4±4.1. The pattern
of light-end loss does not appear to be a function of
either geographic location or reservoir depth, although
minor loss of light ends may have resulted from storage
conditions prior to analysis. Where light-end loss does
not appear to be a factor Ð i.e. beyond n±C20 Ð the oils
have extremely similar n-alkane distributions (Fig. 6).
This observation, as well as the similarities in pristane/
phytane ratio and stable carbon isotope ratio (Table 1),
provide evidence that the Brunei oils are derived from
very similar organic facies. The molecular and isotopic
similarity of these Brunei oils with those of oshore
Sarawak (Malaysia) to the northeast (Anuar and Muhamad, 1997) suggest that this characteristic organic facies
may extend along the entire northern margin of Borneo.
Seven of the 12 oils in this sample set were analyzed
for their biomarker distributions, with speci®c emphasis
on the distribution of C27ÿ30 tetracyclic and pentacyclic
hydrocarbons. As is common with many oils of southeast Asia, the Brunei oils contain both oleanane and a
series of bicadinanes, and their sterane carbon number
distributions are dominated by the C29 homologue.
Typical distributions of bicadinanes, oleanane C27ÿ29
steranes and C27,29ÿ32 hopanes are shown in the m/z
217.20 and m/z 191.18 mass chromatograms of Fig. 7.
Biomarker ratios derived from the mass chromatograms
of each of the Brunei oils are listed in Table 2, and support the alkane-based conclusion that a similar organic
facies is responsible for these oils.
Detailed examination of the molecular data suggests
that the organic facies that gave rise to these oshore
Brunei oils contains organic matter that is predominantly land-plant derived (i.e. allochthonous), with
variable admixtures of autochthonous, algal-derived
organic matter from the water column directly above
the site of deposition. The dominance of allochthonous
organic matter is indicated by elevated pristane/phytane
ratios (Table 1) and the presence of bicadinanes in all
samples. The occurrence of autochthonous organic
matter in the source depositional setting is indicated by
the presence of n-propylcholestanes in the Brunei oils
(J.A. Curiale, unpublished data).
Additional direct evidence for an admixture of autochthonous organic matter is shown in Fig. 8, where
varying amounts of angiospermous organic input are
monitored by the (relative) contents of ethylcholestane
(ordinate) and oleanane (abscissa). Although the trend
in Fig. 8 would appear to be consistent in terms of a
directly proportionate contribution of these two terrigenous indicators, it is noted that previous workers have
identi®ed opposite trends in other basins of southeast
Asia (cf. Murray et al., 1997).
The varying input of allochthonous, angiospermous
debris to the source for these oils displays a geographical component, as indicated in Fig. 9 for the
oleanane/hopane ratio. The variability in sourcing
organic matter evident here represents regional dierences in the type of organic matter deposited by the
Champion (paleo-)delta system (cf. Sandal, 1996; Saller
et al., 1999), which apparently resulted in a relative
increase in transport and deposition of angiosperm
debris in the northeastern portion of the study area.
These conclusions can be extended further when the
source rocks responsible for these oils are eventually
penetrated by oshore drilling.
3.2. Eects of migration
Initial examination of the biomarker ratio data in
Table 2 suggested that the thermal maturity for each of
these oils Ð classically de®ned as the maturity level of
the source rock at the time the oils were expelled Ð is
extremely low. Such an observation is consistent with
the common observation of very low molecular maturity levels for oils reservoired in the clastic sediments of
Tertiary deltas worldwide, and for this reason is not
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
1481
Fig. 5. Gas chromatograms for whole oils from the northern and western portions of the oshore study area (left) and the eastern
portion of the oshore study area (right). The nomenclature above each chromatogram lists (left to right) the sample number (cf.
Table 1), the well name and number, and the top and bottom depths of the tested interval, in feet. The compounds eluting after n-C21
and n-C32 are internal standards. Chromatographic conditions are referenced in the text.
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Fig. 5. (continued)
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
1483
Fig. 6. Distribution of n-alkanes from C20 to C30, plotted as a percentage of the total n-alkanes in this range. Sample numbers listed in
the box are the same as those in Table 1. All compounds measured as peak height.
considered unusual. Furthermore, the correlation
between common molecular maturity parameters of this
dataset (e.g., 20S/20S+20R-ethylcholestane and the
trisnorneohopane/trisnorhopane ratio; Table 2) appears
reasonable. However, other correlations appear substantially more problematic. For example, a linear correlation coecient (r2) of 0.97 is observed between the
20S/20S+20R-ethylcholestane ratio and the diacholestane/cholestane ratio (data in Table 2). Although the
latter ratio has been observed to increase with increasing
maturity (e.g. Curiale, 1992), to our knowledge such an
increase occurs only at maturity levels beyond those
apparent here.
Concerns over these apparent maturity variations
prompted us to consider the current reservoir temperatures for these oils, to assess whether the observed
maturity levels were being ``set'' at the time of migration/entrapment rather than at the time of sourcing.
Using geothermal gradients of Sandal (1996) and an
assumed water bottom temperature for all wells of
10 C, reservoir temperatures for the oil set range from
60 to 94 C. As shown in Fig. 10, both the 20S/20S+
20R-ethylcholestane and the diacholestane/cholestane
ratios correlate with present-day reservoir temperature
(r2=0.83 and 0.92, respectively). Based upon these
observations, we conclude that the biomarker-based
maturity levels that we are measuring re¯ect the presentday maturity of the reservoir, rather than that of the
source rock(s) for these oils.
This phenomenon has been observed previously in
other Tertiary deltaic systems, and is generally classi®ed
as migration-contamination (also referred to as solvent
extraction and hydrocarbon entrainment), de®ned as ``the
emplacement into a migrating ¯uid, via dissolution, of
compounds indigenous to the host stratigraphic section,
and exogenous to the migrating ¯uid itself'' (Curiale and
Bromley, 1996a). Migration-contamination has been
observed in several settings, by RullkoÈtter et al. (1984),
Philp and Gilbert (1986), Bac et al. (1990), Bac and
Schulein (1990), Thompson and Kennicut (1990), Walters (1990), Morelos-Garcia et al. (1993) and Comet et
al. (1993). Several of the maturity indicators for the
Brunei oils (Table 2), including the 20S/20S+20Rethylcholestane ratio, appear to be consistent with this
conclusion. Of particular interest is the observation that
the x-intercept in Fig. 10 Ð i.e. the temperature at
which the 20S/20S+20R-ethylcholestane ratio extrapolates to zero Ð is approximately 15 C. This value is
quite close to the water-bottom temperature in this
region, indicating that this ratio is under the direct control of the present-day thermal regime oshore Brunei.
On the basis of these observations, we conclude that the
Brunei oils serve as a solvent which initially contained
low biomarker concentrations. During migration and/or
after entrapment, this ``solvent'' extracted syndepositional biomarkers (i.e. biomarkers, or their precursors,
that were deposited at the same time as rest of the
lithologic unit) from the reservoir sediments. Additional
support for this contention comes from the occurrence
in the Brunei oils of distinctive ole®ns, including 4and 5-sterenes, diasterenes and oleanenes (J.A. Curiale,
unpublished results). The most obvious contamination of
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Fig. 7. m/z 217.20 (top) and 191.18 (bottom) mass chromatograms for a Juragan-1 oil, shown as a typical oshore Brunei Darussalam
oil. Peak designations correspond to the identities listed in Table 3. Measurements made on whole oils at approximately 5000 mass
resolution; further analytical conditions are referenced in the text.
incoming condensates with syndepositional organic
matter occurs when the migrating condensates contain
very low initial concentrations of a speci®c biomarker or
biomarker suite, relative to the concentrations of these
components available in the migration conduit or the
reservoir rock. This is the case with the observed ole®ns
and with the 5a(H),14a(H),17a(H)-20(S+R)-24-ethylcholestanes discussed above. Migration-contamination
involving other components Ð including terpanes Ð is
less obvious, possibly due to higher initial concentrations of these components in the migrating condensate.
These conclusions raise serious questions about the
viability of using biomarker parameters as source facies
and source maturity indicators in the Brunei oil set
(cf. Curiale and Bromley, 1996a). At the least, the
maturity ratios discussed above appear to be thoroughly
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Table 2
Biomarker data, oshore Brunei Darussalam oilsa
Source facies indicators
Sample
number
1L04239
1L04241
1L04242
1L04244
1L04245
1L04247
1L04249
Well name
(depth)
Juragan 2 (2729 m)
Laksamana 1 (2171.5 m)
Laksamana 1 (2982.5 m)
BCS 1 (not available)
Perdana 1 (2762.6 m)
Perdana SEL-1 (1988.7 m)
Juragan 1 (2825.5 m)
Sterane carbon
numberb
C27
C28
C29
29.8
26.2
23.6
26.0
27.6
26.1
29.9
19.5
21.4
18.4
20.9
21.4
21.9
20.1
50.7
52.4
58.0
53.1
50.9
52.1
50.0
H/S
Maturity indicators
c
6.04
3.77
5.58
5.63
5.01
3.20
9.22
Ol/H
35/31-35
Bicad
20S/S+Rg Diasth 22S/S+Ri Ts/Tmj
0.77
1.15
1.52
1.16
1.09
1.18
0.88
0.011
0.023
0.021
0.018
0.020
0.007
0.007
0.85
0.36
0.40
0.48
0.45
0.38
1.09
0.18
0.14
0.19
0.18
0.16
0.12
0.22
d
e
f
0.13
0.09
0.15
0.13
0.11
0.07
0.16
0.53
0.54
0.55
0.55
0.55
0.54
0.54
0.65
0.56
0.68
0.65
0.56
0.56
0.76
a
All ratios measured from peak heights on mass chromatograms from GC/MS-SIR runs at mass resolution of approximately 5000.
Distribution of 5a(H),14a(H),17a(H)-20R steranes by carbon number (%) (from m/z 217.20 trace).
c
17a(H),21b(H)-hopane/5a(H),14a(H),17a(H)-20R-24-ethylcholestane (from m/z 191.18 and 217.20 traces).
d
[18a(H)+18b(H)]-oleanane/17a(H),21b(H)-hopane (from m/z 191.18 trace).
e
17a(H),21b(H)-22(S+R)-C35-hopane/17a(H),21b(H)-22(S+R)-C31-35-hopane (from m/z 191.18 trace).
f
trans-trans-trans-Bicadinane/5a(H),14a(H),17a(H)-20R-24-ethylcholestane (from m/z 217.20 trace)
g
5a(H),14a(H),17a(H)-20S-24-ethylcholestane/5a(H),14a(H),17a(H)-20(S+R)-24-ethylcholestane (from m/z 217.20 trace).
h
13b(H),17a(H)-diacholestane/14a(H),17a(H)-20R-cholestane (from m/z 217.20 trace).
i
17a(H),21b(H)-22S-C31-hopane/17a(H),21b(H)-22(S+R)-C31-hopane (from m/z 191.18 trace).
j
18a(H)-22,29,30-trisnorneohopane/17a(H)-22,29,30-trisnorhopane (from m/z 191.18 trace).
b
Fig. 8. Bivariate plot of the 5a(H),14a(H),17a(H)-20R-24-ethylcholestane/5a(H),14a(H),17a(H)-20R-cholestane ratio (ordinate;
measured as peak height on the m/z 217.20 mass chromatogram) versus the [18a(H)+18b(H)]-oleanane/hopane ratio (abscissa; measured as peak height on the m/z 191.18 mass chromatogram). Data are listed in Table 2, and discussed in the text.
1486
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Fig. 9. Map of oshore Brunei Darussalam, showing the [18a(H)+18b(H)]-oleanane/hopane ratio (in parentheses) in a series of oshore oils. The dark blobs are the major oil and gas ®elds; bathymetry is shown in meters. The northwest-southeast trending lines
oshore represent the Brunei±Malaysia international boundary.
overprinted by contributions from the syndepositional
organic matter in the reservoir sediments. On balance it
would appear, with respect to unravelling the source
characteristics of these oils, that low-concentration
components in the migrating oil are severely compromised by migration-contamination. For this reason, we
have relied for source facies (and source maturity)
determinations upon bulk parameters (e.g. d13C of
whole oil) and those molecular components that are in
suciently high initial concentration so as not to have
been substantially overprinted by syndepositional
organic matter in the reservoir sediments (e.g. n-alkanes
and acyclic isoprenoids). Although our previous source
facies conclusions for these oils remain the same when
using these criteria, we note that assessment of the thermal
maturity of the source rock at the time of expulsion of
these oils is now impossible to determine accurately.
Although reliance on bulk parameters and molecular
suites in relatively high concentration (e.g. d13C values and
n-alkane distributions) provides reasonable estimates of
original source facies for these oils, it is observed that
even parameters such as these may have been in¯uenced
by migration-related phenomenon in oshore Brunei.
Fig. 11 shows the relationship between the extent of
``front-end loading'' in these oils (as measured by the
ratio of the C13 to C22 n-alkanes) and their d13C value.
The trend of increasing d13C values with increasing light
n-alkane bias has been observed in other Tertiary deltaic
oils (Dzou and Hughes, 1993; Curiale and Bromley,
1996b and references therein), and has been attributed
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
1487
Fig. 10. Superimposed bivariate plots of the 5a(H),14a(H),17a(H)-20S/(20R+20S)-24-ethylcholestane ratio (diamond symbols) and
the 13b(H),17a(H)-20S-diacholestane/5a(H),14a(H),17a(H)-20R-cholestane ratio (circle symbols), versus the approximate reservoir
temperature, in degrees Celsius (abscissa).
to migration-fractionation (Curiale and Bromley,
1996b). Even though the parameter variability in Fig. 11
is relatively minor compared to other documented
instances of migration-fractionation, it is noted that this
process has apparently aected the composition of the
Brunei oils to varying extents.
4. Source rock potential
The full sample set was sub-sampled for source rock
analysis with the objective of providing data representative of both location and depositional setting (i.e.
facies). On this basis, of the 72 outcrop samples, 53
samples were chosen for further study. Total organic
carbon (TOC) contents and Rock-Eval pyrolysis yields
are listed in Table 4, categorized by depositional facies
and lithology.
Rock-Eval Tmax data indicate that each of the samples is thermally immature with respect to generation of
liquid hydrocarbons. Tmax values are less than 430 C in
all cases, and less than 410±420 C in most cases.
Although this very low maturity level precludes the use
of this sample set for molecular and isotopic oil±source
rock correlations, conclusions may be derived about the
source rock potential of individual facies and lithologies
of the Brunei stratigraphic succession.
The data in Table 4 are displayed graphically in Figs.
12 and 13, and subdivided in these ®gures according to
depositional facies and lithology. These plots suggest
that the greatest liquid hydrocarbon source rock potential occurs in the tidal and embayment facies, with
hydrogen indices approaching 300 mg/g in coals of the
tidal facies (Fig. 13).
In general, regardless of depositional setting, the
shales of the sample set possess low amounts of organic
matter and the lowest liquid generation potential, and
are likely to produce only gas when thermally mature
Table 3
Peak Assignments
b
c
d
m
o
p
q
s
t
u
v
A
B
C
D
cis-cis-trans-Bicadinane
18a(H)-22,29,30-Trisnorneohopane
trans-trans-trans-Bicadinane
17a(H),21b(H)-30-Norhopane
[18a(H)+18b(H)]-Oleanane
17a(H),21b(H)-Hopane
17b(H),21a(H)-Hopane
17a(H),21b(H)-22S-30-Homohopane
17a(H),21b(H)-22R-30-Homohopane
17a(H),21b(H)-22S-30-Bishomohopane
17a(H),21b(H)-22R-30-Bishomohopane
5a(H),14a(H),17a(H)-20R-Cholestane
5a(H),14a(H),17a(H)-20R-24-Methylcholestane
5a(H),14a(H),17a(H)-20R-24-Ethylcholestane
5a(H),14a(H),17a(H)-20S-24-Ethylcholestane
1488
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Table 4
Source rock dataa
Sample ID
Tidal
Shale
MM-12
MM-14
Coaly shale
KB-14
MM-10
MM-11
SU-3
KB-13
KB-12
KB-11
KB-7
KB-8
KB-5
KB-6
KB-2
KB-3
SA-9
SU-9
SA-4
SA-8
Coal
SA-5
SU-1
SA-2
KB-4
KB-10
KB-9
SU-7
Embayment
Shale
MM-3
MM-2
MM-4
MM-1
Coaly shale
SA-12
MM-8
SU-8
SA-10
SA-1
SU-10
Coal
SA-3
SU-4
SU-5
SU-6
Shoreface
Shale
J-6
MM-5
TOC (%)
S1 (mg/g)
S2 (mg/g)
Tmax ( C)
S3 (mg/g)
HI (mg/g)
OI (mg/g)
3.42
1.05
0.29
0.13
0.75
0.30
403
2.83
0.58
77
29
292
55
1.86
3.05
47.40
3.05
7.89
3.96
8.38
7.00
3.99
34.30
8.96
16.60
16.10
5.38
6.40
8.83
23.50
0.12
0.28
2.70
0.23
1.01
0.20
0.64
0.68
0.29
2.91
1.02
1.16
1.09
1.14
0.50
1.71
2.04
0.55
0.87
22.08
1.80
8.52
1.88
13.18
12.85
1.38
55.83
17.54
15.32
17.22
5.76
3.84
13.57
7.50
417
410
409
417
395
411
405
409
397
401
409
412
403
417
397
422
414
0.50
1.56
41.87
1.45
1.92
1.23
2.11
1.51
1.68
12.50
2.36
9.93
5.29
4.23
1.87
7.14
14.31
30
29
47
59
108
47
157
184
35
163
196
92
107
107
60
154
32
27
51
88
48
24
31
25
22
42
36
26
60
33
79
29
81
61
17.60
20.20
22.80
33.70
60.20
59.10
60.50
5.14
3.67
2.50
2.08
2.55
3.06
6.36
31.06
21.73
18.54
57.08
135.10
95.30
171.13
398
405
408
402
408
412
401
13.98
11.93
11.25
8.33
13.61
25.71
16.13
176
108
81
169
224
161
283
79
59
49
25
23
44
27
1.22
3.41
3.61
6.23
0.14
0.65
0.40
1.35
0.34
1.08
0.86
1.97
392
391
385
0.64
2.35
2.22
4.14
28
32
24
32
52
69
61
66
2.12
2.94
3.92
4.22
5.41
6.06
0.14
0.37
0.29
0.45
0.36
0.76
0.41
1.19
2.20
2.61
4.31
7.12
415
406
399
396
401
406
0.78
1.87
1.06
1.60
1.40
1.71
19
40
56
62
80
117
37
64
27
38
26
28
50.30
60.50
46.10
27.80
2.85
2.65
3.33
3.67
45.23
96.32
91.11
53.06
406
409
401
396
28.09
14.48
15.27
8.57
90
159
198
191
56
24
33
31
3.61
1.02
0.30
0.15
2.80
0.49
412
0.77
0.37
78
48
21
36
(continued overpage)
1489
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Table 1 (continued)
Sample ID
MM-9
SA-6
TOC (%)
S1 (mg/g)
S2 (mg/g)
0.84
1.02
0.08
0.11
0.16
0.49
Tmax ( C)
S3 (mg/g)
HI (mg/g)
OI (mg/g)
0.17
1.38
19
48
20
135
Coaly shale
KB-1
SA-11
SU-11
Coal
SA-7
J-7
JM-5
JM-4
L-7
9.37
2.22
2.52
0.86
0.24
0.26
8.31
0.85
1.41
412
411
419
5.40
0.60
0.66
89
38
56
58
27
26
18.10
1.22
0.85
0.97
1.12
4.21
0.09
0.16
0.12
0.11
26.44
0.35
0.78
0.66
0.70
401
430
431
434
9.58
1.21
0.16
0.39
0.18
146
29
92
68
63
53
99
19
40
16
Coaly shale
J-8
8.67
0.48
8.18
403
2.02
94
23
a
TOC=total organic carbon; S1, S2, hydrocarbons yielded from Rock-Eval pyrolysis; Tmax, temperature at fastest S2 generation
rate; S3, carbon dioxide yielded from Rock-Eval pyrolysis; HI, hydrogen index; OI, oxygen index.
Fig. 11. Bivariate plot of the n-C13/n-C22 ratio (ordinate; measured from peak heights in the whole oil gas chromatograms) vs the
whole oil carbon isotope ratio (abscissa).
(Fig. 13). Data for the coaly shales suggest a similar
conclusion. However, selected coals originating in
environments proximate to the marine setting, including
tidal, lagoonal, embayment and shoreface areas, have
sucient organic matter and generative potential to be
considered as potential sources for both oil and gas
(Fig. 12; Thompson et al., 1985a, b; Wan Hasiah, 1999).
5. Implications and conclusions
It has long been recognized from geochemical studies
that organic matter derived from land plants and
deposited in marine environments is the source of most
of the oil and gas in Brunei (Schreurs, 1996). However,
volumetrically-signi®cant potential source rocks have
1490
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Fig. 12. Plots of the hydrocarbon generation potential (Rock-Eval S1+S2, in mg hydrocarbons/g rock) vs total organic carbon
(TOC,%), for the tidal, embayment, shoreface and shelfal depositional settings. Speci®c lithologies are indicated. Note that the y-axis
is logarithmic, and that the scale of the tidal setting (top left) extends an order of magnitude beyond the scale for the other depositional settings.
neither been observed in outcrop nor penetrated in the
subsurface. As a result, no speci®c source rock interval
has been identi®ed. Although the results of the present
study do not allow us to specify conclusively either the
lithologic unit or the age of the source for the Brunei
oils, several conclusions may be reached from the chemical composition of the oshore oils and the source
rock capabilities of the onshore coals and coaly shales.
The Brunei oils originated from source rocks that
contain mainly allochthonous organic matter (i.e. continental plant debris) deposited in the neritic environment of a pro-delta setting. Although the fundamental
nature of the source facies for each of the oshore oils
in this study is constant, variation in input of autochthonous versus allochthonous organic matter in the
source unit(s) for these oils is apparent from the molecular data. If a single lithologic unit is responsible for
sourcing these oils, the organic matter in that unit must
consists of a mixture of (a) land plant organic matter
and (b) biota from the photic zone of the water column.
Based upon the molecular composition of the oils, our
data show that the ratio of allochthonous to autochthonous organic matter in the source increases to the
northeast. If it is assumed that the quantity of organic
matter generated in the water column photic zone
remains unchanged over this relatively small geographic
area, then it is likely that the dierences in source rock
character result from dierences in the amount (rather
than the quality) of contributed terrigenous organic
matter in the southwest and northeast areas of oshore
Brunei. This is presumably related to speci®c depositional patterns of the Champion paleodelta sediments
(Fig. 3), which are expected to show increasing terrigenous input toward the northeastern part of our study
area.
Although the relative concentrations of these sourcerelated molecular components allow conclusions about
the character of the source rock organic matter, other
hydrocarbon suites have been aected substantially by
the migration process. Our data show evidence for signi®cant extraction, by migrated liquid petroleum, of
syndepositional molecular components that otherwise
would serve as proxies for source rock maturity at the
time of oil expulsion. This overprinting limits the use of
biomarkers as source, maturity and migration indicators
in oils of the Brunei oshore. Of particular concern are
the problems inherent in oil±source rock correlation
eorts when the oils in question contain, in addition to
molecular components generated in the source rock,
biomarkers and biomarker suites dissolved from syndepositional organic matter in the reservoir rocks and/or
migratory conduits. Attempted molecular (and possibly
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
1491
Fig. 13. Adapted van Krevelen plots [Hydrogen Index (HI) vs Oxygen Index (OI), as mg hydrocarbons/g rock and mg carbon dioxide/g rock, respectively] for the tidal, embayment, shoreface and shelfal depositional settings. Speci®c lithologies are indicated.
isotopic) correlations between such oils and their purported source unit(s) will certainly fail if proper consideration is not given to the dilution of sourceindigenous source rock biomarkers by extraneous biomarkers contributed after expulsion. In such instances,
we recommend that conventional biomarker correlations (i.e. those utilizing tetracyclic and pentacyclic aliphatic hydrocarbons) be corroborated with data for
molecular suites that occur in higher relative concentration in the original source (e.g. tricyclic terpanes, alkylated naphthalenes, etc.). Using this approach there is a
greater likelihood that the components in question are
thermogenic products of generation within the source
rock, and the potential for molecular dilution in the
reservoir and migratory conduit will be minimized.
Onshore autochthonous coals and coaly shales may
be used as analogs for the allochthonous coaly intervals
that have sourced the oshore oils (Wan Hasiah, 1999).
Source rock evaluation of a set of 53 shales, coaly shales
and coals indicates that coals proximate to a marine
setting, and particularly those deposited within the tidal
range, have the potential to generate liquid hydrocarbons. Because this potential is yet to be realized for
the coals in our sample set, oil±source rock correlations
are not feasible. Despite the implied source rock information that can be derived from chemical characteristics
of the oils, con®rmed oil±source rock correlations must
await future exploration eorts which result in the
penetration of mature source section, most likely in the
oshore.
Exploration eorts that began in onshore Brunei
about a century ago have since been extended into the
oshore, and will eventually extend to the deepwater
areas farther north and northwest. The success of these
eorts in identifying commercial liquid hydrocarbons
farther oshore will depend, in the ®rst instance, on the
presence of crude oil source rocks in this area. Although
the oils examined here testify only to the presence of
such sources on the inner shelf, the mechanism of moving terrigenous organic matter oshore and supplementing its sourcing capability with autochthonous
organic matter from the photic zone should extrapolate
directly to the deepwater setting, and allow for the prediction of liquid hydrocarbon potential in outer shelf
and slope areas (Anuar and Muhamad, 1997). Our
source rock and oil compositional results provide support for the occurrence of such potential in these outer
waters.
1492
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Acknowledgements
We appreciate the cooperation of the geologists of
Fletcher Challenge Energy Borneo in providing us
access of the oshore oil samples. Conversations with
Sherman Smith, John Baines and Art Saller improved
our understanding of the petroleum systems of Brunei.
We thank Mike Kirby and Baby Ellamil for drafting
assistance, and Paul Peaden and Bernie Wilk for assistance with acquisition of the GC and GC/MS data. E.
Tegelaar (Baseline Resolution Inc.) provided assistance
with identi®cation of ole®ns in the Brunei oils (via GC/
MS/MS analysis). The manuscript was improved as a
result of comments from reviewers S. Imbus and C.
Schiefelbein. We also acknowledge Unocal Corporation
for allowing us to release the data and publish this
paper.
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Brunei Darussalam
Characteristics of selected petroleums and source rocks
J. Curiale a,*, J. Morelos a,1, J. Lambiase b, W. Mueller c,2
a
Unocal Corporation, 14141 Southwest Freeway, Sugar Land, TX 77478, USA
Universiti Brunei Darussalam, Petroleum Geoscience, Bandar Seri Begawan BE1410, Negara, Brunei
c
Unocal Borneo Utara Ltd, Locked Bag #76, Bandar Seri Begawan BS8611, Negara, Brunei
b
Abstract
The development of three Tertiary deltaic complexes has resulted in the deposition of up to 10 km of sandstones and
shales comprising the sources and reservoirs for crude oils that occur onshore, near-oshore and, with future
exploration eorts, those likely to be encountered in deepwater reservoirs north of the Brunei coastline. We examined a
series of oshore oils and onshore rock samples in Brunei Darussalam (a) to delineate oil family groups and their
source rock characteristics, and (b) to assess the source potential of the sedimentary sequence with respect to lithology
and depositional setting. Twelve oshore oils and 53 shales, coaly shales and coals were examined. The oils contain
indicators of allochthonous (e.g. bicadinanes, oleananes) and autochthonous (e.g. cholestanes and methylcholestanes)
components in the source organic matter. Predictable geographic variations of this mixed input are clearly evident in
the sample set (e.g. allochthonous input appears to increase in oshore Brunei to the northeast). Although this molecular source signature is relatively clear, migration of these oils from deep (and unidenti®ed) source rocks has resulted
in extensive migration-contamination with respect to the tetracyclic and pentacyclic hydrocarbons. This contamination
has resulted in strong correlations between certain molecular maturity indicators and the present-day temperature of
the reservoirs. Liquid hydrocarbon source rock potential is present in the tidal and coastal embayment facies, and is
greatest in the Miocene coals. Neither the shales nor coaly shales contain signi®cant oil generative potential. The
thermal immaturity of the sample set precludes valid oil±source rock correlations without conducting arti®cial
maturation experiments on the coals. # 2000 Elsevier Science Ltd. All rights reserved.
Keywords: Brunei; Sarawak; Sabah; Malaysia; Allochthonous coaly organic matter; Bicadinanes; Oleanane; Migration-fractionation;
Migration-contamination; Organic facies
1. Introduction
1.1. Background/objectives
Brunei Darussalam occupies a northern portion of
the island of Borneo, sharing that island with parts of
Malaysia and Indonesia. The occurrence of more than
* Corresponding author. Tel.: +1-281-287-5646; fax: +1281-287-5403.
E-mail address: [email protected] (J. Curiale).
1
Current address: 14431 Broadgreen, Houston, TX 77079,
USA.
2
Current address: Pure Resources: 1004 N. Big Spring,
Midland, TX 79701, USA.
10 km of Tertiary sedimentary section, contained in
basins created by depocenters that have moved extensively throughout the Neogene, makes petroleum
exploration particularly challenging (Crevello et al.,
1997). The ®rst exploration well in Brunei was drilled in
1899, and large amounts of petroleum have been produced in the past 70 years. Although eorts during the
®rst ®ve decades of exploration (1911±1960) were concentrated onshore, the past 30 years have seen increasing
oshore exploration and discovery.
Petroleum geochemistry studies of Brunei oils began
indirectly with Grantham (1986), who ®rst noticed a
series of ``resin compounds'' in thermal extracts of fossil
Brunei resins. These compounds were subsequently
identi®ed as bicadinanes, and have since been observed
in several Tertiary oils of southeast Asia (van Aarssen et
0146-6380/00/$ - see front matter # 2000 Elsevier Science Ltd. All rights reserved.
PII: S0146-6380(00)00084-X
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
al., 1990), including the oshore Brunei oils of the present study. The same compounds were observed by
Hitam and Scherer (1993) in both onshore and oshore
Brunei oils, an observation consistent with generation of
low-heterocompound crude from a source facies rich in
angiospermous (resinous) land plant debris (Sandal,
1996). The low-sulfur oils generated from these coals
and coaly shales were later subjected to in-reservoir
biodegradation where burial depths are less than 1500 m.
Source rock studies in Brunei, summarized by Sandal
(1996), have been unsuccessful in identifying substantial
thicknesses of oil-prone section. The scant geological
and geochemical evidence for the origin of the Brunei
oils suggests that terrigenous organic matter deposited
at shelf and slope water depths is the most likely source.
Although such disseminated land plant debris is conventionally considered to be gas-prone, the occurrence
of a substantial net thickness of thin, hydrogen-rich
stringers of allochthonous organic matter within deepwater marine sections is postulated as the primary source
material for the liquid hydrocarbons both onshore and
oshore Brunei (cf. Thompson et al., 1985a).
In this study, we evaluate a series of crude oils and
condensates from oshore Brunei, and a set of shales,
coaly shales and coals from onshore outcrops, using
source rock, carbon isotopic and molecular marker
analysis techniques (Curiale et al., 1999). Our objectives
are to de®ne the character of oshore Brunei oils, to
deduce the depositional setting of the responsible source
rock(s) and the type and variation of organic matter in
these rock(s), and to place this information into an
exploration context in oshore Brunei Darussalam.
1.2. Exploration history in Brunei
Sandal (1996) provides an excellent, detailed history
of petroleum exploration in Brunei Darussalam, with
emphasis on the role of Brunei Shell Petroleum Company (BSP), and much of this section is summarized
from this source. Oil seepages across the Malaysian
border in northern Sarawak, Malaysia, were ®rst reported
in the middle of the 19th century, and subsequent drilling
resulted in the 1910 discovery of the Miri ®eld, which
became the ®rst commercial oil®eld in northwestern
Borneo. Exploration in Brunei Darussalam began in
1899 with a 198 m hole near Bandar Seri Begawan, the
present day capital, and the Belait-2 well was the ®rst to
strike oil. The ®rst commercial oil ®eld was the Seria
®eld, discovered by Shell in 1929.
Exploration oshore Brunei began in the 1950s, and
the ®rst oshore well was drilled in 1957. Since 1965
approximately 70,000 km of 2D seismic have been
acquired in Brunei Darussalam. Since the late 1980s,
seismic acquisition has been mostly 3D, with an estimated 12,000 km2 covering virtually the entire shelf and
slope areas. From 1913 to 1999, operators have drilled
204 exploration wells, including 129 oshore and 75
onshore (Fig. 1). From these activities, 13 commercially
exploitable oil and gas ®elds have been found, as
shown in Fig. 2. The country's current production is in
excess of 150,000 bopd and 1,100 mmcfgpd. Although
BSP is by far the major producer in Brunei, there are
currently three other petroleum concession holders, all
joint ventures of Unocal, Fletcher Challenge and Elf
Aquitaine.
1.3. Stratigraphic framework
The Neogene sediments in Brunei and adjacent
Malaysia consist of up to 10 km of sandstones and
shales assigned to three deltaic complexes that generally
young from east to west (Koopman, 1996; van Borren et
al., 1996). The oldest of the three, the Meligan Delta,
originated in the Paleogene, with deposition of the
Temburong and Meligan Formations continuing into
the early Miocene (Fig. 3). A signi®cant regional
unconformity separates Meligan strata from the overlying Champion Delta middle to late Miocene deposits.
In Brunei, the Champion Delta strata are the prime
petroleum-bearing succession and are represented by the
Setap, Belait, Lambir, Miri and Seria Formations (Fig.
3). The Setap Formation consists of up to 3 km of predominantly shale with thin interbedded sandstones (van
Borren et al., 1996). It ranges from early to middle
Miocene and becomes progressively younger to the
northwest (van Borren et al., 1996). The Setap shales
were deposited in an open marine, relatively distal
environment and represent basinal equivalents of the
more sandy, deltaic facies.
The Belait Formation, a dominantly sandstone succession with interbedded shales and coals, spans the early
to late Miocene and comprises the entire Champion
Delta depositional system in much of Brunei (Fig. 3). It
is a lateral equivalent of the Setap Formation shales in
the early and middle Miocene and of the Lambir, Miri
and Seria Formations in the middle and late Miocene.
Much of the Belait Formation has been interpreted as
coastal and coastal plain deposits from a range of sedimentary environments associated with a relatively large
delta (Wilford, 1961). The sandstones have been described
as mostly ¯uvial (van Borren et al., 1996). The Lambir,
Miri and Seria Formations are lithologically similar to
the Belait Formation but are considered to be more
marine (van Borren et al., 1996). However, recent outcrop
studies indicate that a wide range of coastal and marine
environments is represented in the Belait Formation
(Lambiase et al., 2000). Facies associations suggest that
much of the Belait Formation was deposited in structurally-controlled, tide-dominated coastal embayments
and on open marine coastlines rather than as part of a
delta. This implies that the Champion Delta is a complex depositional system of primarily shallow marine
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
origin, and that there is very little dierence between the
Belait Formation and the Lambir, Miri and Seria Formations (Lambiase et al, 2000). Tidal and shoreface
sandstones dominate the Belait Formation, and ¯uvial
1477
sandstones are rare to absent in outcrop (Lambiase et
al., 2000). Similarly, the exposed coals are closely associated with tidal deposits, and palynological analysis
indicates that these coals contain primarily mangrove
Fig. 1. Exploration drilling history in 5 year segments from 1910 to 1999. Adapted from Sandal (1996); data from various sources,
including Sandal (1996).
Fig. 2. Structural elements oshore Brunei Darussalam. Oil and gas ®elds are also indicated. Adapted from Sandal (1996), and with
contributions from W. Ade and S. Smith.
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Fig. 3. Neogene lithostratigraphy of Brunei (after Sandal, 1996).
debris (M. Simmons, pers. comm.), suggesting deposition
in coastal swamps.
The late Miocene to Quaternary Baram Delta succession is the youngest of the three deltaic systems. In
Brunei, it is represented by the Liang Formation which
unconformably overlies the Belait and Seria Formations
(Fig. 3). A variety of ¯uvial, tidal and shoreface sandstones and shales occur within the Liang Formation
(Abdullah Ibrahim, 1998).
2. Methods
2.1. Sample set Ð locations and ages
We examined in molecular and isotopic detail a set of
12 oils sampled from Miocene reservoir sands of six
exploration wells, as part of Unocal's exploration focus
on the oshore region of Brunei (Fig. 2). Well names
and reservoir depths are listed in Table 1. The wells are
located 60±90 km oshore, in water depths of 90±150 m.
Reservoir depths range from 2 to 3 km below mudline, and
the well locations cover a northeast±southwest distance (i.e.
roughly parallel to the coastline) of about 50 km. Oil
samples were subsampled from glass bottles, and had
originally been recovered from the wells from months to
years prior to subsampling for this project. Sample storage
during this time was at ambient temperatures (70±75 F).
In addition, 72 onshore outcrop samples from Brunei
were taken for source rock analyses, and for use as
facies analogs for source rocks in the oshore region.
All were collected from the Belait Formation within the
Berakas Syncline, and all range from middle to late
Miocene (Fig. 4). This sample set represents strata from
two major depositional settings, speci®cally tide-dominated
coastal embayment and continental shelf, of varying
ages that crop out at dierent geographic locations
within the syncline (Fig. 4).
Coastal embayment successions consist of sediments
deposited in several environments including tidal channels,
tidal ¯ats, distributary channels and coastal swamps.
The 45 samples from tide-dominated environments
include shales, coals and coaly shales that were collected
from low energy, muddy facies that are interbedded
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Table 1
General geochemical data, oshore Brunei Darussalam oilsa
Sample
Well Name
Reservoir depth (m)
d13C (%)
n-C13/n-C22
Pristane/phytane
Pristane/n-C17
Phytane/n-C18
1L04239
1L04240
1L04241
1L04242
1L04243
1L04244
1L04245
1L04246
1L04247
1L04248
1L04249
1L04251
Juragan 2
Juragan 2
Laksamana 1
Laksamana 1
BCS 1
BCS 1
Perdana 1
Perdana 1
Perdana Selatan 1
Perdana Selatan 1
Juragan 1
Juragan 1
2729±2740
2890±2940
2171.5
2982.5
n.a.b
n.a.
2762.6
2761±2767
1988.7
n.a.
2825.5±2863.7
2990±3023
ÿ26.97
ÿ27.06
ÿ27.29
ÿ27.21
ÿ26.82
ÿ27.61
ÿ27.58
ÿ27.82
ÿ27.44
ÿ27.20
ÿ27.21
ÿ27.22
2.06
2.12
1.59
1.58
1.78
1.65
1.31
1.21
1.82
1.92
1.43
1.65
4.04
4.09
3.37
3.96
3.95
3.61
3.48
3.42
4.22
4.02
3.42
3.79
1.05
1.04
1.35
1.07
0.98
1.02
1.09
1.09
1.02
0.98
1.08
1.15
0.30
0.29
0.43
0.30
0.26
0.30
0.34
0.33
0.27
0.27
0.34
0.33
a
b
Chromatographic ratios are calculated from peak heights.
n.a., Not available.
Fig. 4. Chronostratigraphic map of the Berakas Suncline area (after James, 1984) showing outcrop localities, number of samples (in
parentheses) and depositional setting for the sample groups.
sandy tidal ¯at and tidal channel strata. These include
subtidal embayment shales that are generally coaly,
coals that accumulated in coastal mangrove swamps,
and shales deposited on muddy tidal ¯ats.
Twenty-seven samples were collected from continental shelf shales and coaly shales that include sedimentary environments ranging from shales interbedded
with lower shoreface sandstones to middle(?) shelf.
Many of these samples contain a signi®cant amount of
terrestrially-derived organic matter, suggesting proximity to a river and/or delta.
2.2. Geochemical analyses
The crude oils examined here were originally collected
during oshore production tests, and maintained at
ambient temperatures prior to analysis. Eorts were
made to collect the rock samples from below the
weathering layer, although the intensity of weathering in
Brunei made this impossible at times. Rock samples
were analyzed for total organic carbon content (LECO
carbon analyzer) and Rock Eval pyrolysis yields
(ramped at 25 C/min to 550 C).
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Whole oil stable carbon isotope, gas chromatographic
(GC) and gas chromatographic±mass spectrometric
(GC/MS) techniques were identical to those reported
previously (Curiale and Stout, 1993; Curiale and Gibling,
1994; Curiale and Bromley, 1996a, b), except where speci®ed otherwise. Isotopic measurements were made on
whole, untopped oils, and are reported in % (per mil)
notation relative to the PDB primary standard. Whole
oil GC analyses were conducted using a J&W 122-1061
column (60 m0.25 mm, id 0.10 mm). The injector temperature was 330 C, and FID temperature was 350 C.
Hydrogen carrier gas was used, and the oven temperature was ramped from ÿ12 C (0 min) to 10 C (0 min) at
2 C/min, and to 350 C (held 25 min) at 5 C/min.
Whole oil GC/MS analyses were conducted with an
HP 5890 gas chromatograph (splitless injection) coupled
to a VG 70 dual sector mass spectrometer set to resolving
power of 5000. Selected ion recording mode was used,
with voltage scanning. Seven masses were monitored,
including 191.18 (pentacyclic triterpanes) and 217.20
(steranes). VG's Opus and OpusQuan software was used
for semi-quantitative determinations, based upon coinjection of 5b-cholane (100 ppm) as an internal standard.
All molecular ratios presented here are based on peak
heights, using speci®c mass chromatograms as indicated
in the tables and ®gures.
3. Crude oil characteristics
3.1. Eects of source rock organic matter type
The n-alkane and isoprenoid distributions for all oils
are very similar (see Fig. 5, consisting of two sub-®gures, each showing six GC traces) Ð all samples are
paranic, with depleted light ends and pristane/phytane
ratios (measured from peak height) of 3.4±4.1. The pattern
of light-end loss does not appear to be a function of
either geographic location or reservoir depth, although
minor loss of light ends may have resulted from storage
conditions prior to analysis. Where light-end loss does
not appear to be a factor Ð i.e. beyond n±C20 Ð the oils
have extremely similar n-alkane distributions (Fig. 6).
This observation, as well as the similarities in pristane/
phytane ratio and stable carbon isotope ratio (Table 1),
provide evidence that the Brunei oils are derived from
very similar organic facies. The molecular and isotopic
similarity of these Brunei oils with those of oshore
Sarawak (Malaysia) to the northeast (Anuar and Muhamad, 1997) suggest that this characteristic organic facies
may extend along the entire northern margin of Borneo.
Seven of the 12 oils in this sample set were analyzed
for their biomarker distributions, with speci®c emphasis
on the distribution of C27ÿ30 tetracyclic and pentacyclic
hydrocarbons. As is common with many oils of southeast Asia, the Brunei oils contain both oleanane and a
series of bicadinanes, and their sterane carbon number
distributions are dominated by the C29 homologue.
Typical distributions of bicadinanes, oleanane C27ÿ29
steranes and C27,29ÿ32 hopanes are shown in the m/z
217.20 and m/z 191.18 mass chromatograms of Fig. 7.
Biomarker ratios derived from the mass chromatograms
of each of the Brunei oils are listed in Table 2, and support the alkane-based conclusion that a similar organic
facies is responsible for these oils.
Detailed examination of the molecular data suggests
that the organic facies that gave rise to these oshore
Brunei oils contains organic matter that is predominantly land-plant derived (i.e. allochthonous), with
variable admixtures of autochthonous, algal-derived
organic matter from the water column directly above
the site of deposition. The dominance of allochthonous
organic matter is indicated by elevated pristane/phytane
ratios (Table 1) and the presence of bicadinanes in all
samples. The occurrence of autochthonous organic
matter in the source depositional setting is indicated by
the presence of n-propylcholestanes in the Brunei oils
(J.A. Curiale, unpublished data).
Additional direct evidence for an admixture of autochthonous organic matter is shown in Fig. 8, where
varying amounts of angiospermous organic input are
monitored by the (relative) contents of ethylcholestane
(ordinate) and oleanane (abscissa). Although the trend
in Fig. 8 would appear to be consistent in terms of a
directly proportionate contribution of these two terrigenous indicators, it is noted that previous workers have
identi®ed opposite trends in other basins of southeast
Asia (cf. Murray et al., 1997).
The varying input of allochthonous, angiospermous
debris to the source for these oils displays a geographical component, as indicated in Fig. 9 for the
oleanane/hopane ratio. The variability in sourcing
organic matter evident here represents regional dierences in the type of organic matter deposited by the
Champion (paleo-)delta system (cf. Sandal, 1996; Saller
et al., 1999), which apparently resulted in a relative
increase in transport and deposition of angiosperm
debris in the northeastern portion of the study area.
These conclusions can be extended further when the
source rocks responsible for these oils are eventually
penetrated by oshore drilling.
3.2. Eects of migration
Initial examination of the biomarker ratio data in
Table 2 suggested that the thermal maturity for each of
these oils Ð classically de®ned as the maturity level of
the source rock at the time the oils were expelled Ð is
extremely low. Such an observation is consistent with
the common observation of very low molecular maturity levels for oils reservoired in the clastic sediments of
Tertiary deltas worldwide, and for this reason is not
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
1481
Fig. 5. Gas chromatograms for whole oils from the northern and western portions of the oshore study area (left) and the eastern
portion of the oshore study area (right). The nomenclature above each chromatogram lists (left to right) the sample number (cf.
Table 1), the well name and number, and the top and bottom depths of the tested interval, in feet. The compounds eluting after n-C21
and n-C32 are internal standards. Chromatographic conditions are referenced in the text.
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Fig. 5. (continued)
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
1483
Fig. 6. Distribution of n-alkanes from C20 to C30, plotted as a percentage of the total n-alkanes in this range. Sample numbers listed in
the box are the same as those in Table 1. All compounds measured as peak height.
considered unusual. Furthermore, the correlation
between common molecular maturity parameters of this
dataset (e.g., 20S/20S+20R-ethylcholestane and the
trisnorneohopane/trisnorhopane ratio; Table 2) appears
reasonable. However, other correlations appear substantially more problematic. For example, a linear correlation coecient (r2) of 0.97 is observed between the
20S/20S+20R-ethylcholestane ratio and the diacholestane/cholestane ratio (data in Table 2). Although the
latter ratio has been observed to increase with increasing
maturity (e.g. Curiale, 1992), to our knowledge such an
increase occurs only at maturity levels beyond those
apparent here.
Concerns over these apparent maturity variations
prompted us to consider the current reservoir temperatures for these oils, to assess whether the observed
maturity levels were being ``set'' at the time of migration/entrapment rather than at the time of sourcing.
Using geothermal gradients of Sandal (1996) and an
assumed water bottom temperature for all wells of
10 C, reservoir temperatures for the oil set range from
60 to 94 C. As shown in Fig. 10, both the 20S/20S+
20R-ethylcholestane and the diacholestane/cholestane
ratios correlate with present-day reservoir temperature
(r2=0.83 and 0.92, respectively). Based upon these
observations, we conclude that the biomarker-based
maturity levels that we are measuring re¯ect the presentday maturity of the reservoir, rather than that of the
source rock(s) for these oils.
This phenomenon has been observed previously in
other Tertiary deltaic systems, and is generally classi®ed
as migration-contamination (also referred to as solvent
extraction and hydrocarbon entrainment), de®ned as ``the
emplacement into a migrating ¯uid, via dissolution, of
compounds indigenous to the host stratigraphic section,
and exogenous to the migrating ¯uid itself'' (Curiale and
Bromley, 1996a). Migration-contamination has been
observed in several settings, by RullkoÈtter et al. (1984),
Philp and Gilbert (1986), Bac et al. (1990), Bac and
Schulein (1990), Thompson and Kennicut (1990), Walters (1990), Morelos-Garcia et al. (1993) and Comet et
al. (1993). Several of the maturity indicators for the
Brunei oils (Table 2), including the 20S/20S+20Rethylcholestane ratio, appear to be consistent with this
conclusion. Of particular interest is the observation that
the x-intercept in Fig. 10 Ð i.e. the temperature at
which the 20S/20S+20R-ethylcholestane ratio extrapolates to zero Ð is approximately 15 C. This value is
quite close to the water-bottom temperature in this
region, indicating that this ratio is under the direct control of the present-day thermal regime oshore Brunei.
On the basis of these observations, we conclude that the
Brunei oils serve as a solvent which initially contained
low biomarker concentrations. During migration and/or
after entrapment, this ``solvent'' extracted syndepositional biomarkers (i.e. biomarkers, or their precursors,
that were deposited at the same time as rest of the
lithologic unit) from the reservoir sediments. Additional
support for this contention comes from the occurrence
in the Brunei oils of distinctive ole®ns, including 4and 5-sterenes, diasterenes and oleanenes (J.A. Curiale,
unpublished results). The most obvious contamination of
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Fig. 7. m/z 217.20 (top) and 191.18 (bottom) mass chromatograms for a Juragan-1 oil, shown as a typical oshore Brunei Darussalam
oil. Peak designations correspond to the identities listed in Table 3. Measurements made on whole oils at approximately 5000 mass
resolution; further analytical conditions are referenced in the text.
incoming condensates with syndepositional organic
matter occurs when the migrating condensates contain
very low initial concentrations of a speci®c biomarker or
biomarker suite, relative to the concentrations of these
components available in the migration conduit or the
reservoir rock. This is the case with the observed ole®ns
and with the 5a(H),14a(H),17a(H)-20(S+R)-24-ethylcholestanes discussed above. Migration-contamination
involving other components Ð including terpanes Ð is
less obvious, possibly due to higher initial concentrations of these components in the migrating condensate.
These conclusions raise serious questions about the
viability of using biomarker parameters as source facies
and source maturity indicators in the Brunei oil set
(cf. Curiale and Bromley, 1996a). At the least, the
maturity ratios discussed above appear to be thoroughly
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J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Table 2
Biomarker data, oshore Brunei Darussalam oilsa
Source facies indicators
Sample
number
1L04239
1L04241
1L04242
1L04244
1L04245
1L04247
1L04249
Well name
(depth)
Juragan 2 (2729 m)
Laksamana 1 (2171.5 m)
Laksamana 1 (2982.5 m)
BCS 1 (not available)
Perdana 1 (2762.6 m)
Perdana SEL-1 (1988.7 m)
Juragan 1 (2825.5 m)
Sterane carbon
numberb
C27
C28
C29
29.8
26.2
23.6
26.0
27.6
26.1
29.9
19.5
21.4
18.4
20.9
21.4
21.9
20.1
50.7
52.4
58.0
53.1
50.9
52.1
50.0
H/S
Maturity indicators
c
6.04
3.77
5.58
5.63
5.01
3.20
9.22
Ol/H
35/31-35
Bicad
20S/S+Rg Diasth 22S/S+Ri Ts/Tmj
0.77
1.15
1.52
1.16
1.09
1.18
0.88
0.011
0.023
0.021
0.018
0.020
0.007
0.007
0.85
0.36
0.40
0.48
0.45
0.38
1.09
0.18
0.14
0.19
0.18
0.16
0.12
0.22
d
e
f
0.13
0.09
0.15
0.13
0.11
0.07
0.16
0.53
0.54
0.55
0.55
0.55
0.54
0.54
0.65
0.56
0.68
0.65
0.56
0.56
0.76
a
All ratios measured from peak heights on mass chromatograms from GC/MS-SIR runs at mass resolution of approximately 5000.
Distribution of 5a(H),14a(H),17a(H)-20R steranes by carbon number (%) (from m/z 217.20 trace).
c
17a(H),21b(H)-hopane/5a(H),14a(H),17a(H)-20R-24-ethylcholestane (from m/z 191.18 and 217.20 traces).
d
[18a(H)+18b(H)]-oleanane/17a(H),21b(H)-hopane (from m/z 191.18 trace).
e
17a(H),21b(H)-22(S+R)-C35-hopane/17a(H),21b(H)-22(S+R)-C31-35-hopane (from m/z 191.18 trace).
f
trans-trans-trans-Bicadinane/5a(H),14a(H),17a(H)-20R-24-ethylcholestane (from m/z 217.20 trace)
g
5a(H),14a(H),17a(H)-20S-24-ethylcholestane/5a(H),14a(H),17a(H)-20(S+R)-24-ethylcholestane (from m/z 217.20 trace).
h
13b(H),17a(H)-diacholestane/14a(H),17a(H)-20R-cholestane (from m/z 217.20 trace).
i
17a(H),21b(H)-22S-C31-hopane/17a(H),21b(H)-22(S+R)-C31-hopane (from m/z 191.18 trace).
j
18a(H)-22,29,30-trisnorneohopane/17a(H)-22,29,30-trisnorhopane (from m/z 191.18 trace).
b
Fig. 8. Bivariate plot of the 5a(H),14a(H),17a(H)-20R-24-ethylcholestane/5a(H),14a(H),17a(H)-20R-cholestane ratio (ordinate;
measured as peak height on the m/z 217.20 mass chromatogram) versus the [18a(H)+18b(H)]-oleanane/hopane ratio (abscissa; measured as peak height on the m/z 191.18 mass chromatogram). Data are listed in Table 2, and discussed in the text.
1486
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Fig. 9. Map of oshore Brunei Darussalam, showing the [18a(H)+18b(H)]-oleanane/hopane ratio (in parentheses) in a series of oshore oils. The dark blobs are the major oil and gas ®elds; bathymetry is shown in meters. The northwest-southeast trending lines
oshore represent the Brunei±Malaysia international boundary.
overprinted by contributions from the syndepositional
organic matter in the reservoir sediments. On balance it
would appear, with respect to unravelling the source
characteristics of these oils, that low-concentration
components in the migrating oil are severely compromised by migration-contamination. For this reason, we
have relied for source facies (and source maturity)
determinations upon bulk parameters (e.g. d13C of
whole oil) and those molecular components that are in
suciently high initial concentration so as not to have
been substantially overprinted by syndepositional
organic matter in the reservoir sediments (e.g. n-alkanes
and acyclic isoprenoids). Although our previous source
facies conclusions for these oils remain the same when
using these criteria, we note that assessment of the thermal
maturity of the source rock at the time of expulsion of
these oils is now impossible to determine accurately.
Although reliance on bulk parameters and molecular
suites in relatively high concentration (e.g. d13C values and
n-alkane distributions) provides reasonable estimates of
original source facies for these oils, it is observed that
even parameters such as these may have been in¯uenced
by migration-related phenomenon in oshore Brunei.
Fig. 11 shows the relationship between the extent of
``front-end loading'' in these oils (as measured by the
ratio of the C13 to C22 n-alkanes) and their d13C value.
The trend of increasing d13C values with increasing light
n-alkane bias has been observed in other Tertiary deltaic
oils (Dzou and Hughes, 1993; Curiale and Bromley,
1996b and references therein), and has been attributed
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
1487
Fig. 10. Superimposed bivariate plots of the 5a(H),14a(H),17a(H)-20S/(20R+20S)-24-ethylcholestane ratio (diamond symbols) and
the 13b(H),17a(H)-20S-diacholestane/5a(H),14a(H),17a(H)-20R-cholestane ratio (circle symbols), versus the approximate reservoir
temperature, in degrees Celsius (abscissa).
to migration-fractionation (Curiale and Bromley,
1996b). Even though the parameter variability in Fig. 11
is relatively minor compared to other documented
instances of migration-fractionation, it is noted that this
process has apparently aected the composition of the
Brunei oils to varying extents.
4. Source rock potential
The full sample set was sub-sampled for source rock
analysis with the objective of providing data representative of both location and depositional setting (i.e.
facies). On this basis, of the 72 outcrop samples, 53
samples were chosen for further study. Total organic
carbon (TOC) contents and Rock-Eval pyrolysis yields
are listed in Table 4, categorized by depositional facies
and lithology.
Rock-Eval Tmax data indicate that each of the samples is thermally immature with respect to generation of
liquid hydrocarbons. Tmax values are less than 430 C in
all cases, and less than 410±420 C in most cases.
Although this very low maturity level precludes the use
of this sample set for molecular and isotopic oil±source
rock correlations, conclusions may be derived about the
source rock potential of individual facies and lithologies
of the Brunei stratigraphic succession.
The data in Table 4 are displayed graphically in Figs.
12 and 13, and subdivided in these ®gures according to
depositional facies and lithology. These plots suggest
that the greatest liquid hydrocarbon source rock potential occurs in the tidal and embayment facies, with
hydrogen indices approaching 300 mg/g in coals of the
tidal facies (Fig. 13).
In general, regardless of depositional setting, the
shales of the sample set possess low amounts of organic
matter and the lowest liquid generation potential, and
are likely to produce only gas when thermally mature
Table 3
Peak Assignments
b
c
d
m
o
p
q
s
t
u
v
A
B
C
D
cis-cis-trans-Bicadinane
18a(H)-22,29,30-Trisnorneohopane
trans-trans-trans-Bicadinane
17a(H),21b(H)-30-Norhopane
[18a(H)+18b(H)]-Oleanane
17a(H),21b(H)-Hopane
17b(H),21a(H)-Hopane
17a(H),21b(H)-22S-30-Homohopane
17a(H),21b(H)-22R-30-Homohopane
17a(H),21b(H)-22S-30-Bishomohopane
17a(H),21b(H)-22R-30-Bishomohopane
5a(H),14a(H),17a(H)-20R-Cholestane
5a(H),14a(H),17a(H)-20R-24-Methylcholestane
5a(H),14a(H),17a(H)-20R-24-Ethylcholestane
5a(H),14a(H),17a(H)-20S-24-Ethylcholestane
1488
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Table 4
Source rock dataa
Sample ID
Tidal
Shale
MM-12
MM-14
Coaly shale
KB-14
MM-10
MM-11
SU-3
KB-13
KB-12
KB-11
KB-7
KB-8
KB-5
KB-6
KB-2
KB-3
SA-9
SU-9
SA-4
SA-8
Coal
SA-5
SU-1
SA-2
KB-4
KB-10
KB-9
SU-7
Embayment
Shale
MM-3
MM-2
MM-4
MM-1
Coaly shale
SA-12
MM-8
SU-8
SA-10
SA-1
SU-10
Coal
SA-3
SU-4
SU-5
SU-6
Shoreface
Shale
J-6
MM-5
TOC (%)
S1 (mg/g)
S2 (mg/g)
Tmax ( C)
S3 (mg/g)
HI (mg/g)
OI (mg/g)
3.42
1.05
0.29
0.13
0.75
0.30
403
2.83
0.58
77
29
292
55
1.86
3.05
47.40
3.05
7.89
3.96
8.38
7.00
3.99
34.30
8.96
16.60
16.10
5.38
6.40
8.83
23.50
0.12
0.28
2.70
0.23
1.01
0.20
0.64
0.68
0.29
2.91
1.02
1.16
1.09
1.14
0.50
1.71
2.04
0.55
0.87
22.08
1.80
8.52
1.88
13.18
12.85
1.38
55.83
17.54
15.32
17.22
5.76
3.84
13.57
7.50
417
410
409
417
395
411
405
409
397
401
409
412
403
417
397
422
414
0.50
1.56
41.87
1.45
1.92
1.23
2.11
1.51
1.68
12.50
2.36
9.93
5.29
4.23
1.87
7.14
14.31
30
29
47
59
108
47
157
184
35
163
196
92
107
107
60
154
32
27
51
88
48
24
31
25
22
42
36
26
60
33
79
29
81
61
17.60
20.20
22.80
33.70
60.20
59.10
60.50
5.14
3.67
2.50
2.08
2.55
3.06
6.36
31.06
21.73
18.54
57.08
135.10
95.30
171.13
398
405
408
402
408
412
401
13.98
11.93
11.25
8.33
13.61
25.71
16.13
176
108
81
169
224
161
283
79
59
49
25
23
44
27
1.22
3.41
3.61
6.23
0.14
0.65
0.40
1.35
0.34
1.08
0.86
1.97
392
391
385
0.64
2.35
2.22
4.14
28
32
24
32
52
69
61
66
2.12
2.94
3.92
4.22
5.41
6.06
0.14
0.37
0.29
0.45
0.36
0.76
0.41
1.19
2.20
2.61
4.31
7.12
415
406
399
396
401
406
0.78
1.87
1.06
1.60
1.40
1.71
19
40
56
62
80
117
37
64
27
38
26
28
50.30
60.50
46.10
27.80
2.85
2.65
3.33
3.67
45.23
96.32
91.11
53.06
406
409
401
396
28.09
14.48
15.27
8.57
90
159
198
191
56
24
33
31
3.61
1.02
0.30
0.15
2.80
0.49
412
0.77
0.37
78
48
21
36
(continued overpage)
1489
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Table 1 (continued)
Sample ID
MM-9
SA-6
TOC (%)
S1 (mg/g)
S2 (mg/g)
0.84
1.02
0.08
0.11
0.16
0.49
Tmax ( C)
S3 (mg/g)
HI (mg/g)
OI (mg/g)
0.17
1.38
19
48
20
135
Coaly shale
KB-1
SA-11
SU-11
Coal
SA-7
J-7
JM-5
JM-4
L-7
9.37
2.22
2.52
0.86
0.24
0.26
8.31
0.85
1.41
412
411
419
5.40
0.60
0.66
89
38
56
58
27
26
18.10
1.22
0.85
0.97
1.12
4.21
0.09
0.16
0.12
0.11
26.44
0.35
0.78
0.66
0.70
401
430
431
434
9.58
1.21
0.16
0.39
0.18
146
29
92
68
63
53
99
19
40
16
Coaly shale
J-8
8.67
0.48
8.18
403
2.02
94
23
a
TOC=total organic carbon; S1, S2, hydrocarbons yielded from Rock-Eval pyrolysis; Tmax, temperature at fastest S2 generation
rate; S3, carbon dioxide yielded from Rock-Eval pyrolysis; HI, hydrogen index; OI, oxygen index.
Fig. 11. Bivariate plot of the n-C13/n-C22 ratio (ordinate; measured from peak heights in the whole oil gas chromatograms) vs the
whole oil carbon isotope ratio (abscissa).
(Fig. 13). Data for the coaly shales suggest a similar
conclusion. However, selected coals originating in
environments proximate to the marine setting, including
tidal, lagoonal, embayment and shoreface areas, have
sucient organic matter and generative potential to be
considered as potential sources for both oil and gas
(Fig. 12; Thompson et al., 1985a, b; Wan Hasiah, 1999).
5. Implications and conclusions
It has long been recognized from geochemical studies
that organic matter derived from land plants and
deposited in marine environments is the source of most
of the oil and gas in Brunei (Schreurs, 1996). However,
volumetrically-signi®cant potential source rocks have
1490
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Fig. 12. Plots of the hydrocarbon generation potential (Rock-Eval S1+S2, in mg hydrocarbons/g rock) vs total organic carbon
(TOC,%), for the tidal, embayment, shoreface and shelfal depositional settings. Speci®c lithologies are indicated. Note that the y-axis
is logarithmic, and that the scale of the tidal setting (top left) extends an order of magnitude beyond the scale for the other depositional settings.
neither been observed in outcrop nor penetrated in the
subsurface. As a result, no speci®c source rock interval
has been identi®ed. Although the results of the present
study do not allow us to specify conclusively either the
lithologic unit or the age of the source for the Brunei
oils, several conclusions may be reached from the chemical composition of the oshore oils and the source
rock capabilities of the onshore coals and coaly shales.
The Brunei oils originated from source rocks that
contain mainly allochthonous organic matter (i.e. continental plant debris) deposited in the neritic environment of a pro-delta setting. Although the fundamental
nature of the source facies for each of the oshore oils
in this study is constant, variation in input of autochthonous versus allochthonous organic matter in the
source unit(s) for these oils is apparent from the molecular data. If a single lithologic unit is responsible for
sourcing these oils, the organic matter in that unit must
consists of a mixture of (a) land plant organic matter
and (b) biota from the photic zone of the water column.
Based upon the molecular composition of the oils, our
data show that the ratio of allochthonous to autochthonous organic matter in the source increases to the
northeast. If it is assumed that the quantity of organic
matter generated in the water column photic zone
remains unchanged over this relatively small geographic
area, then it is likely that the dierences in source rock
character result from dierences in the amount (rather
than the quality) of contributed terrigenous organic
matter in the southwest and northeast areas of oshore
Brunei. This is presumably related to speci®c depositional patterns of the Champion paleodelta sediments
(Fig. 3), which are expected to show increasing terrigenous input toward the northeastern part of our study
area.
Although the relative concentrations of these sourcerelated molecular components allow conclusions about
the character of the source rock organic matter, other
hydrocarbon suites have been aected substantially by
the migration process. Our data show evidence for signi®cant extraction, by migrated liquid petroleum, of
syndepositional molecular components that otherwise
would serve as proxies for source rock maturity at the
time of oil expulsion. This overprinting limits the use of
biomarkers as source, maturity and migration indicators
in oils of the Brunei oshore. Of particular concern are
the problems inherent in oil±source rock correlation
eorts when the oils in question contain, in addition to
molecular components generated in the source rock,
biomarkers and biomarker suites dissolved from syndepositional organic matter in the reservoir rocks and/or
migratory conduits. Attempted molecular (and possibly
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
1491
Fig. 13. Adapted van Krevelen plots [Hydrogen Index (HI) vs Oxygen Index (OI), as mg hydrocarbons/g rock and mg carbon dioxide/g rock, respectively] for the tidal, embayment, shoreface and shelfal depositional settings. Speci®c lithologies are indicated.
isotopic) correlations between such oils and their purported source unit(s) will certainly fail if proper consideration is not given to the dilution of sourceindigenous source rock biomarkers by extraneous biomarkers contributed after expulsion. In such instances,
we recommend that conventional biomarker correlations (i.e. those utilizing tetracyclic and pentacyclic aliphatic hydrocarbons) be corroborated with data for
molecular suites that occur in higher relative concentration in the original source (e.g. tricyclic terpanes, alkylated naphthalenes, etc.). Using this approach there is a
greater likelihood that the components in question are
thermogenic products of generation within the source
rock, and the potential for molecular dilution in the
reservoir and migratory conduit will be minimized.
Onshore autochthonous coals and coaly shales may
be used as analogs for the allochthonous coaly intervals
that have sourced the oshore oils (Wan Hasiah, 1999).
Source rock evaluation of a set of 53 shales, coaly shales
and coals indicates that coals proximate to a marine
setting, and particularly those deposited within the tidal
range, have the potential to generate liquid hydrocarbons. Because this potential is yet to be realized for
the coals in our sample set, oil±source rock correlations
are not feasible. Despite the implied source rock information that can be derived from chemical characteristics
of the oils, con®rmed oil±source rock correlations must
await future exploration eorts which result in the
penetration of mature source section, most likely in the
oshore.
Exploration eorts that began in onshore Brunei
about a century ago have since been extended into the
oshore, and will eventually extend to the deepwater
areas farther north and northwest. The success of these
eorts in identifying commercial liquid hydrocarbons
farther oshore will depend, in the ®rst instance, on the
presence of crude oil source rocks in this area. Although
the oils examined here testify only to the presence of
such sources on the inner shelf, the mechanism of moving terrigenous organic matter oshore and supplementing its sourcing capability with autochthonous
organic matter from the photic zone should extrapolate
directly to the deepwater setting, and allow for the prediction of liquid hydrocarbon potential in outer shelf
and slope areas (Anuar and Muhamad, 1997). Our
source rock and oil compositional results provide support for the occurrence of such potential in these outer
waters.
1492
J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493
Acknowledgements
We appreciate the cooperation of the geologists of
Fletcher Challenge Energy Borneo in providing us
access of the oshore oil samples. Conversations with
Sherman Smith, John Baines and Art Saller improved
our understanding of the petroleum systems of Brunei.
We thank Mike Kirby and Baby Ellamil for drafting
assistance, and Paul Peaden and Bernie Wilk for assistance with acquisition of the GC and GC/MS data. E.
Tegelaar (Baseline Resolution Inc.) provided assistance
with identi®cation of ole®ns in the Brunei oils (via GC/
MS/MS analysis). The manuscript was improved as a
result of comments from reviewers S. Imbus and C.
Schiefelbein. We also acknowledge Unocal Corporation
for allowing us to release the data and publish this
paper.
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