Brunei Darussalam
Characteristics of selected petroleums and source rocks
J. Curiale
a,*, J. Morelos
a,1, J. Lambiase
b, W. Mueller
c,2aUnocal Corporation, 14141 Southwest Freeway, Sugar Land, TX 77478, USA
bUniversiti Brunei Darussalam, Petroleum Geoscience, Bandar Seri Begawan BE1410, Negara, Brunei cUnocal Borneo Utara Ltd, Locked Bag #76, Bandar Seri Begawan BS8611, Negara, Brunei
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 mole-cular 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
10 km of Tertiary sedimentary section, contained in basins created by depocenters that have moved exten-sively 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 pro-duced in the past 70 years. Although eorts during the ®rst ®ve decades of exploration (1911±1960) were con-centrated 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. P I I : S 0 1 4 6 - 6 3 8 0 ( 0 0 ) 0 0 0 8 4 - X
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* Corresponding author. Tel.: 281-287-5646; fax: +1-281-287-5403.
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,
al., 1990), including the oshore Brunei oils of the pre-sent 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 con-ventionally considered to be gas-prone, the occurrence of a substantial net thickness of thin, hydrogen-rich stringers of allochthonous organic matter within deep-water 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 Com-pany (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 esti-mated 12,000 km2covering 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 over-lying 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 pre-dominantly 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 suc-cession 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.
origin, and that there is very little dierence between the Belait Formation and the Lambir, Miri and Seria For-mations (Lambiase et al, 2000). Tidal and shoreface sandstones dominate the Belait Formation, and ¯uvial
sandstones are rare to absent in outcrop (Lambiase et al., 2000). Similarly, the exposed coals are closely asso-ciated 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).
debris (M. Simmons, pers. comm.), suggesting deposition in coastal swamps.
The late Miocene to Quaternary Baram Delta succes-sion 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 sand-stones 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±75F).
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
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 con-tinental shelf shales and coaly shales that include sedi-mentary 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 proxi-mity 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 25C/min to 550C).
Table 1
General geochemical data, oshore Brunei Darussalam oilsa
Sample Well Name Reservoir depth (m) d13C (%) n-C
13/n-C22 Pristane/phytane Pristane/n-C17 Phytane/n-C18
1L04239 Juragan 2 2729±2740 ÿ26.97 2.06 4.04 1.05 0.30
1L04240 Juragan 2 2890±2940 ÿ27.06 2.12 4.09 1.04 0.29
1L04241 Laksamana 1 2171.5 ÿ27.29 1.59 3.37 1.35 0.43
1L04242 Laksamana 1 2982.5 ÿ27.21 1.58 3.96 1.07 0.30
1L04243 BCS 1 n.a.b
ÿ26.82 1.78 3.95 0.98 0.26
1L04244 BCS 1 n.a. ÿ27.61 1.65 3.61 1.02 0.30
1L04245 Perdana 1 2762.6 ÿ27.58 1.31 3.48 1.09 0.34
1L04246 Perdana 1 2761±2767 ÿ27.82 1.21 3.42 1.09 0.33
1L04247 Perdana Selatan 1 1988.7 ÿ27.44 1.82 4.22 1.02 0.27
1L04248 Perdana Selatan 1 n.a. ÿ27.20 1.92 4.02 0.98 0.27
1L04249 Juragan 1 2825.5±2863.7 ÿ27.21 1.43 3.42 1.08 0.34
1L04251 Juragan 1 2990±3023 ÿ27.22 1.65 3.79 1.15 0.33
a Chromatographic ratios are calculated from peak heights. b n.a., Not available.
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 spe-ci®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 0.10mm). The injector
tem-perature was 330C, and FID temperature was 350C.
Hydrogen carrier gas was used, and the oven tempera-ture was ramped fromÿ12C (0 min) to 10C (0 min) at
2C/min, and to 350C (held 25 min) at 5C/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 co-injection 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
Then-alkane and isoprenoid distributions for all oils are very similar (see Fig. 5, consisting of two sub-®g-ures, 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. beyondn±C20Ð 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 Muha-mad, 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 C27ÿ30tetracyclic and pentacyclic
hydrocarbons. As is common with many oils of south-east 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 andm/z191.18 mass chromatograms of Fig. 7. Biomarker ratios derived from the mass chromatograms of each of the Brunei oils are listed in Table 2, and sup-port 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 pre-dominantly 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 auto-chthonous 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 terri-genous 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 geo-graphical component, as indicated in Fig. 9 for the oleanane/hopane ratio. The variability in sourcing organic matter evident here represents regional dier-ences 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
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 aftern-C21
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 sub-stantially more problematic. For example, a linear cor-relation coecient (r2) of 0.97 is observed between the
20S/20S+20R-ethylcholestane ratio and the diacholes-tane/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 tempera-tures for these oils, to assess whether the observed maturity levels were being ``set'' at the time of migra-tion/entrapment rather than at the time of sourcing. Using geothermal gradients of Sandal (1996) and an assumed water bottom temperature for all wells of 10C, reservoir temperatures for the oil set range from
60 to 94C. 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 present-day 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), Wal-ters (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+20R -ethylcholestane 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 extra-polates to zero Ð is approximately 15C. This value is
quite close to the water-bottom temperature in this region, indicating that this ratio is under the direct con-trol 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 syndeposi-tional 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 4
-and5-sterenes, diasterenes and oleanenes (J.A. Curiale,
unpublished results). The most obvious contamination of
Fig. 6. Distribution ofn-alkanes from C20to C30, plotted as a percentage of the totaln-alkanes in this range. Sample numbers listed in
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-ethyl-cholestanes discussed above. Migration-contamination
involving other components Ð including terpanes Ð is less obvious, possibly due to higher initial concentra-tions 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
Table 2
Biomarker data, oshore Brunei Darussalam oilsa
Source facies indicators Maturity indicators
Sample number
Well name (depth)
Sterane carbon numberb
H/Sc Ol/Hd 35/31-35e Bicadf 20S/S+Rg Diasth 22S/S+Ri Ts/Tmj
C27 C28 C29
1L04239 Juragan 2 (2729 m) 29.8 19.5 50.7 6.04 0.77 0.011 0.85 0.18 0.13 0.53 0.65 1L04241 Laksamana 1 (2171.5 m) 26.2 21.4 52.4 3.77 1.15 0.023 0.36 0.14 0.09 0.54 0.56 1L04242 Laksamana 1 (2982.5 m) 23.6 18.4 58.0 5.58 1.52 0.021 0.40 0.19 0.15 0.55 0.68 1L04244 BCS 1 (not available) 26.0 20.9 53.1 5.63 1.16 0.018 0.48 0.18 0.13 0.55 0.65 1L04245 Perdana 1 (2762.6 m) 27.6 21.4 50.9 5.01 1.09 0.020 0.45 0.16 0.11 0.55 0.56 1L04247 Perdana SEL-1 (1988.7 m) 26.1 21.9 52.1 3.20 1.18 0.007 0.38 0.12 0.07 0.54 0.56 1L04249 Juragan 1 (2825.5 m) 29.9 20.1 50.0 9.22 0.88 0.007 1.09 0.22 0.16 0.54 0.76
a All ratios measured from peak heights on mass chromatograms from GC/MS-SIR runs at mass resolution of approximately 5000. b Distribution of 5a(H),14a(H),17a(H)-20Rsteranes by carbon number (%) (fromm/z217.20 trace).
c 17a(H),21b(H)-hopane/5a(H),14a(H),17a(H)-20R-24-ethylcholestane (fromm/z191.18 and 217.20 traces). d [18a(H)+18b(H)]-oleanane/17a(H),21b(H)-hopane (fromm/z191.18 trace).
e 17a(H),21b(H)-22(S+R)-C
35-hopane/17a(H),21b(H)-22(S+R)-C31-35-hopane (fromm/z191.18 trace). f trans-trans-trans-Bicadinane/5a(H),14a(H),17a(H)-20R-24-ethylcholestane (fromm/z217.20 trace)
g 5a(H),14a(H),17a(H)-20S-24-ethylcholestane/5a(H),14a(H),17a(H)-20(S+R)-24-ethylcholestane (fromm/z217.20 trace). h 13b(H),17a(H)-diacholestane/14a(H),17a(H)-20R-cholestane (fromm/z217.20 trace).
i 17a(H),21b(H)-22S-C31-hopane/17a(H),21b(H)-22(S+R)-C31-hopane (fromm/z191.18 trace). j 18a(H)-22,29,30-trisnorneohopane/17a(H)-22,29,30-trisnorhopane (fromm/z191.18 trace).
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 compro-mised 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 C13to C22n-alkanes) and theird13C value.
The trend of increasingd13C 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
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 repre-sentative 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-EvalTmax data indicate that each of the
sam-ples is thermally immature with respect to generation of liquid hydrocarbons.Tmaxvalues are less than 430C in
all cases, and less than 410±420C 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 rockpotentialof 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 poten-tial 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
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).
Table 3
Peak Assignments
b cis-cis-trans-Bicadinane
c 18a(H)-22,29,30-Trisnorneohopane d trans-trans-trans-Bicadinane m 17a(H),21b(H)-30-Norhopane o [18a(H)+18b(H)]-Oleanane p 17a(H),21b(H)-Hopane q 17b(H),21a(H)-Hopane
Table 4
Source rock dataa
Sample ID TOC (%) S1 (mg/g) S2 (mg/g) Tmax(C) S3 (mg/g) HI (mg/g) OI (mg/g)
Tidal Shale
MM-12 3.42 0.29 0.75 403 2.83 77 292
MM-14 1.05 0.13 0.30 0.58 29 55
Coaly shale
KB-14 1.86 0.12 0.55 417 0.50 30 27
MM-10 3.05 0.28 0.87 410 1.56 29 51
MM-11 47.40 2.70 22.08 409 41.87 47 88
SU-3 3.05 0.23 1.80 417 1.45 59 48
KB-13 7.89 1.01 8.52 395 1.92 108 24
KB-12 3.96 0.20 1.88 411 1.23 47 31
KB-11 8.38 0.64 13.18 405 2.11 157 25
KB-7 7.00 0.68 12.85 409 1.51 184 22
KB-8 3.99 0.29 1.38 397 1.68 35 42
KB-5 34.30 2.91 55.83 401 12.50 163 36
KB-6 8.96 1.02 17.54 409 2.36 196 26
KB-2 16.60 1.16 15.32 412 9.93 92 60
KB-3 16.10 1.09 17.22 403 5.29 107 33
SA-9 5.38 1.14 5.76 417 4.23 107 79
SU-9 6.40 0.50 3.84 397 1.87 60 29
SA-4 8.83 1.71 13.57 422 7.14 154 81
SA-8 23.50 2.04 7.50 414 14.31 32 61
Coal
SA-5 17.60 5.14 31.06 398 13.98 176 79
SU-1 20.20 3.67 21.73 405 11.93 108 59
SA-2 22.80 2.50 18.54 408 11.25 81 49
KB-4 33.70 2.08 57.08 402 8.33 169 25
KB-10 60.20 2.55 135.10 408 13.61 224 23
KB-9 59.10 3.06 95.30 412 25.71 161 44
SU-7 60.50 6.36 171.13 401 16.13 283 27
Embayment Shale
MM-3 1.22 0.14 0.34 0.64 28 52
MM-2 3.41 0.65 1.08 392 2.35 32 69
MM-4 3.61 0.40 0.86 391 2.22 24 61
MM-1 6.23 1.35 1.97 385 4.14 32 66
Coaly shale
SA-12 2.12 0.14 0.41 415 0.78 19 37
MM-8 2.94 0.37 1.19 406 1.87 40 64
SU-8 3.92 0.29 2.20 399 1.06 56 27
SA-10 4.22 0.45 2.61 396 1.60 62 38
SA-1 5.41 0.36 4.31 401 1.40 80 26
SU-10 6.06 0.76 7.12 406 1.71 117 28
Coal
SA-3 50.30 2.85 45.23 406 28.09 90 56
SU-4 60.50 2.65 96.32 409 14.48 159 24
SU-5 46.10 3.33 91.11 401 15.27 198 33
SU-6 27.80 3.67 53.06 396 8.57 191 31
Shoreface Shale
J-6 3.61 0.30 2.80 412 0.77 78 21
MM-5 1.02 0.15 0.49 0.37 48 36
(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
Table 1 (continued)
Sample ID TOC (%) S1 (mg/g) S2 (mg/g) Tmax(C) S3 (mg/g) HI (mg/g) OI (mg/g)
MM-9 0.84 0.08 0.16 0.17 19 20
SA-6 1.02 0.11 0.49 1.38 48 135
Coaly shale
KB-1 9.37 0.86 8.31 412 5.40 89 58
SA-11 2.22 0.24 0.85 411 0.60 38 27
SU-11 2.52 0.26 1.41 419 0.66 56 26
Coal
SA-7 18.10 4.21 26.44 401 9.58 146 53
J-7 1.22 0.09 0.35 1.21 29 99
JM-5 0.85 0.16 0.78 430 0.16 92 19
JM-4 0.97 0.12 0.66 431 0.39 68 40
L-7 1.12 0.11 0.70 434 0.18 63 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 then-C13/n-C22ratio (ordinate; measured from peak heights in the whole oil gas chromatograms) vs the
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 che-mical 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. con-tinental plant debris) deposited in the neritic environ-ment of a pro-delta setting. Although the fundaenviron-mental nature of the source facies for each of the oshore oils in this study is constant, variation in input of auto-chthonous versus alloauto-chthonous organic matter in the source unit(s) for these oils is apparent from the mole-cular 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 auto-chthonous 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 deposi-tional patterns of the Champion paleodelta sediments (Fig. 3), which are expected to show increasing terrige-nous input toward the northeastern part of our study area.
Although the relative concentrations of these source-related 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 sig-ni®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 synde-positional organic matter in the reservoir rocks and/or migratory conduits. Attempted molecular (and possibly
isotopic) correlations between such oils and their pur-ported source unit(s) will certainly fail if proper con-sideration is not given to the dilution of source-indigenous source rock biomarkers by extraneous bio-markers contributed after expulsion. In such instances, we recommend that conventional biomarker correla-tions (i.e. those utilizing tetracyclic and pentacyclic ali-phatic hydrocarbons) be corroborated with data for molecular suites that occur in higher relative concentra-tion in the original source (e.g. tricyclic terpanes, alky-lated 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 hydro-carbons. 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 infor-mation 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 mov-ing terrigenous organic matter oshore and supple-menting its sourcing capability with autochthonous organic matter from the photic zone should extrapolate directly to the deepwater setting, and allow for the pre-diction of liquid hydrocarbon potential in outer shelf and slope areas (Anuar and Muhamad, 1997). Our source rock and oil compositional results provide sup-port for the occurrence of such potential in these outer waters.
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 assis-tance 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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