brunei darussalam characteristics of selected petroleums ...directory.umm.ac.id/data...

Brunei DarussalamCharacteristics 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, BruneicUnocal 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 andshales comprising the sources and reservoirs for crude oils that occur onshore, near-o�shore and, with futureexploration e�orts, those likely to be encountered in deepwater reservoirs north of the Brunei coastline. We examined a

series of o�shore oils and onshore rock samples in Brunei Darussalam (a) to delineate oil family groups and theirsource rock characteristics, and (b) to assess the source potential of the sedimentary sequence with respect to lithologyand depositional setting. Twelve o�shore oils and 53 shales, coaly shales and coals were examined. The oils containindicators 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 inthe sample set (e.g. allochthonous input appears to increase in o�shore 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 contaminationhas resulted in strong correlations between certain molecular maturity indicators and the present-day temperature ofthe 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. Thethermal immaturity of the sample set precludes valid oil±source rock correlations without conducting arti®cialmaturation 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 ofthe island of Borneo, sharing that island with parts of

Malaysia and Indonesia. The occurrence of more than

10 km of Tertiary sedimentary section, contained inbasins 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 in1899, and large amounts of petroleum have been pro-

duced in the past 70 years. Although e�orts during the®rst ®ve decades of exploration (1911±1960) were con-centrated onshore, the past 30 years have seen increasing

o�shore exploration and discovery.Petroleum geochemistry studies of Brunei oils began

indirectly with Grantham (1986), who ®rst noticed aseries of ``resin compounds'' in thermal extracts of fossil

Brunei resins. These compounds were subsequentlyidenti®ed as bicadinanes, and have since been observedin several Tertiary oils of southeast Asia (van Aarssen et

0146-6380/00/$ - see front matter # 2000 Elsevier Science Ltd. All rights reserved.

PI I : S0146-6380(00 )00084-X

Organic Geochemistry 31 (2000) 1475±1493

www.elsevier.nl/locate/orggeochem

* Corresponding author. Tel.: +1-281-287-5646; 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,

Midland, TX 79701, USA.

al., 1990), including the o�shore Brunei oils of the pre-sent study. The same compounds were observed byHitam and Scherer (1993) in both onshore and o�shoreBrunei oils, an observation consistent with generation of

low-heterocompound crude from a source facies rich inangiospermous (resinous) land plant debris (Sandal,1996). The low-sulfur oils generated from these coals

and coaly shales were later subjected to in-reservoirbiodegradation where burial depths are less than 1500 m.Source rock studies in Brunei, summarized by Sandal

(1996), have been unsuccessful in identifying substantialthicknesses of oil-prone section. The scant geologicaland geochemical evidence for the origin of the Brunei

oils suggests that terrigenous organic matter depositedat 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-richstringers of allochthonous organic matter within deep-water marine sections is postulated as the primary source

material for the liquid hydrocarbons both onshore ando�shore Brunei (cf. Thompson et al., 1985a).In this study, we evaluate a series of crude oils and

condensates from o�shore Brunei, and a set of shales,coaly shales and coals from onshore outcrops, usingsource rock, carbon isotopic and molecular marker

analysis techniques (Curiale et al., 1999). Our objectivesare to de®ne the character of o�shore Brunei oils, todeduce the depositional setting of the responsible sourcerock(s) and the type and variation of organic matter in

these rock(s), and to place this information into anexploration context in o�shore Brunei Darussalam.

1.2. Exploration history in Brunei

Sandal (1996) provides an excellent, detailed history

of petroleum exploration in Brunei Darussalam, withemphasis on the role of Brunei Shell Petroleum Com-pany (BSP), and much of this section is summarizedfrom this source. Oil seepages across the Malaysian

border in northern Sarawak, Malaysia, were ®rst reportedin the middle of the 19th century, and subsequent drillingresulted in the 1910 discovery of the Miri ®eld, which

became the ®rst commercial oil®eld in northwesternBorneo. Exploration in Brunei Darussalam began in1899 with a 198 m hole near Bandar Seri Begawan, the

present day capital, and the Belait-2 well was the ®rst tostrike oil. The ®rst commercial oil ®eld was the Seria®eld, discovered by Shell in 1929.

Exploration o�shore Brunei began in the 1950s, andthe ®rst o�shore well was drilled in 1957. Since 1965approximately 70,000 km of 2D seismic have beenacquired in Brunei Darussalam. Since the late 1980s,

seismic acquisition has been mostly 3D, with an esti-mated 12,000 km2 covering virtually the entire shelf andslope areas. From 1913 to 1999, operators have drilled

204 exploration wells, including 129 o�shore and 75onshore (Fig. 1). From these activities, 13 commerciallyexploitable oil and gas ®elds have been found, asshown in Fig. 2. The country's current production is in

excess of 150,000 bopd and 1,100 mmcfgpd. AlthoughBSP is by far the major producer in Brunei, there arecurrently three other petroleum concession holders, all

joint ventures of Unocal, Fletcher Challenge and ElfAquitaine.

1.3. Stratigraphic framework

The Neogene sediments in Brunei and adjacent

Malaysia consist of up to 10 km of sandstones andshales assigned to three deltaic complexes that generallyyoung from east to west (Koopman, 1996; van Borren etal., 1996). The oldest of the three, the Meligan Delta,

originated in the Paleogene, with deposition of theTemburong and Meligan Formations continuing intothe 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 theSetap, 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 (vanBorren et al., 1996). It ranges from early to middleMiocene and becomes progressively younger to thenorthwest (van Borren et al., 1996). The Setap shales

were deposited in an open marine, relatively distalenvironment and represent basinal equivalents of themore sandy, deltaic facies.

The Belait Formation, a dominantly sandstone suc-cession with interbedded shales and coals, spans the earlyto late Miocene and comprises the entire Champion

Delta depositional system in much of Brunei (Fig. 3). Itis a lateral equivalent of the Setap Formation shales inthe early and middle Miocene and of the Lambir, Miriand Seria Formations in the middle and late Miocene.

Much of the Belait Formation has been interpreted ascoastal and coastal plain deposits from a range of sedi-mentary environments associated with a relatively large

delta (Wilford, 1961). The sandstones have been describedas 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 moremarine (van Borren et al., 1996). However, recent outcropstudies indicate that a wide range of coastal and marine

environments is represented in the Belait Formation(Lambiase et al., 2000). Facies associations suggest thatmuch of the Belait Formation was deposited in structu-rally-controlled, tide-dominated coastal embayments

and on open marine coastlines rather than as part of adelta. This implies that the Champion Delta is a com-plex depositional system of primarily shallow marine

1476 J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493

origin, and that there is very little di�erence between theBelait Formation and the Lambir, Miri and Seria For-mations (Lambiase et al, 2000). Tidal and shorefacesandstones dominate the Belait Formation, and ¯uvial

sandstones are rare to absent in outcrop (Lambiase etal., 2000). Similarly, the exposed coals are closely asso-ciated with tidal deposits, and palynological analysisindicates 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 o�shore Brunei Darussalam. Oil and gas ®elds are also indicated. Adapted from Sandal (1996), and with

contributions from W. Ade and S. Smith.

J. Curiale et al. / Organic Geochemistry 31 (2000) 1475±1493 1477

debris (M. Simmons, pers. comm.), suggesting depositionin coastal swamps.

The late Miocene to Quaternary Baram Delta succes-sion is the youngest of the three deltaic systems. InBrunei, it is represented by the Liang Formation whichunconformably 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 of12 oils sampled from Miocene reservoir sands of sixexploration wells, as part of Unocal's exploration focuson the o�shore region of Brunei (Fig. 2). Well names

and reservoir depths are listed in Table 1. The wells arelocated 60±90 km o�shore, 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 hadoriginally been recovered from the wells from months toyears prior to subsampling for this project. Sample storageduring this time was at ambient temperatures (70±75�F).

In addition, 72 onshore outcrop samples from Bruneiwere taken for source rock analyses, and for use asfacies analogs for source rocks in the o�shore region.

All were collected from the Belait Formation within theBerakas Syncline, and all range from middle to lateMiocene (Fig. 4). This sample set represents strata from

twomajor depositional settings, speci®cally tide-dominatedcoastal embayment and continental shelf, of varyingages that crop out at di�erent 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 environmentsinclude shales, coals and coaly shales that were collectedfrom low energy, muddy facies that are interbedded

Fig. 3. Neogene lithostratigraphy of Brunei (after Sandal, 1996).


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 interbeddedwith lower shoreface sandstones to middle(?) shelf.

Many of these samples contain a signi®cant amount ofterrestrially-derived organic matter, suggesting proxi-mity to a river and/or delta.

2.2. Geochemical analyses

The crude oils examined here were originally collectedduring o�shore production tests, and maintained at

ambient temperatures prior to analysis. E�orts weremade to collect the rock samples from below theweathering layer, although the intensity of weathering inBrunei made this impossible at times. Rock samples

were analyzed for total organic carbon content (LECOcarbon analyzer) and Rock Eval pyrolysis yields(ramped at 25�C/min to 550�C).

Table 1

General geochemical data, o�shore Brunei Darussalam oilsa

Sample Well Name Reservoir depth (m) d13C (%) n-C13/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.

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.


Whole oil stable carbon isotope, gas chromatographic(GC) and gas chromatographic±mass spectrometric(GC/MS) techniques were identical to those reportedpreviously (Curiale and Stout, 1993; Curiale andGibling,

1994; Curiale and Bromley, 1996a, b), except where spe-ci®ed otherwise. Isotopic measurements were made onwhole, untopped oils, and are reported in % (per mil)

notation relative to the PDB primary standard. Wholeoil GC analyses were conducted using a J&W 122-1061column (60 m�0.25 mm, id 0.10 mm). The injector tem-

perature was 330�C, and FID temperature was 350�C.Hydrogen carrier gas was used, and the oven tempera-ture 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) coupledto 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 usedfor semi-quantitative determinations, based upon co-injection of 5b-cholane (100 ppm) as an internal standard.

All molecular ratios presented here are based on peakheights, using speci®c mass chromatograms as indicatedin the tables and ®gures.

3. Crude oil characteristics

3.1. E�ects 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-®g-ures, each showing six GC traces) Ð all samples arepara�nic, with depleted light ends and pristane/phytane

ratios (measured from peak height) of 3.4±4.1. The patternof light-end loss does not appear to be a function ofeither geographic location or reservoir depth, althoughminor loss of light ends may have resulted from storage

conditions prior to analysis. Where light-end loss doesnot appear to be a factor Ð i.e. beyond n±C20 Ð the oilshave 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 isotopicsimilarity of these Brunei oils with those of o�shoreSarawak (Malaysia) to the northeast (Anuar and Muha-

mad, 1997) suggest that this characteristic organic faciesmay 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 pentacyclichydrocarbons. 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 numberdistributions are dominated by the C29 homologue.Typical distributions of bicadinanes, oleanane C27ÿ29steranes 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 chromatogramsof each of the Brunei oils are listed in Table 2, and sup-

port the alkane-based conclusion that a similar organicfacies is responsible for these oils.Detailed examination of the molecular data suggests

that the organic facies that gave rise to these o�shoreBrunei oils contains organic matter that is pre-dominantly land-plant derived (i.e. allochthonous), with

variable admixtures of autochthonous, algal-derivedorganic matter from the water column directly abovethe site of deposition. The dominance of allochthonousorganic matter is indicated by elevated pristane/phytane

ratios (Table 1) and the presence of bicadinanes in allsamples. The occurrence of autochthonous organicmatter 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, wherevarying amounts of angiospermous organic input aremonitored by the (relative) contents of ethylcholestane

(ordinate) and oleanane (abscissa). Although the trendin Fig. 8 would appear to be consistent in terms of adirectly proportionate contribution of these two terri-genous indicators, it is noted that previous workers have

identi®ed opposite trends in other basins of southeastAsia (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 theoleanane/hopane ratio. The variability in sourcing

organic matter evident here represents regional di�er-ences in the type of organic matter deposited by theChampion (paleo-)delta system (cf. Sandal, 1996; Salleret al., 1999), which apparently resulted in a relative

increase in transport and deposition of angiospermdebris in the northeastern portion of the study area.These conclusions can be extended further when the

source rocks responsible for these oils are eventuallypenetrated by o�shore drilling.

3.2. E�ects of migration

Initial examination of the biomarker ratio data in

Table 2 suggested that the thermal maturity for each ofthese oils Ð classically de®ned as the maturity level ofthe source rock at the time the oils were expelled Ð isextremely low. Such an observation is consistent with

the common observation of very low molecular matur-ity levels for oils reservoired in the clastic sediments ofTertiary deltas worldwide, and for this reason is not


Fig. 5. Gas chromatograms for whole oils from the northern and western portions of the o�shore study area (left) and the eastern

portion of the o�shore 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.


Fig. 5. (continued)


considered unusual. Furthermore, the correlation

between common molecular maturity parameters of thisdataset (e.g., 20S/20S+20R-ethylcholestane and thetrisnorneohopane/trisnorhopane ratio; Table 2) appearsreasonable. However, other correlations appear sub-

stantially more problematic. For example, a linear cor-relation coe�cient (r2) of 0.97 is observed between the20S/20S+20R-ethylcholestane ratio and the diacholes-

tane/cholestane ratio (data in Table 2). Although thelatter ratio has been observed to increase with increasingmaturity (e.g. Curiale, 1992), to our knowledge such an

increase occurs only at maturity levels beyond thoseapparent here.Concerns over these apparent maturity variations

prompted us to consider the current reservoir tempera-

tures for these oils, to assess whether the observedmaturity 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 anassumed water bottom temperature for all wells of10�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/cholestaneratios correlate with present-day reservoir temperature

(r2=0.83 and 0.92, respectively). Based upon theseobservations, we conclude that the biomarker-basedmaturity 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 ``theemplacement into a migrating ¯uid, via dissolution, ofcompounds indigenous to the host stratigraphic section,and exogenous to the migrating ¯uid itself'' (Curiale and

Bromley, 1996a). Migration-contamination has beenobserved in several settings, by RullkoÈ tter 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 etal. (1993). Several of the maturity indicators for the

Brunei oils (Table 2), including the 20S/20S+20R-ethylcholestane ratio, appear to be consistent with thisconclusion. Of particular interest is the observation thatthe 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 15�C. This value isquite 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 o�shore Brunei.On the basis of these observations, we conclude that the

Brunei oils serve as a solvent which initially containedlow biomarker concentrations. During migration and/orafter entrapment, this ``solvent'' extracted syndeposi-

tional biomarkers (i.e. biomarkers, or their precursors,that were deposited at the same time as rest of thelithologic unit) from the reservoir sediments. Additionalsupport for this contention comes from the occurrence

in the Brunei oils of distinctive ole®ns, including �4-and �5-sterenes, diasterenes and oleanenes (J.A. Curiale,unpublished results). The most obvious contamination of

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.


incoming condensates with syndepositional organic

matter occurs when the migrating condensates containvery low initial concentrations of a speci®c biomarker orbiomarker suite, relative to the concentrations of thesecomponents available in the migration conduit or the

reservoir rock. This is the case with the observed ole®nsand 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, thematurity ratios discussed above appear to be thoroughly

Fig. 7. m/z 217.20 (top) and 191.18 (bottom) mass chromatograms for a Juragan-1 oil, shown as a typical o�shore 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.


Table 2

Biomarker data, o�shore Brunei Darussalam oilsa

Source facies indicators Maturity indicators

Sample

number

Well name

(depth)

Sterane carbon

numberbH/Sc Ol/Hd 35/31-35e Bicadf 20S/S+Rg Diasth 22S/S+Ri Ts/Tm

j

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)-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).

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; mea-

sured as peak height on the m/z 191.18 mass chromatogram). Data are listed in Table 2, and discussed in the text.


overprinted by contributions from the syndepositionalorganic matter in the reservoir sediments. On balance it

would appear, with respect to unravelling the sourcecharacteristics of these oils, that low-concentrationcomponents in the migrating oil are severely compro-

mised by migration-contamination. For this reason, wehave relied for source facies (and source maturity)determinations upon bulk parameters (e.g. d13C of

whole oil) and those molecular components that are insu�ciently high initial concentration so as not to havebeen substantially overprinted by syndepositionalorganic matter in the reservoir sediments (e.g. n-alkanes

and acyclic isoprenoids). Although our previous sourcefacies conclusions for these oils remain the same whenusing these criteria, we note that assessment of the thermal

maturity of the source rock at the time of expulsion ofthese oils is now impossible to determine accurately.

Although reliance on bulk parameters and molecularsuites in relatively high concentration (e.g. d13C values andn-alkane distributions) provides reasonable estimates of

original source facies for these oils, it is observed thateven parameters such as these may have been in¯uencedby migration-related phenomenon in o�shore Brunei.

Fig. 11 shows the relationship between the extent of``front-end loading'' in these oils (as measured by theratio 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 deltaicoils (Dzou and Hughes, 1993; Curiale and Bromley,1996b and references therein), and has been attributed

Fig. 9. Map of o�shore Brunei Darussalam, showing the [18a(H)+18b(H)]-oleanane/hopane ratio (in parentheses) in a series of o�-

shore oils. The dark blobs are the major oil and gas ®elds; bathymetry is shown in meters. The northwest-southeast trending lines

o�shore represent the Brunei±Malaysia international boundary.


to migration-fractionation (Curiale and Bromley,1996b). Even though the parameter variability in Fig. 11is relatively minor compared to other documented

instances of migration-fractionation, it is noted that thisprocess has apparently a�ected the composition of theBrunei oils to varying extents.

4. Source rock potential

The full sample set was sub-sampled for source rockanalysis 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, 53samples were chosen for further study. Total organiccarbon (TOC) contents and Rock-Eval pyrolysis yields

are listed in Table 4, categorized by depositional faciesand lithology.Rock-Eval Tmax data indicate that each of the sam-

ples is thermally immature with respect to generation ofliquid hydrocarbons. Tmax values are less than 430�C inall cases, and less than 410±420�C in most cases.

Although this very low maturity level precludes the useof this sample set for molecular and isotopic oil±sourcerock correlations, conclusions may be derived about thesource 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 suggestthat 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 thetidal facies (Fig. 13).In general, regardless of depositional setting, the

shales of the sample set possess low amounts of organicmatter and the lowest liquid generation potential, andare 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

s 17a(H),21b(H)-22S-30-Homohopane

t 17a(H),21b(H)-22R-30-Homohopane

u 17a(H),21b(H)-22S-30-Bishomohopane

v 17a(H),21b(H)-22R-30-Bishomohopane

A 5a(H),14a(H),17a(H)-20R-Cholestane

B 5a(H),14a(H),17a(H)-20R-24-Methylcholestane

C 5a(H),14a(H),17a(H)-20R-24-Ethylcholestane

D 5a(H),14a(H),17a(H)-20S-24-Ethylcholestane


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

(continued overpage)


(Fig. 13). Data for the coaly shales suggest a similarconclusion. However, selected coals originating inenvironments proximate to the marine setting, includingtidal, lagoonal, embayment and shoreface areas, have

su�cient organic matter and generative potential to beconsidered 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 studiesthat organic matter derived from land plants and

deposited in marine environments is the source of mostof 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 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).


neither been observed in outcrop nor penetrated in thesubsurface. As a result, no speci®c source rock intervalhas been identi®ed. Although the results of the present

study do not allow us to specify conclusively either thelithologic unit or the age of the source for the Bruneioils, several conclusions may be reached from the che-

mical composition of the o�shore oils and the sourcerock 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 fundamentalnature of the source facies for each of the o�shore oils

in this study is constant, variation in input of auto-chthonous versus allochthonous organic matter in thesource unit(s) for these oils is apparent from the mole-

cular data. If a single lithologic unit is responsible forsourcing these oils, the organic matter in that unit mustconsists 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, ourdata 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 organicmatter generated in the water column photic zoneremains unchanged over this relatively small geographic

area, then it is likely that the di�erences in source rockcharacter result from di�erences in the amount (ratherthan the quality) of contributed terrigenous organic

matter in the southwest and northeast areas of o�shoreBrunei. 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 studyarea.Although the relative concentrations of these source-

related molecular components allow conclusions aboutthe character of the source rock organic matter, otherhydrocarbon suites have been a�ected substantially by

the migration process. Our data show evidence for sig-ni®cant extraction, by migrated liquid petroleum, ofsyndepositional molecular components that otherwise

would serve as proxies for source rock maturity at thetime of oil expulsion. This overprinting limits the use ofbiomarkers as source, maturity and migration indicators

in oils of the Brunei o�shore. Of particular concern arethe problems inherent in oil±source rock correlatione�orts when the oils in question contain, in addition tomolecular components generated in the source rock,

biomarkers and biomarker suites dissolved from synde-positional organic matter in the reservoir rocks and/ormigratory conduits. Attempted molecular (and possibly

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 deposi-

tional settings.


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 arethermogenic products of generation within the sourcerock, 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 o�shore oils (Wan Hasiah, 1999).Source rock evaluation of a set of 53 shales, coaly shalesand coals indicates that coals proximate to a marinesetting, and particularly those deposited within the tidal

range, have the potential to generate liquid hydro-carbons. Because this potential is yet to be realized forthe 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 characteristicsof the oils, con®rmed oil±source rock correlations mustawait future exploration e�orts which result in the

penetration of mature source section, most likely in theo�shore.Exploration e�orts that began in onshore Brunei

about a century ago have since been extended into the

o�shore, and will eventually extend to the deepwaterareas farther north and northwest. The success of thesee�orts in identifying commercial liquid hydrocarbons

farther o�shore will depend, in the ®rst instance, on thepresence of crude oil source rocks in this area. Althoughthe oils examined here testify only to the presence of

such sources on the inner shelf, the mechanism of mov-ing terrigenous organic matter o�shore and supple-menting its sourcing capability with autochthonous

organic matter from the photic zone should extrapolatedirectly to the deepwater setting, and allow for the pre-diction of liquid hydrocarbon potential in outer shelfand slope areas (Anuar and Muhamad, 1997). Our

source rock and oil compositional results provide sup-port for the occurrence of such potential in these outerwaters.

Fig. 13. Adapted van Krevelen plots [Hydrogen Index (HI) vs Oxygen Index (OI), as mg hydrocarbons/g rock and mg carbon diox-

ide/g rock, respectively] for the tidal, embayment, shoreface and shelfal depositional settings. Speci®c lithologies are indicated.


Acknowledgements

We appreciate the cooperation of the geologists ofFletcher Challenge Energy Borneo in providing us

access of the o�shore oil samples. Conversations withSherman Smith, John Baines and Art Saller improvedour understanding of the petroleum systems of Brunei.

We thank Mike Kirby and Baby Ellamil for draftingassistance, and Paul Peaden and Bernie Wilk for assis-tance with acquisition of the GC and GC/MS data. E.

Tegelaar (Baseline Resolution Inc.) provided assistancewith 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 Corporationfor allowing us to release the data and publish thispaper.

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