Post-generative alteration eects on petroleum in the onshore
Northwest Java Basin, Indonesia
Haposan Napitupulu
a,b, Leroy Ellis
c,d,*, Richard M. Mitterer
b aPertamina EP Jl. Merdeka Timur No.6, Jakarta 10110, IndonesiabUniversity of Texas at Dallas, Richardson, TX 75083-0688, USA
cARCO Exploration and Production Technology, 2300 West Plano Parkway, Plano, TX 75075-8499, USA dTerra Nova Technologies, PMB 409, 18352 Dallas Pkwy, Ste. 136, Dallas, TX 75287, USA
Received 15 March 1998; accepted 4 November 1999 (returned to author for revision 15 June 1998)
Abstract
Northwest Java Basin oils, largely derived from the ¯uvial-deltaic to nearshore marine Talangakar formation of Oli-gocene to Early Miocene, range from heavy oils to extremely light oils and retrograde condensates, with API gravities of a suite of oils ranging from about 17to 53. Heavy oils, with API gravities less than 22, all of which are in shallow
reservoirs, are biodegraded. Pristine oils concomitant with related derivative residual and retrograde condensate oil types indicate evaporative fractionation phenomena. Post-generative alteration processes are widespread in this highly faulted region. Pristane to phytane biomarker ratios of retrograde condensates and residual oils have been shown to be severely aected by evaporative fractionation. Principal component analysis (PCA) of isotope and biomarker data identi®ed two oil families associated with source rocks of the Talangakar formation. One group is suggested to be derived from more marine in¯uenced delta-front to prodelta depositional settings, while the second group is attributed to a higher plant-rich delta-plain to delta-front depositional environment. Correlation of these oil families with the varied depositional environments of the Talangakar formation has allowed a more re®ned approach to the identi®cation of hydrocarbon migration pathways in the Northwest Java Basin. Multivariate statistical analysis is shown to be an eec-tive tool in correlating high gravity condensate oil types.#2000 Elsevier Science Ltd. All rights reserved.
Keywords:Oil; Condensate; Evaporative fractionation; Water washing; Biodegradation; Principal component analysis (PCA); NW Java Basin
1. Introduction
Crude oil compositions, although initially controlled by the nature and maturity of organic matter in the source rock, are subject to a complex series of sub-sequent compositional modi®cations that may occur during migration and within the reservoir (Lafargue and Barker, 1988). Gross changes in oil composition are generally attributed to thermal maturation and bio-degradation eects. Thermal maturation, a consequence of increasing burial depth and higher temperature, will
form increasingly lighter gravity oils until extreme tem-peratures result in cracking of the parent kerogen and/ or oil to gas. By contrast, biodegradation by subsurface microbial communities at shallow depths leads to hea-vier (or low API gravity) oils. In addition, more com-plex phenomena involving evaporative fractionation, water washing, deasphalting, mineral catalysis, gravity segregation, subsurface PVT (pressure-volume-tempera-ture) eects, and dewaxing may all contribute, to vary-ing extents, to alteration of crude oils either in the reservoir or along migration pathways.
Light oils (usually from 30 to 50API gravity) and/or
retrograde condensates (ranging up to 60API gravity)
may, in most cases, be de®ned as the low molecular weight portion of crude oils that becomes entrained/miscible with
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 ( 9 9 ) 0 0 1 5 4 - 0
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* Corresponding author.
a gas phase, and transported away from the primary crude oil reservoir. This re-migration tends to be direc-ted along permeable stratigraphic units or faults to shallower reservoir depths where lower geothermal temperatures and pressures result in the entrained ¯uids condensing to a separate liquid phase. The new reservoir is, therefore, partitioned into a two-phase gas±liquid system, similar to the parent reservoir that sourced the hydrocarbons. Other occurrences of light oils may be attributed to overmature products derived directly from the parent kerogen at late stages of catagenesis/early metamorphism (Hunt, 1996). Oils of this type are the result of thermal cleavage reactions, which tend to pro-duce a greater proportion ofn-alkanes relative to bran-ched and cyclic alkanes (Philippi, 1975). Condensates (usually > 50API gravity) may be de®ned as a natural
wet gas accumulation in which liquid hydrocarbons, such as those comprising the gasoline range, exist toge-ther with gases in a single phase at some equilibrium de®ned by PVT conditions in the reservoir (McCain 1973; Hunt, 1996). At surface temperatures and pres-sures, liquids may condense from these `wet gases' and form extremely light API gravity ¯uids (i.e., con-densates). Two of the most important processes respon-sible for the formation and alteration of light oils and retrograde condensates are evaporative fractionation and water washing.
1.1. Evaporative fractionation
The term evaporative fractionation is suggested for the complex PVT phenomena involved in the phase-separation of gas from reservoired oil (Thompson, 1983). In this process, the original reservoir becomes oversaturated as a consequence of reservoir pressure depletion, or through additional hydrocarbon charging, involving migration of methane and other migrated light hydrocarbons (C2±C5) from the original source
rock that has now reached the gas window. Over®lling of the reservoir capacity past spill point permits the escape and re-migration of gases and ¯uids. Other sce-narios may involve loss of gases from the parent reser-voir, perhaps due to faulting, overburden removal, seismic activity, or simply leakage (e.g. via micro-fracturing) through a gas-permeable seal rock that allows only movement of gases, and other low mole-cular weight components. In all cases, gases serve as the mobile phase in which entrained hydrocarbon liquids are distributed vertically and/or horizontally along `paths of least resistance' in the sedimentary sequence before ®nally reaching a new reservoir or escaping to the surface. As gases migrate upward, carrying entrained oil, subsurface pressure is reduced, and heavier hydro-carbon components in the gas phase liquefy and con-dense enroute. Hence, as pressure and temperature decrease at shallower depths, new gas±liquid phase PVT
equilibria are continuously established, ultimately resulting in the shallowest oils and condensates being the highest API gravity ¯uids (assuming no microbial degradation). The process of evaporative fractionation is likely to be continuous, with hydrocarbon ¯uids redistributing and accumulating on multiple occasions by the same process within the generative basin, until eventually only dry or wet gas accumulations exist in a reservoir (Thompson, 1987, 1988). The frequency of occurrence of gas-condensate accumulations depends upon the frequency of occurrence of the separation process, which in turn, depends upon the frequency of fault movement and ultimately upon the availability and supply of hydrocarbon gases to the trap. The total distance that oil and condensate may remigrate to other traps can vary from a few hundred meters to more than one hundred kilometres (Vandenbroucke et al., 1983).
A consequence of the evaporative fractionation pro-cess is the formation of ``derivative'' light oils (retro-grade condensates), condensates and residual oils from the ``pristine'' parent oils. In each case, gross composi-tional changes in the hydrocarbon components of the gases and liquids take place (Thompson, 1987). In the evaporative fractionation process, low molecular weight saturated hydrocarbons are preferentially incorporated into the vapour phase, relative to aromatic components, and tend to remigrate from the original reservoir. Non-biodegraded and remigrated light oils or condensates, are generally reservoired at shallower depths, and will typically exhibit an enrichment in light ends andn -par-ans concomitant with higher API gravities relative to the parent oil. By comparison, residual oils, which are generally found in deeper reservoirs, usually show a loss of light ends and an increase in aromaticity concomitant with lower API gravities relative to the parent oil (Thompson, 1987; Dzou and Hughes, 1993; Curiale and Bromley, 1996; Hunt, 1996).
Dzou and Hughes (1993) investigated the K ®eld oils, oshore Taiwan, which produce predominantly gas along with small amounts of liquid hydrocarbons. Gases and liquids from these ®elds could be correlated to the same deltaic source rock and maturity, thus invoking a suspected process of evaporative fractiona-tion of deeper, initially remigrated oil. Hunt (1996) used bulk properties, GC patterns, and fractionation index plus the B value (Toluene/n-C7) to identify oils that
pattern in C5±C7 n-alkane distributions on the gas
chromatogram (Holba et al., 1996).
1.2. Water washing and biodegradation
Crude oils may be substantially altered during migra-tion, or in the reservoir, by water washing concomitant with biodegradation (Seifert and Moldowan, 1979; Lafargue and Barker, 1988). Biodegradation involves microbial alteration of crude oil in the reservoir and may be possible whenever the oil pool is in contact with shallow meteoric waters. Among the saturated hydro-carbon classes, normal alkanes are the ®rst compound type consumed by bacteria. Hence, biodegraded oils can usually be characterized by the absence, or presence of very low concentrations, ofn-alkanes, simple branched alkanes and alkylcyclohexanes relative to isoprenoid or bicyclic alkanes that are more resistant to microbial alteration (Evans et al., 1971; Volkman et al., 1983).
Water washing is particularly eective within the low-boiling range of hydrocarbons and results in a decreased API gravity, followed by sequestering of low molecular weight aromatics (i.e., benzene, toluene) before light alkanes and naphthenes are removed (Connan, 1984; Palmer, 1984). Conditions favorable for water washing are known to exist during oil migration, especially when oil is migrating through a hydrologically active water-wet carrier bed and reservoir system. Water washing without concomitant biodegradation is indicated by: (1) a decrease in the amount of aromatic and low molecular weight n-alkanes while naphthenes are unaltered, (2) partial removal of C15+ aromatics while C15+ alkanes
are unaected, and (3) a decrease in sulphur-bearing aromatics (especially dibenzothiophene) (Palmer, 1984; Lafargue and Barker, 1988). In most cases, the loss of benzene and toluene is a good indicator that water washing has occurred. However, in cases where there is a complete absence of gasoline range components or light ends, loss of higher molecular weight species such as dibenzothiophene relative to phenanthrene may also prove to be a good indicator (Palmer, 1984).
Biodegradation and water washing processes often occur together. Assessing the extent of water washing on migrating and reservoired crude oils is dicult because of the more dominant eect of microbial alteration of the oil. Biodegradation typically occurs in the shallowest reservoirs in a basin where viable bacterial communities in meteoric waters commonly exist and are transported, in some cases, along with migrating waters to reservoirs. With time, an active hydrologic system, and favorable static subsurface conditions, microbial alteration of crude oil may be extremely pronounced and lead to signi®cant changes in the gross compositional matrix of the oil (Lafargue and Barker, 1988; Peters and Moldowan, 1993). In cases such as these, the eects of biodegradation far exceed those of water washing. In
deeper reservoirs and associated migration conduits, bacteria communities are less likely to be viable mainly due to the eects of increasing temperature. In these scenarios, water washing eects can be more pro-nounced and, therefore, easier to observe.
In this study, detailed geochemical analyses of Northwest Java Basin oils are examined in order to understand the origin of light oils and condensates. Signature compositional variations exhibited by sam-pled petroleum ¯uids derived from two distinct NW Java oil families reveal the varying extent of these aforementioned processes.
2. Regional geological setting
The NW Java Basin is located between the Bogor Trough to the south, the continental Sunda Plate to the north, the Tanggerang High to the west, and the Arja-winangun High to the east (Fig. 1). This basin is part of a series of basins (e.g., Palembang, Sunda, Asri) that originated on the southern edge of the Sunda craton during a major Eocene-Oligocene orogenic period of dextral wrenching (Daly et al., 1987; Gresko et al., 1995).
In the NW Java Basin, an extensive accumulation of Tertiary sediments up to 5000 meters thick covers a cratonic basement of pre-Tertiary age (Nayoan, 1972), with the stratigraphic succession ranging in age from Late Paleocene (?) - Mid-Eocene to Holocene (Fig. 2). The Oligocene to Middle Miocene sediments were deposited in a general transgressive sequence. The rock units of this sequence comprise Talangakar, Baturaja and Cibulakan formations. This transgressive sequence consists mainly of shale interbedded with sandstone, siltstone and coal which covers the northern half of the basin, grading southward into deep water shale and carbonate facies. Talangakar strata, which were depos-ited in deltaic to shore environments range from 150 m to greater than 900 m thick in the shelf area and basin axis depocenters. The coals and carbonaceous shales of this depositional system exhibit excellent hydrocarbon source rock characteristics (Fletcher and Bay, 1975; Roe and Polito, 1977; Gordon, 1985; Robinson, 1987; Pramono et al., 1990; Noble et al., 1991, 1997; Wu, 1991).
3. Analytical
Oils [22, see Table 1] sampled from NW Java exploration and production wells (well-head separa-tors), were analyzed as summarized in Tables 2±4. Oils were sampled directly from the well-head and collected in sealed glass vials. The biodegraded oil (JTB-194) was obtained from Pertamina Lab in Cirebon. Samples were kept at ambient conditions for a short time period (3±4 weeks) until arrival at ARCO Exploration Research and Technical Services Laboratories (Plano, TX), where all samples were subsequently stored in a refrigerator. All sample preparation and GC, GC±MS analyses were performed within a few months of their arrival. Whole oils were analyzed by gas chromatography on a HP
5890 GC equipped with a 60 m0.25 mm i.d. capillary
column coated with a 0.25 mm dimethylploysiloxane (DB-1) phase. Sample preparation of the oils involved topping under a stream of nitrogen at 40C for 1 h, before
treatment with an excess of pentane to precipitate asphaltenes. The pentane soluble fraction was subse-quently concentrated, with the polar NSO fraction then removed using a Waters Sep-Pak Plus CN cartridge using pentane as eluent. The apolar saturated, and moderately polar aromatic hydrocarbon, fractions were isolated by medium-pressure liquid chromatography (MPLC) using deactivated silica and activated silica columns.
Gas chromatography±mass spectrometry (GC±MS) was performed on saturate and aromatic fractions using a
HP 5890 GC equipped with a 60 m0.25 mm i.d
capil-lary column coated with a 0.1 mm phenyl methylpoly-siloxane (DB-5) phase. The concentrations of selected biomarkers were determined by adding standards (100 ppm), 5b-cholane for saturates and d10-anthracene for
aromatics. Response factors for the components of interest relative to the internal standards were taken as a nominal
value of 1.0. While this is not strictly true, it is eective for the purpose of comparing samples with one another.
Table 1
Sample name, location, reservoir age and inferred depositional environment of source rocks for NW Java Basin
Well Depth (m) Sub-basin Reservoir age Depositional environment of source rock
CCH-P5 1027±1031 Rengasdengklok High Upper Miocene Near shore
SIN-5 1456±1468 Jatibarang Upper Miocene Near shore
RDL-2 1071±1075 Rengasdengklok High Middle Miocene Near shore
JTB-194 468±473 Jatibarang Middle Miocene Near shore
CLT-1 1800±1803 Pasirputih Middle Miocene Near shore
SDS-1 1840±1846 Pasirputih Middle Miocene Near shore
PGD-3 1693±1695 Pasirputih Middle Miocene Near shore
RDG-45 1411±1418 Jatibarang Middle Miocene Near shore
PCT-1 1538±1548 Jatibarang Middle Miocene Near shore
CMS-21A 1807±1811 Pamanukan High Middle Miocene Fluvio - Deltaic
SNT-1 1328±1331 Jatibarang Lower Miocene Near shore
TBN-1 1821±1827 Ciputat Lower Miocene Fluvio - Deltaic
PMK-2 2195±2199 Pasirputih Lower Miocene Near shore
CLU-5 1811±1816 Pasirputih Lower Miocene Near shore
JNG-1 832±838 Ciputat Lower Miocene Near shore
BJR-2 1578±1580 Pasirputih Lower Miocene Fluvio - Deltaic
WLU-2 1575±1579 Pamanukan High Lower Miocene Fluvio - Deltaic
TGB-24 1621±1667 Pamanukan High Lower Miocene Near shore
JTB-128 1845±1849 Jatibarang Lower Miocene Fluvio - Deltaic
CMB-7 2367±2372 Pamanukan High Upper Oligocene Fluvio - Deltaic SBD-1 2111±2114 Pamanukan High Upper Oligocene Fluvio - Deltaic
KPT-1 1645±1647 Jatibarang Upper Oligocene Fluvio - Deltaic
Table 2
Bulk oil characteristics of NW Java oils
13C (PDB, per mil) Oil composition (%)
Well API %S Oil Sat Aro NSO Asp Sat Aro NSO Asp Sat/Aro
CCH-PS 20.7 1.19 ÿ23.0 ÿ22.0 ÿ23.2 ÿ24.5 44 45 11 ± 1.0
SIN-5 36.1 0.09 ÿ27.2 ÿ28.9 ÿ26.8 ÿ27.6 ÿ27.0 64 21 11 3 3.1
RDL-2 32.1 0.13 ÿ27.1 ÿ27.9 ÿ26.6 ÿ27.0 ÿ27.4 63 22 11 4 2.8
JTB-194 17.8 0.42 ÿ27.2 ÿ28.2 ÿ26.8 ÿ27.0 ÿ26.2 39 39 18 3 1.0
CLT-1 32.9 0.08 ÿ28.3 ÿ29.6 ÿ27.1 ÿ28.2 ÿ28.1 64 29 6 1 2.2
SDS-1 43.6 0.07 ÿ27.0 ÿ28.7 ÿ26.2 ÿ28.7 ± 72 21 7 ± 3.4
PGD-3 50.1 0.15 ÿ27.0 ÿ27.9 ÿ25.8 ÿ29.2 ± 72 14 13 1 5.2
RDG-45 30.2 0.24 ÿ27.5 ÿ29.0 ÿ16.4 ÿ27.0 ÿ25.3 62 25 12 1 2.4
PCT-1 40.3 0.08 ÿ27.2 ÿ28.3 ÿ26.2 ± ± 76 20 4 ± 3.7
CMS-21A 40.6 0.08 ÿ27.1 ÿ27.8 ÿ26.4 ÿ27.6 ÿ26.3 58 19 15 8 3.1
SNT-1 53.4 0.02 ÿ26.6 ± ± ± ± ± ± ± ± ±
TBN-1 32.0 0.11 ÿ28.6 ÿ30.2 ÿ27.7 ÿ27.5 ÿ26.6 71 16 9 5 4.5
PMK-2 35.2 0.05 ÿ28.3 ÿ29.2 ÿ26.8 ÿ28.5 ± 58 36 6 ± 1.6
CLU-5 33.7 0.12 ÿ28.2 ÿ28.9 ÿ26.4 ÿ28.2 ± 68 25 7 ± 2.8
JNG-1 28.1 0.25 ÿ26.4 ÿ27.7 ÿ25.6 ÿ26.1 ÿ24.4 62 24 11 3 2.5
BJR-2 43.3 0.02 ÿ27.3 ÿ26.5 ÿ25.7 ± ± 51 44 4 ± 1.2
WLU-2 33.1 0.07 ÿ27.9 ÿ28.4 ÿ27.9 ÿ28.8 ÿ27.0 38 9 13 40 4.3
TGB-24 35.6 0.20 ÿ27.6 ÿ29.1 ÿ26.4 ÿ27.2 ÿ25.9 64 27 8 1 2.4
JTB-128 22.7 0.09 ÿ28.4 ÿ29.5 ÿ27.2 ÿ27.4 ÿ27.9 52 21 13 14 2.4
CMB-7 23.8 0.14 ÿ28.6 ÿ29.6 ÿ27.6 ÿ27.6 ÿ27.9 44 31 17 8 1.4
SBD-1 25.8 0.16 ÿ28.2 ÿ29.1 ÿ27.1 ÿ27.3 ÿ27.0 53 22 13 12 2.5
KPT-1 45.1 0.02 ÿ27.6 ÿ28.0 ÿ26.8 ÿ28.4 ± 68 27 5 ± 2.6
4. Results
4.1. Bulk oil characteristics
The locations and ages of crude oils and rock samples used in this study are given in Table 1, with some asso-ciated geochemical data presented in Tables 2±4. Bulk oil characteristics for 22 onshore NW Java Basin crude oils are listed in Table 2. The oils vary in appearance at room temperature from highly viscous black tarry sub-stances to colourless light oils. API oil gravities range from 17.8 to 53.4, re¯ecting oil classi®cations from
heavy to light crude oils and retrograde condensates (Hunt, 1996). As shown in Fig. 3, a plot of API gravity against depth for the oils, three out of ®ve of the med-ium gravity oils occur at depths deeper than 1800 m while 12 out of 15 light oils and retrograde condensates occur at depths between 1300 and 1850 m. The two heavy oils identi®ed in this study occur at depths shal-lower than 1300 m. These data show that most of the lighter API gravity crude oils and retrograde con-densates are found in shallower reservoirs, whereas the
medium API gravity crude oils are generally found in deeper reservoirs (exceptions are JNG-1 and RDG-45). Observations such as these, in which the shallower reservoirs in a basin contain the lighter gravity ¯uids, are consistent with data suggesting that evaporative fractionation processes may be responsible (Dzou, 1990; Dzou and Hughes, 1993; Holba et al., 1996). The heavy API gravity oils (CCH-P5 and JTB-194) analyzed in this study are located in the shallowest sections of the basin and display obvious signs of biodegradation, including depletion of n-alkanes and isoprenoids (Fig. 4). Table 2 shows that CCH-P5 and JTB-194 also pos-sess the highest sulphur contents of the oils analyzed with values of 1.19 and 0.42% S, respectively (average of NW Java oils in this study is 0.18% S), a character-istic often associated with biodegraded petroleums (Hunt, 1996). CCH-P5 oil is unusual in that it is reported to be derived from a carbonate source rock (Napitupulu et al., 1997).
Table 2 lists the stable carbon isotope measurements (expressed in per mil PDB) for the 22 NW Java oils, including data for the respective saturate, aromatic,
Table 3
Geochemical data for NW Java Basin oilsb
Well Pr Pr CPI C27R 20S 20S Oleanane DBT % Rc
Ph n-C17 CPI C29R 20S+20R 20S+28R C30 Hopane Phen
CCH-P5 4.9 3.3 1.2 1.10 0.24 ±a 0.04 0.20 0.54
CMS-21A 8.2 2.0 1.2 1.10 0.54 0.51 0.31 0.12 0.88
SNT-1 5.6 1.8 ± ± ± ± ± ±
JTB-128 8.1 4.6 1.3 0.72 0.53 0.54 0.24 0.12 0.77
CMB-7 9.6 11.3 1.4 0.85 0.54 0.58 0.43 0.06 0.76
SBD-1 7.6 2.7 1.2 0.93 0.52 0.53 0.30 0.10 0.85
KPT-1 16.7 4.1 1.2 0.89 0.50 0.54 0.37 0.04 0.74
Notes:ÿ, No data acquired or available.
De®nitions and methods of measurement: Pr/Ph=pristane/phytane (GC); Pr/n-C17=pristane/n-heptadecane (GC); CPI=carbon preference index (GC); C27R/C29R=C27 aaa20R-cholestane/C29aaa20R-ethylcholestane (m/z 217); 20S/(20S+20R), 20S and 20R diastereomers of 5a(H),14a(H),17a(H)-ethylcholestane (m/z 217); 20S/20S+28R triaromatics, C20 pregnane/(C20 pregnane +C28 20R stigmastane) (m/z231); Ol/C30H=18a(H)-oleanane/C30 17a(H)-hopane (m/z191); DBT/PHEN=dibenzothiophene (m/z
NSO and asphaltene fractions for each oil. Fig. 5(a) and (b) present `Galimov' or `Stahl' -type isotope plots (Galimov 1973; Stahl 1978) for nine oils that are classi-®ed as `pristine' or `pristine-like' based on whole oil chromatograms, in which, each oil displays relatively limited signs of post-generative alteration eects such as evaporative fractionation, water washing or biode-gradation. Hence, while the de®ned `pristine-like' oils we have used in this study may well re¯ect recharged residual oils, they approximate as best as is possible what the original pristine oil may have actually looked like (i.e. `pristine-like', see Figs. 13 and 14). From Fig. 5, two distinct isotope trends can be discerned among the nine oils plotted. Group 1 samples (Fig. 5a: PMK-2, SIN-5, TGB-24, RDG-45, SDS-1 and RDL-2) have a heavier saturate fraction carbon isotopic composition (d13C
sat>ÿ29.2%) than Group 2 samples (Fig. 5b:
TBN-1, JTB-128 and CMB-7) (d13C
sat <ÿ29.5%).
Similarly, for the aromatic fraction, Group 1 samples have heavier carbon isotopic values (d13C
aro>ÿ26.8%)
relative to Group 2 samples (d13C
aro>ÿ27.2%). The
individual line pro®les these types of curves depict can
provide important geochemical correlation information. Typically, oils and bitumens show a general enrichment in 13C for fractions of increasing polarity and boiling
point. However, variations in source rock facies con-comitant with secondary processes such as migration, deasphalting or thermal maturation may in¯uence the isotopic composition of each fraction resulting in `irre-gular' line pro®les (Chung et al., 1981). For the desig-nated `pristine-like' oils shown in Fig. 5, no signi®cant eect of secondary processes are inferred, hence the variations in the isotopic line pro®les between the Group 1 and Group 2 oils may, therefore, be attributed to source rock heterogeneity. For Group 1 oils, these line variations are re¯ected as heavier isotopic char-acteristics of the whole oil, saturate and aromatic frac-tions, relative to Group 2 oils, which are characterized by a lighter isotopic line pro®le. Interestingly, the iso-topic values recorded for the NSO fractions in both oil groups are quite similar.
4.2. Principal component analysis
In order to examine the two oil groupings in greater detail, principal component analysis (PCA) was per-formed using bulk oil, carbon isotope and biomarker data (Tables 2 and 3). Due to the fact that many integral geochemical variables will be compromised as a con-sequence of evaporative fractionation, biodegradation and water washing phenomena, an initial determination of the most important or signi®cant oil parameters was ®rst established using 17 geochemical variables for the nine inferred pristine or pristine-like oils. Fig. 6(a) shows a scores plot of all 17 biomarker and bulk oil variables for the samples. From this plot, the `weighting' of the variables comprising the ®rst and most signi®cant principal component (accounting for 36% of the var-iance) clearly indicates two collective sets of dependent variables, with one set of variables representing samples exhibiting `a more terrestrial in¯uence' and the second set of variables representing samples exhibiting `a more marine in¯uence.' Variables indicative of terrestrial or higher plant contributions include compounds and parameters such as oleanane, high pristane/phytane, C29
sterane and C19 and C20tricyclic terpanes (Powell and
McKirdy, 1973; Reed, 1977; Hunt, 1996). Variables suggestive of a marine in¯uence may include high abundance of dibenzothiophene, C23 tricyclic terpane,
C27 sterane and C29 hopane compounds (Huang and
Meinschein, 1979; Hughes, 1984; Peters and Moldowan, 1993). Taking into account the ¯uvial deltaic source of the NW Java oils, the oils can be distinguished into families containing a more signi®cant terrestrial or higher plant character and families exhibiting more of a marine in¯uence.
Fig. 6(b) is a factor plot of the main principal com-ponents for 21 NW Java oils (SNT-1 was omitted due to
Table 4
Compositional ratios for gasoline fraction of NW Java Basin oils
CMS-21A 20.2 1.0 10.6 0.4
SNT-1 22.5 1.3 0.8 0.5
JTB-128 14.4 0.7 1.8 0.3
CMB-7 10.7 0.5 2.3 0.2
SBD-1 3.5 0.4 0.5 0.1
KPT-1 17.3 0.8 1.4 0.3
Notes:ÿ, No data acquired or available.
lack of biomarker data). Due to the gross compositional variations associated with the oils (i.e. light, medium, and heavy/biodegraded oils), only those `more robust' variables less likely to be aected by post-generative processes (e.g., evaporative fractionation, biodegrada-tion, migration fractionation) were included. Conse-quently, aected variables such as CPI, Pr/Ph, Pr/nC-17 and carbon isotope data were omitted in order to mini-mize potential weighting of the principal components with data likely to skew the results and subsequent interpretations. The two oil family groupings, initially based on carbon isotope data of the pristine-like oils (Fig. 5), are also clearly seen in Fig. 6(b). In addition to the pristine-like oils previously classi®ed, samples WLU-2, SBD-1, KPT-1 and CMS-21A are correlated with Group 2 oils, suggested to exhibit a relatively greater terrestrial in¯uence. Furthermore, samples PGD-3, PCT-1, JTB-194, CLT-1, CLU-5 and JNG-1 can be associated with Group 1 oils, suggested to exhibit a relatively greater marine in¯uence. Sample CCH-P5,
proposed to be derived from a carbonate source rock, is the only oil that could not be correlated to either group. The PCA methodology employed here involves ®rst determining oil groupings/families based on pristine or pristine-like oils, before subsequently incorporating all other altered oils/condensates, (i.e. those aected by the aforementioned secondary phenomena) using a more restricted group of `robust' PCA variables. This metho-dology serves to constrain and guide the statistical ana-lysis, such that provided the initial groupings are maintained, the oils/condensates aected by secondary processes can then also be correlated with some con-®dence. While this procedure can not claim to be 100% foolproof, it does provide a level of statistical con®dence and ecacy otherwise unobtainable, and allows for oil/ condensate correlations on seemingly `impossible sam-ples' that may be devoid of important geochemical parameters. This type of `guarded' statistical treatment may well represent the safest approach to determining oil/ condensate correlations and family groupings involving
hydrocarbon ¯uids that are severely aected by second-ary processes.
4.3. Source parameters
The main source intervals attributed to the NW Java Basin oils are the ¯uvial-deltaic sub-units of the Upper Oligocene Talangakar formation (Fig. 2) (Fletcher and Bay, 1975; Roe and Polito, 1977; Gordon, 1985; Robinson, 1987; Pramono et al., 1990; Wu, 1991; Noble et al., 1991, 1997). Pristane-to-phytane ratios for the pristine-like oils used in this study are very high, aver-aging 7.6 (1:4), suggesting a relatively oxic
deposi-tional setting. This ratio must be used with some caution as an indicator of redox condition during sedi-mentation, as it may also re¯ect the relationship between the chemistry of the environment and the pre-cursor organisms (Didyk et al., 1978; ten Haven et al., 1987; Dzou, 1990).
Oleanane, a land plant biomarker derived from angio-sperms is present in all NW Java oils used in this study, with the exception of SNT-1. Sample SNT-1 represents an extreme example of a retrograde condensate and is devoid
of any high molecular weight species greater than 15 carbons (Fig. 7). Many of the oils used in this study are waxy and exhibit high abundances of parans between C20 and C35. Carbon preference indices for these oils
average 1.2, re¯ecting strong contributions of higher plant-derived C25 to C35 odd-carbon-numbered
paraf-®ns. Based on these paran distributions, all of the Group 2 oils, characterized as containing a relatively greater higher plant contribution, are waxy, while a signi®cant number of Group 1 oils (9 of 12), character-ized as containing a relatively greater marine in¯uence, are non-waxy.
Fig. 8 is a ternary diagram of the relative abundance of C27, C28 and C29 steranes for the oils used in this
study. Data from this plot show that Group 1 samples are clearly weighted in favour of the C27steranes while
Group 2 samples are clearly weighted towards a higher content of C29steranes. These data further support the
interpretation that Group 1 samples exhibit a greater marine character relative to the more terrestrially-dominated Group 2 samples. It is important to be aware of possible bicadinane interferences on sterane m/z
217 ion chromatograms, especially when dealing with
south-east Asian petroleum systems. Our analyses showed only the C2820S sterane stereoisomer (not used)
was compromised by bicadinane interference.
Fig. 9, a plot of the saturate versus aromatic carbon isotope values for the nine pristine-like oils, shows very clearly the distinction between the assigned pristine-like oils of Groups 1 and 2. Isotopic dierences can generally be attributed to proportional dierences in the amount of higher plant and algal derived organic matter in the source rock that generated the crude oils. Modern terrestrial lipids from C3 plants have light isotopic signatures, usually d13C
sat=ÿ30%or lighter, which in distal deltaic systems
may become progressively diluted with isotopically heavier algal material in more distal marine environments (Collis-ter et al., 1994; Collis(Collis-ter and Wavreck, 1997). The Group 2 oils are isotopically lighter than Group 1 oils, in good agreement with the aforementioned proposal that the Group 2 oils are more terrestrially dominated with iso-topically lighter, plant organic material. These data sup-port a proximal depositional setting for the Group 2 oils. The Group 1 oils, while still terrestrially dominated, pos-sess a greater proportion of isotopically heavier, marine algal organic matter consistent with an inferred distal depositional setting for these oils.
4.4. Maturity parameters
Sterane and triterpane hydrocarbon biomarkers are useful maturity indicators and geochemical correlation tools (cf. Peters and Moldowan, 1993). Evaluation of
condensate and light crude oil maturities may be di-cult, however, due to the lean concentration of relatively higher molecular weight sterane and triterpane hydro-carbons (C27+ compounds) in these oils.
Fig. 10(a) is a plot of API Gravity against 20S/ (20S+20R) C29sterane isomerization. With the
excep-tion of biodegraded sample CCH-P5, all the oils show sterane isomerization values ranging between 0.41±0.63. Higher sterane values than can be derived from normal sterane isomerization equilibration (equilibrium range 0.52±0.55, cf. Peters and Moldowan, 1993) were recor-ded for ®ve of the NW Java Basin oils. While biode-gradation can result in arti®cially high sterane ratios above 0.55, this eect would provide a possible expla-nation for biodegraded sample JTB-194 only (cf. Peters and Moldowan, 1993). Coelution problems with afore-mentioned species such as bicadinanes on m/z 217 selected ion chromatograms, used to calculate sterane isomerization ratios, are common with Tertiary-age oils from Indonesia and may arti®cially elevate sterane ratios. Only bicadinane T1 was found to coelute with the C28
20S sterane (not used) in this study. Interestingly, nine of the 14 higher gravity oils, such as PGD-3, KPT-1, BJR-2 and PCT-1 (but not SNT-1), have lower sterane isomerization values compared to the values recorded for the heavier medium-gravity oils. These data indicate that the high gravity oils used in this study are probably not high maturity oils, rather their origin may be attributed to evaporative fractionation processes leading to retrograde condensates formation. Further support for
this interpretation is obtained from calculated equiva-lent vitrinite re¯ectance values based on the Methyl Phenanthrene Index-1 (MPI-1) (Radke et al. 1986). Calculated equivalent vitrinite re¯ectance (% Rc) values for the NW Java Basin oils range from 0.69 to 0.98% [Fig. 10(b)], suggesting early to middle maturity levels for the parent source rock. These values are in agree-ment with published estimates of Talangakar source rock maturity levels (VRo of 0.7±0.75 %) in the NW Java Basin (Pramono et al., 1990). Therefore, geologic factors rather than source maturity appear to be gov-erning and controlling the evaporative fractionation phenomena observed in this study.
Light hydrocarbon maturity data obtained from gasoline range hydrocarbon components are also asses-sed. Fig. 11, a plot of isoheptane values (I) against
heptane values (H), indicates that all the light oils/ret-rograde condensates (with the exception of biodegraded samples CCH-P5, JTB-194, CLT-1) are of normal maturity. These data further support the proposal that the high gravity oils in this study, are most likely the result of evaporative fractionation processes and not high thermal maturity.
5. Discussion
5.1. Evaporative fractionation
The distributions and concentrations of gas (C1±C4)
and gasoline (C5±C14) range components in oils are
aec-ted by a complex combination of subsurface processes
related to source type, migration, evaporative fractio-nation, water washing, and thermal maturation (Ley-thaeuser et al., 1979; Welte et al., 1982). Physical partitioning of oils may result in compositional changes during remigration, greatly aecting parameters com-monly used for geochemical characterization of migration
¯uids (Thompson and Kennicutt, 1990). Thompson (1988) noted that migration eects in deltaic environments, where oil tend to undergo multiple migration processes, are very pronounced and require special consideration.
The 22 onshore NW Java Basin oils were analyzed for gas and gasoline range hydrocarbons, with associated
Fig. 7. Gas chromatogram of retrograde condensate SNT-1. These high gravity ¯uid types are usually found in the shal-lowest reservoirs.
Fig. 8. Ternary diagram of relative abundance of C27±C28±C29aaa20R steranes in NW Java Basin oils.
gasoline compositional ratios shown in Table 4. Fig. 12 is a plot of two light hydrocarbon parameters (n-heptane/methylcyclohexane against toluene/n -hep-tane) used to identify those samples aected by biode-gradation-water washing and evaporative fractionation processes. High toluene/n-heptane ratios for the major-ity of the 22 oils suggest that evaporative fractionation processes have occurred to varying extents. Formation of retrograde condensates, such as those described pre-viously, from pristine oils by post-generative processes like evaporative fractionation also results in the forma-tion of `residual oils.' Residual oils are characterized by
loss of low molecular weight hydrocarbons, enhanced concentration of aromatic compounds, and lower API gravities than the original oils (Thompson, 1987; Dzou, 1990; Dzou and Hughes, 1993). Figs. 13 and 14 show whole oil gas chromatograms of Groups 1 and 2 pris-tine-like oils, respectively, together with associated ret-rograde condensate and residual oil examples. Fig. 13(b) illustrates typical features associated with a majority of Group 1 oils (9 of 12), including a non-waxy paran distribution showingn-alkanes eluting betweennC5and
approximately nC30. Other features include high
pris-tane/phytane ratios and a strong abundance of methyl-cyclohexane (MCH). Fig. 13(a) is a Group 1 retrograde condensate exhibiting prominent concentrations of hydrocarbons eluting betweennC5andnC18, but devoid
of higher molecular weight species abovenC18,
indicat-ing that this oil is a product of evaporative fractionation processes. Figs. 13(c) depicts a Group 1 residual oil with an absence of low molecular weight hydrocarbons belownC12, demonstrating that the light hydrocarbons
originally associated with this oil have been removed and transported away.
Fig. 14(b) shows typical features associated with all of the Group 2 oils (with the exception of extremely light oils) from the NW Java Basin, including a waxy paran distribution indicated by the abundance of odd carbon-numbered n-alkanes eluting between nC20 and nC35.
Other features, similar to those of Group 1 oils, include high pristane/phytane ratios and relatively high con-centrations of methylcyclohexane (MCH). Fig. 14(a) and (c), as with Fig. 13(a) and (c), illustrates the forma-tion of derivative retrograde condensates and residual
Fig. 10. (a) 20S/(20S+20R)aaaC29sterane versus API grav-ity. Most NW Java Basin oils have sterane isomerization values ranging from 0.41 to 0.63 (except CCH-P5). (b) Calculated vitrinite re¯ectance (% Rc) versus API gravity for NW Java Basin oils, suggesting early to middle maturity levels for the parent source rock.
oils from pristine unaltered oils via evaporative fractio-nation processes. From these examples, it is clear that evaporative fractionation processes are important geo-logical phenomena aecting oils in the NW Java Basin. Vertical migration is very prevalent in this region due to an extensive and complex fault system that has provided the main conduits for hydrocarbon migration, and no doubt, also is responsible for the evaporative fractiona-tion processes aecting many of the oils.
Evaporative fractionation eects, in addition to altering the grossn-alkane distributions of the NW Java oils, appear to have also induced changes in the pristane/ phytane ratios of the retrograde condensates and resi-dual oils. Fig. 15 is a plot of Pr/Ph against Pr/n-C17for
each of the Group 1 and Group 2 oils shown in Figs. 13 and 14. Retrograde condensates in each group have higher pristane/phytane values relative to the parent pristine oil; conversely, residual oils in each group have
lower pristane/phytane values relative to the parent pristine oil. Evaporative fractionation processes appear to increase the abundance of pristane relative to phytane in retrograde condensates, while reducing the abun-dance of pristane relative to phytane in the residual oils. These observations, therefore, have obvious and impor-tant implications in oil correlation studies that compare pristane and phytane distributions in retrograde con-densate, pristine and residual oil types.
5.2. Biodegradation and water washing
Biodegraded oils are represented by JTB-194 and CCH-P5; these oils have low API gravities (17.8±20.7),
low saturate/aromatic ratios, low paranic contents, and a de®ciency in low molecular weight aromatic hydrocarbons (Fig. 4 and Table 2). These oils are loca-ted in the shallowest reservoirs in the basin, where
favorable conditions for biodegradation are likely to exist.
Water washed oils are commonly characterized by the loss of low molecular weight aromatic hydrocarbons such as benzene and toluene (Palmer, 1984; Lafargue and Barker, 1988). Fig. 16 depicts three whole oil chro-matograms of Group 1 oils that illustrate the eects of water washing on a retrograde condensate formed from a related pristine-like oil. Samples PCT-1 and PGD-3 [Fig. 16(a) and (b)] represent examples of Group 1 ret-rograde condensates formed by evaporative fractiona-tion processes on a parent Group 1 pristine-like oil such as TGB-24 [Fig. 16(c)]. All three oils have similar abundances of cyclohexane (CH) and methylcyclohex-ane (MCH), supporting previous assertions that satu-rated hydrocarbons are less likely than aromatic hydrocarbons to be aected by evaporative fractiona-tion and water washing processes. In addifractiona-tion, within
Fig. 13. Gas chromatograms of representative Group 1 oils illustrating compositional changes associated with evaporative fractionation: (a) a retrograde condensate with high abundance of hydrocarbons eluting between nC5 and nC18, suggesting formation by evaporative fractionation; (b) typical pristine-like Group 1 oil; and (c) 1 residual oil has lost its light hydro-carbons.
Fig. 14. Gas chromatograms of representative Group 2 oils illustrating compositional changes associated with evaporative fractionation processes: (b) a typical pristine-like Group 2 oil, (a and c) a retrograde condensate and a residual oil derived from a pristine-like oils as a result of evaporative fractionation.
saturated hydrocarbon classes, naphthenic compound types such as CH and MCH are more resistant than linear n-alkanes to biodegradation processes. Sample PCT-1 clearly shows the eects of water washing as observed by the loss of benzene, toluene and xylene.
Concomitant with water washing, this oil may have also undergone limited microbial degradation resulting in removal of the C5±C7linear alkanes. With respect to the
light aromatic components in retrograde condensate PGD-3 and pristine-like oil TGB-24, no loss of benzene,
toluene or xylene appear to have occurred. These data suggest that water washing processes have aected, and to a signi®cantly larger extent, retrograde condensate PCT-1 compared to retrograde condensate PGD-3 and pristine-like oil TGB-24. As all three oils are located at similar depths, between 1500 and 1700 m, it may be envisaged that evaporative fractionation processes responsible for the formation of retrograde condensate PCT-1 also exposed this oil, in particular, to active charged meteoric waters along the remigration pathway. The eect of water washing in these instances can clearly be discerned against additional post-generative processes such as evaporative fractionation and biode-gradation. Fig. 16 shows that oils experiencing eva-porative fractionation may also exhibit the eects of water washing during re-migration from the original reservoir into a shallower reservoir, or in the new reser-voir itself.
5.3. Migration pathways of NW Java oils
Previous studies in the NW Java Basin concluded that migration pathways occurred laterally and/or vertically out of the source area (Wu, 1991; Noble et al., 1997). In these reports, extended lateral migration pathways in this basin were suggested to be oriented in a pre-dominantly north±south direction along faults with vertical and cross-stratal migration conduits attributed to in-situ faulting concomitant with rapid transport of ¯uids during periods of tectonic activity. Oil migration along these complex fault systems is dependent on the location of nearby source rocks that have reached thermal maturity. As oil migration distances in the NW Java Basin are anticipated to be relatively short, the identi®cation of dierent geochemical characteristics of reservoired oils may actually provide unique insights into source rock variability in this region. Results from this study indi-cate that all the terrestrially-dominated Group 2 oils, with the exception of TBN-1, are located in close proximity to the eastern ¯ank of the onshore NW Java Basin in reservoirs on, or near, the present-day coastline. Oils with Group 1 characteristics are exclusively located in onshore reservoirs in the central, western and southern interior regions of the NW Java Basin. Fig. 17 shows an inferred sequence of depositional settings of the Talan-gakar formation from ¯uvial deltaic to nearshore mar-ine environments based on biostratigraphic and paleoenvironmental analyses of cores, drill cuttings and well logs from the Late Oligocene to the Early Miocene (Wu, 1991). As Fig. 17 illustrates, the Talangakar for-mation represents a marine transgressional sequence during this time interval, with ¯uvial deltaic deposits overlain by nearshore marine sediments. The main paleo-delta complex is located in the central portion of the present-day oshore Arjuna Basin and in the eastern ¯ank region near the present coastline. More marine
in¯uenced Group 1 oils appear to be concentrated in present day central onshore regions (Pasirputih sub-basin) that correspond to nearshore marine and pro-delta Talangakar deposits. In addition, more terrestrial in¯uenced Group 2 oils appear to be concentrated in present-day central oshore regions (Wu, 1991; Noble et al., 1997) and nearshore eastern coastal regions of the NW Java Basin that correspond to delta plain Talangakar transgressive deposits. It is proposed, therefore, that the main delta plain to ¯uvial-deltaic complex of the Talangakar Formation is the source region for Group 2
oils, while prodelta to nearshore Talangakar deposits are the likely source rocks for the Group 1 oils.
Proposed migration pathways of Group 1 and Group 2 oils from identi®ed mature source pods to identi®ed NW Java Basin reservoirs are indicated (Fig. 18). Hydrocarbon migration pathways in the NW Java Basin were previously largely proposed on the basis of nearby reservoir locations and known geological fault conduits (Wu, 1991; Noble et al., 1997). The identi®ca-tion in this work of two distinct oil families in the NW Java Basin assists in the identi®cation of hydrocarbon migration pathways based on geochemical correlation. These data help to constrain and better re®ne likely migration scenarios.
6. Conclusions
The main source rock of onshore NW Java Basin oils is the ¯uvio-deltaic to nearshore Talangakar Formation. The oils consist of light oils/retrograde condensates, residual oils, and pristine oils that have been aected by evaporative fractionation, biodegradation, and water washing.
NW Java oil samples are less mature than expected for light oils and condensates generated by extreme thermal processes. The compositional patterns and maturity estimates infer that the origin of the light oils and retrograde condensates in this basin are, in fact, due to migration and evaporative fractionation eects.
Principal Component Analysis was eectively used to correlate retrograde condensate, pristine and residual oil types after screening of labile biomarker variables. In general, these oils can be classi®ed into a more marine in¯uenced group and a more terrestrial dominated group.
Pristane/phytane ratios are signi®cantly aected by evaporative fractionation processes, with light oils or retrograde condensates having higher Pr/Ph ratios and residual oils having lower ratios than original parent pristine oils.
The eects of water washing, concomitant with eva-porative fractionation processes, were observed to sequester low molecular weight aromatics such as ben-zene and toluene.
Acknowledgements
The authors thank Pertamina EP and ARCO AEPT for support of this project and permission to present the results of our Northwest Java Basin study. We are grateful to Erika Shoemaker-Ellis for graphical assis-tance with manuscript ®gures. The authors would also like to acknowledge Dr. Ron Noble and Dr. Leon Dzou for reviewing the manuscript and providing many help-ful suggestions.
Associate EditorÐR. Lin
Appendix
% C27=% C27aaa20R-cholestane (m/z217).
% C28=% C28aaa20R-methylcholestane (m/z217).
% C29=% C29aaa20R-ethylcholestane (m/z217).
C27R/C29R=C27 aaa 20R-cholestane/C29 aaa
20R-ethylcholestane (m/z217).
C29H/C30H=C2917a(H)-hopane/C3017a(H)-hopane
(m/z191).
Ol/C30H=18a(H)-oleanane/C30 17a(H)-hopane (m/z
191).
TT(19+20)/TT23=C19+C20 tricyclic terpanes/C23
tricyclic terpane (m/z191).
TT23/C30H, C23tricyclic terpane/C3017a(H)-hopane
(m/z191).
DBT/PHEN = dibenzothiophene (m/z 184)/phenan-threne (m/z178).
Pr/Ph = pristane/phytane (GC). Pr/n-C17=pristane/n-C17(GC).
CPI2=Carbon preference index (GC).
API=API gravity (whole oil).
% S=Sulfur content (%).
d13C
Aro=d13C Oil aromatic fraction. d13C
Oil=d13C Whole oil. d13C
Sat=d13C Oil saturate fraction.
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