Directory UMM :Data Elmu:jurnal:O:Organic Geochemistry:Vol31.Issue4.2000:

Organic Geochemistry 31 (2000) 295±315
www.elsevier.nl/locate/orggeochem

Post-generative alteration e€ects on petroleum in the onshore
Northwest Java Basin, Indonesia
Haposan Napitupulua,b, Leroy Ellisc,d,*, Richard M. Mittererb
a

Pertamina EP Jl. Merdeka Timur No.6, Jakarta 10110, Indonesia
University of Texas at Dallas, Richardson, TX 75083-0688, USA
c
ARCO Exploration and Production Technology, 2300 West Plano Parkway, Plano, TX 75075-8499, USA
d
Terra Nova Technologies, PMB 409, 18352 Dallas Pkwy, Ste. 136, Dallas, TX 75287, USA
b

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 Oligocene 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 17 to 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 a€ected 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 e€ective 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 subsequent 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 biodegradation e€ects. Thermal maturation, a consequence

of increasing burial depth and higher temperature, will

* Corresponding author.
E-mail address: tntech@home.com (L. Ellis).

form increasingly lighter gravity oils until extreme temperatures result in cracking of the parent kerogen and/
or oil to gas. By contrast, biodegradation by subsurface
microbial communities at shallow depths leads to heavier (or low API gravity) oils. In addition, more complex phenomena involving evaporative fractionation,
water washing, deasphalting, mineral catalysis, gravity
segregation, subsurface PVT (pressure-volume-temperature) e€ects, and dewaxing may all contribute, to varying extents, to alteration of crude oils either in the
reservoir or along migration pathways.
Light oils (usually from 30 to 50 API gravity) and/or
retrograde condensates (ranging up to 60 API 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.
PII: S0146-6380(99)00154-0

296

H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

a gas phase, and transported away from the primary
crude oil reservoir. This re-migration tends to be directed 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 produce a greater proportion of n-alkanes relative to branched and cyclic alkanes (Philippi, 1975). Condensates
(usually > 50 API gravity) may be de®ned as a natural
wet gas accumulation in which liquid hydrocarbons,
such as those comprising the gasoline range, exist together 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 pressures, liquids may condense from these `wet gases' and

form extremely light API gravity ¯uids (i.e., condensates). Two of the most important processes responsible 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 phaseseparation 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 scenarios may involve loss of gases from the parent reservoir, perhaps due to faulting, overburden removal,
seismic activity, or simply leakage (e.g. via microfracturing) through a gas-permeable seal rock that
allows only movement of gases, and other low molecular 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 hydrocarbon components in the gas phase liquefy and condense 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 process is the formation of ``derivative'' light oils (retrograde condensates), condensates and residual oils from
the ``pristine'' parent oils. In each case, gross compositional 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. Nonbiodegraded and remigrated light oils or condensates,
are generally reservoired at shallower depths, and will
typically exhibit an enrichment in light ends and n-parans 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,
o€shore 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 fractionation 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
have undergone evaporative fractionation. Holba et al.
(1996) used o€shore Louisiana oils to show that residual
oils from evaporative fractionation processes are usually
found in deeper reservoirs and are characterized by loss
of light ends and elevated aromaticity. Reservoired
residual oils may also receive later recharging by
hydrocarbon contributions. Oils observed to have
undergone numerous cycles of evaporative fractionation
with subsequent recharge were found to exhibit a ``V''

H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

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 migration, 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 hydrocarbon 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, of n-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 e€ective within the lowboiling 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 waterwet 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 una€ected, 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 dicult because
of the more dominant e€ect 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 e€ects of
biodegradation far exceed those of water washing. In

297

deeper reservoirs and associated migration conduits,
bacteria communities are less likely to be viable mainly
due to the e€ects of increasing temperature. In these
scenarios, water washing e€ects can be more pronounced 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 sampled 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 Arjawinangun 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 deposited 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).
At least ten active petroleum systems, with 150 separate oil and gas ®elds, have been recognized in this basin
by Noble et al. (1997). Oil and gas in the onshore NW
Java Basin have migrated northward through onshore
structural highs to o€shore basins (Noble et al., 1997).
Hydrocarbons are distributed in the o€shore and
onshore NW Java Basin in Upper Oligocene (Talangakar
formation) to Upper Miocene (Parigi formation) reservoirs, and the oils are predominantly derived from ¯uviodeltaic source rocks (Table 1).

298

H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

Fig. 1. Northwest Java Basin location map.

3. Analytical
Oils [22, see Table 1] sampled from NW Java
exploration and production wells (well-head separators), 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 40 C for 1 h, before
treatment with an excess of pentane to precipitate
asphaltenes. The pentane soluble fraction was subsequently 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

H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

299

Fig. 2. Generalized stratigraphic column for Northwest Java Basin (adapted from Arpandi and Patmosukismo, 1975; Arianto, 1993;
Gresko et al., 1995; Noble et al., 1997).

HP 5890 GC equipped with a 60 m0.25 mm i.d capillary column coated with a 0.1 mm phenyl methylpolysiloxane (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 e€ective for
the purpose of comparing samples with one another.
Carbon isotopic analyses were performed at the stable
isotope laboratory at U. T. Dallas and at Coastal Science Laboratory (Austin, TX). Stable carbon isotope
ratios are reported in parts per thousand (per mil) relative to the PDB standard with a precision of 0.2%.

300

H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

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
SIN-5
RDL-2
JTB-194
CLT-1
SDS-1
PGD-3
RDG-45
PCT-1
CMS-21A
SNT-1
TBN-1
PMK-2
CLU-5
JNG-1
BJR-2
WLU-2
TGB-24
JTB-128
CMB-7
SBD-1
KPT-1

1027±1031
1456±1468
1071±1075
468±473
1800±1803
1840±1846
1693±1695
1411±1418
1538±1548
1807±1811
1328±1331
1821±1827
2195±2199
1811±1816
832±838
1578±1580
1575±1579
1621±1667
1845±1849
2367±2372
2111±2114
1645±1647

Rengasdengklok High
Jatibarang
Rengasdengklok High
Jatibarang
Pasirputih
Pasirputih
Pasirputih
Jatibarang
Jatibarang
Pamanukan High
Jatibarang
Ciputat
Pasirputih
Pasirputih
Ciputat
Pasirputih
Pamanukan High
Pamanukan High
Jatibarang
Pamanukan High
Pamanukan High
Jatibarang

Upper Miocene
Upper Miocene
Middle Miocene
Middle Miocene
Middle Miocene
Middle Miocene
Middle Miocene
Middle Miocene
Middle Miocene
Middle Miocene
Lower Miocene
Lower Miocene
Lower Miocene
Lower Miocene
Lower Miocene
Lower Miocene
Lower Miocene
Lower Miocene
Lower Miocene
Upper Oligocene
Upper Oligocene
Upper Oligocene

Near shore
Near shore
Near shore
Near shore
Near shore
Near shore
Near shore
Near shore
Near shore
Fluvio - Deltaic
Near shore
Fluvio - Deltaic
Near shore
Near shore
Near shore
Fluvio - Deltaic
Fluvio - Deltaic
Near shore
Fluvio - Deltaic
Fluvio - Deltaic
Fluvio - Deltaic
Fluvio - Deltaic

Table 2
Bulk oil characteristics of NW Java oils
13

C (PDB, per mil)

Oil composition (%)

Well

API

%S

Oil

Sat

Aro

NSO

Asp

Sat

Aro

NSO

Asp

Sat/Aro

CCH-PS
SIN-5
RDL-2
JTB-194
CLT-1
SDS-1
PGD-3
RDG-45
PCT-1
CMS-21A
SNT-1
TBN-1
PMK-2
CLU-5
JNG-1
BJR-2
WLU-2
TGB-24
JTB-128
CMB-7
SBD-1
KPT-1

20.7
36.1
32.1
17.8
32.9
43.6
50.1
30.2
40.3
40.6
53.4
32.0
35.2
33.7
28.1
43.3
33.1
35.6
22.7
23.8
25.8
45.1

1.19
0.09
0.13
0.42
0.08
0.07
0.15
0.24
0.08
0.08
0.02
0.11
0.05
0.12
0.25
0.02
0.07
0.20
0.09
0.14
0.16
0.02

ÿ23.0
ÿ27.2
ÿ27.1
ÿ27.2
ÿ28.3
ÿ27.0
ÿ27.0
ÿ27.5
ÿ27.2
ÿ27.1
ÿ26.6
ÿ28.6
ÿ28.3
ÿ28.2
ÿ26.4
ÿ27.3
ÿ27.9
ÿ27.6
ÿ28.4
ÿ28.6
ÿ28.2
ÿ27.6

ÿ22.0
ÿ28.9
ÿ27.9
ÿ28.2
ÿ29.6
ÿ28.7
ÿ27.9
ÿ29.0
ÿ28.3
ÿ27.8
±
ÿ30.2
ÿ29.2
ÿ28.9
ÿ27.7
ÿ26.5
ÿ28.4
ÿ29.1
ÿ29.5
ÿ29.6
ÿ29.1
ÿ28.0

ÿ23.2
ÿ26.8
ÿ26.6
ÿ26.8
ÿ27.1
ÿ26.2
ÿ25.8
ÿ16.4
ÿ26.2
ÿ26.4
±
ÿ27.7
ÿ26.8
ÿ26.4
ÿ25.6
ÿ25.7
ÿ27.9
ÿ26.4
ÿ27.2
ÿ27.6
ÿ27.1
ÿ26.8

ÿ24.5
ÿ27.6
ÿ27.0
ÿ27.0
ÿ28.2
ÿ28.7
ÿ29.2
ÿ27.0
±
ÿ27.6
±
ÿ27.5
ÿ28.5
ÿ28.2
ÿ26.1
±
ÿ28.8
ÿ27.2
ÿ27.4
ÿ27.6
ÿ27.3
ÿ28.4

ÿ27.0
ÿ27.4
ÿ26.2
ÿ28.1
±
±
ÿ25.3
±
ÿ26.3
±
ÿ26.6
±
±
ÿ24.4
±
ÿ27.0
ÿ25.9
ÿ27.9
ÿ27.9
ÿ27.0
±

44
64
63
39
64
72
72
62
76
58
±
71
58
68
62
51
38
64
52
44
53
68

45
21
22
39
29
21
14
25
20
19
±
16
36
25
24
44
9
27
21
31
22
27

11
11
11
18
6
7
13
12
4
15
±
9
6
7
11
4
13
8
13
17
13
5

±
3
4
3
1
±
1
1
±
8
±
5
±
±
3
±
40
1
14
8
12
±

1.0
3.1
2.8
1.0
2.2
3.4
5.2
2.4
3.7
3.1
±
4.5
1.6
2.8
2.5
1.2
4.3
2.4
2.4
1.4
2.5
2.6

Notes: ÿ, No data acquired or available.

301

H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315
Table 3
Geochemical data for NW Java Basin oilsb
Well

CCH-P5
SIN-5
RDL-2
JTB-194
CLT-1
SDS-1
PGD-3
RDG-45
PCT-1
CMS-21A
SNT-1
TBN-1
PMK-2
CLU-5
JNG-1
BJR-2
WLU-2
TGB-24
JTB-128
CMB-7
SBD-1
KPT-1

Pr

Pr

CPI

C27R

20S

20S

Oleanane

DBT

Ph

n-C17

CPI

C29R

20S+20R

20S+28R

C30 Hopane

Phen

4.9
7.9
6.1
±
9.8
9.7
13.8
5.3
11.6
8.2
5.6
7.7
7.9
9.0
5.1
14.4
2.4
6.5
8.1
9.6
7.6
16.7

3.3
1.8
1.6
±
5.5
3.2
2.1
1.3
1.7
2.0
1.8
2.2
1.6
2.0
1.3
2.0
1.4
1.6
4.6
11.3
2.7
4.1

1.2
1.2
1.2
±
1.2
1.2
±
1.2
1.3
1.2
±
1.2
1.1
1.2
1.2
±
1.1
1.2
1.3
1.4
1.2
1.2

1.10
1.54
1.43
1.61
2.63
1.43
1.49
2.04
1.85
1.10
±
0.60
4.00
2.56
2.27
1.04
0.55
2.27
0.72
0.85
0.93
0.89

0.24
0.52
0.57
0.58
0.54
0.45
0.41
0.56
0.47
0.54
±
0.50
0.63
0.59
0.55
0.47
0.50
0.52
0.53
0.54
0.52
0.50

±a
0.53
0.71
0.67
0.59
0.56
±
0.67
±
0.51
±
0.64
0.71
0.78
0.75
±
0.52
0.78
0.54
0.58
0.53
0.54

0.04
0.04
0.39
0.46
0.36
0.43
0.30
0.40
0.29
0.31
±
0.39
0.45
0.37
0.76
0.26
0.15
0.46
0.24
0.43
0.30
0.37

0.20
0.11
0.10
0.02
0.06
0.06
0.03
0.30
0.09
0.12
±
0.09
0.16
0.13
0.56
0.13
0.06
0.19
0.12
0.06
0.10
0.04

% Rc

0.54
0.93
0.88
0.69
0.75
0.74
0.78
0.98
0.88
0.88
0.82
0.85
0.92
0.89
0.86
0.75
0.97
0.77
0.76
0.85
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 aaa 20R-cholestane/C29 aaa 20R-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/z 231); Ol/C30H=18a(H)-oleanane/C30 17a(H)-hopane (m/z 191); DBT/PHEN=dibenzothiophene (m/z
184)/phenanthrene (m/z 178); %Rc=calculated equivalent vitrinite re¯ectance, 0.60 (MPI-1)+0.40 (for Roÿ29.2%) than Group 2 samples (Fig. 5b:
TBN-1, JTB-128 and CMB-7) (d13Csat ÿ26.8%)
relative to Group 2 samples (d13Caro>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 concomitant with secondary processes such as migration,
deasphalting or thermal maturation may in¯uence the
isotopic composition of each fraction resulting in `irregular' line pro®les (Chung et al., 1981). For the designated `pristine-like' oils shown in Fig. 5, no signi®cant
e€ect 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 characteristics of the whole oil, saturate and aromatic fractions, relative to Group 2 oils, which are characterized
by a lighter isotopic line pro®le. Interestingly, the isotopic 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 performed 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 consequence 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 variance) 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 C20 tricyclic 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 components for 21 NW Java oils (SNT-1 was omitted due to

H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

303

Fig. 3. API gravity versus depth for NW Java oils. Twelve of 15 light oils and retrograde condensates occur at depths between 1300
and 1850 m. GOR=Gas to oil ratio (McCain, 1973; Hunt, 1996).

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 a€ected by post-generative
processes (e.g., evaporative fractionation, biodegradation, migration fractionation) were included. Consequently, a€ected variables such as CPI, Pr/Ph, Pr/nC-17
and carbon isotope data were omitted in order to minimize 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 WLU2, 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 a€ected by the
aforementioned secondary phenomena) using a more
restricted group of `robust' PCA variables. This methodology serves to constrain and guide the statistical analysis, such that provided the initial groupings are
maintained, the oils/condensates a€ected 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 ecacy otherwise unobtainable, and allows for oil/
condensate correlations on seemingly `impossible samples' 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

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H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

Fig. 4. Gas chromatograms of two biodegraded oils (JTB-194 and CCH-P5).

hydrocarbon ¯uids that are severely a€ected by secondary 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, averaging 7.6 ( ˆ 1:4), suggesting a relatively oxic depositional setting. This ratio must be used with some
caution as an indicator of redox condition during sedimentation, as it may also re¯ect the relationship
between the chemistry of the environment and the precursor organisms (Didyk et al., 1978; ten Haven et al.,
1987; Dzou, 1990).
Oleanane, a land plant biomarker derived from angiosperms 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 parans 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 paran 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), characterized 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 C27 steranes while
Group 2 samples are clearly weighted towards a higher
content of C29 steranes. These data further support the
interpretation that Group 1 samples exhibit a greater
marine character relative to the more terrestriallydominated Group 2 samples. It is important to be aware
of possible bicadinane interferences on sterane m/z
217 ion chromatograms, especially when dealing with

H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

305

Fig. 5. `Galimov' or `Stahl'-type isotope plots for nine pristine-like NW Java Basin oils showing two distinct isotope trends.

south-east Asian petroleum systems. Our analyses
showed only the C28 20S 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 di€erences can generally be
attributed to proportional di€erences 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
d13Csat=ÿ30% or lighter, which in distal deltaic systems
may become progressively diluted with isotopically heavier
algal material in more distal marine environments (Collister et al., 1994; Collister 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 isotopically lighter, plant organic material. These data support a proximal depositional setting for the Group 2 oils.
The Group 1 oils, while still terrestrially dominated, possess 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 hydrocarbons (C27+ compounds) in these oils.
Fig. 10(a) is a plot of API Gravity against 20S/
(20S+20R) C29 sterane isomerization. With the exception 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 recorded for ®ve of the NW Java Basin oils. While biodegradation can result in arti®cially high sterane ratios
above 0.55, this e€ect would provide a possible explanation for biodegraded sample JTB-194 only (cf. Peters
and Moldowan, 1993). Coelution problems with aforementioned 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

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H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

Fig. 6. (a) Scores plot of 17 geochemical variables for nine pristine-like NW Java Basin oils. One set of variables re¯ects a more
terrestrial in¯uence with the second set re¯ecting a more marine in¯uence (see Appendix for parameter de®nitions). (b) Factor plot of
the main principal components for 21 NW Java Basin oils illustrating two oil families. A subset of 10 `robust' selectively screened
geochemical variables was used for the bulk sample set.

this interpretation is obtained from calculated equivalent 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 agreement 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 governing and controlling the evaporative fractionation
phenomena observed in this study.
Light hydrocarbon maturity data obtained from
gasoline range hydrocarbon components are also assessed. Fig. 11, a plot of isoheptane values (I) against

heptane values (H), indicates that all the light oils/retrograde 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 a€ected by a complex combination of subsurface processes

H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

Fig. 7. Gas chromatogram of retrograde condensate SNT-1.
These high gravity ¯uid types are usually found in the shallowest reservoirs.

307

Fig. 9. d13C of saturate fraction versus d13C of aromatic fraction
for nine NW Java Basin pristine-like oils of Group 1 and Group
2. (Sofer line, d13C ARO=1.14 d13C SAT+5.46, Sofer, 1984).

Fig. 8. Ternary diagram of relative abundance of C27±C28±C29 aaa 20R steranes in NW Java Basin oils.

related to source type, migration, evaporative fractionation, water washing, and thermal maturation (Leythaeuser et al., 1979; Welte et al., 1982). Physical
partitioning of oils may result in compositional changes
during remigration, greatly a€ecting parameters commonly used for geochemical characterization of migration

¯uids (Thompson and Kennicutt, 1990). Thompson (1988)
noted that migration e€ects 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

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H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

Fig. 11. Heptane value (H) versus isoheptane value (I) for NW
Java Basin oils. None of the light oils/retrograde condensate
are overmature (after Thompson, 1987; Holba et al., 1996).

Fig. 10. (a) 20S/(20S+20R) aaa C29 sterane versus API gravity. 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.

gasoline compositional ratios shown in Table 4.
Fig. 12 is a plot of two light hydrocarbon parameters
(n-heptane/methylcyclohexane against toluene/n-heptane) used to identify those samples a€ected by biodegradation-water washing and evaporative fractionation
processes. High toluene/n-heptane ratios for the majority of the 22 oils suggest that evaporative fractionation
processes have occurred to varying extents. Formation
of retrograde condensates, such as those described previously, from pristine oils by post-generative processes
like evaporative fractionation also results in the formation 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 pristine-like oils, respectively, together with associated retrograde 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 paran
distribution showing n-alkanes eluting between nC5 and
approximately nC30. Other features include high pristane/phytane ratios and a strong abundance of methylcyclohexane (MCH). Fig. 13(a) is a Group 1 retrograde
condensate exhibiting prominent concentrations of
hydrocarbons eluting between nC5 and nC18, but devoid
of higher molecular weight species above nC18, indicating 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
below nC12, 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 paran
distribution indicated by the abundance of odd carbonnumbered n-alkanes eluting between nC20 and nC35.
Other features, similar to those of Group 1 oils, include
high pristane/phytane ratios and relatively high concentrations of methylcyclohexane (MCH). Fig. 14(a)
and (c), as with Fig. 13(a) and (c), illustrates the formation of derivative retrograde condensates and residual

H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

309

Fig. 12. Light hydrocarbon parameters [n-heptane/methylcyclohexane (F) versus toluene/n-heptane (B)] illustrating changes in oil
composition brought about biodegradation-water washing and evaporative fractionation processes (after Thompson, 1987).

oils from pristine unaltered oils via evaporative fractionation processes. From these examples, it is clear that
evaporative fractionation processes are important geological phenomena a€ecting 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 fractionation processes a€ecting many of the oils.
Evaporative fractionation e€ects, in addition to
altering the gross n-alkane distributions of the NW Java
oils, appear to have also induced changes in the pristane/
phytane ratios of the retrograde condensates and residual oils. Fig. 15 is a plot of Pr/Ph against Pr/n-C17 for
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 abundance of pristane relative to phytane in the residual oils.
These observations, therefore, have obvious and important implications in oil correlation studies that compare
pristane and phytane distributions in retrograde condensate, 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 paranic contents,
and a de®ciency in low molecular weight aromatic
hydrocarbons (Fig. 4 and Table 2). These oils are located in the shallowest reservoirs in the basin, where

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H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

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 hydrocarbons.

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 chromatograms of Group 1 oils that illustrate the e€ects 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 retrograde condensates formed by evaporative fractionation 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 methylcyclohexane (MCH), supporting previous assertions that saturated hydrocarbons are less likely than aromatic
hydrocarbons to be a€ected by evaporative fractionation and water washing processes. In addition, within

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.

Fig. 15. E€ect of evaporative fractionation on pristane/phytane versus pristane/n-C17 parameters for Group 1 and Group
2 pristine-like oils. Pristane/phytane values are higher in retrograde condensates, and lower in residual oils relative to the
parent pristine-like oil in each group.

H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

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 e€ects of water washing as
observed by the loss of benzene, toluene and xylene.

311

Concomitant with water washing, this oil may have also
undergone limited microbial degradation resulting in
removal of the C5±C7 linear alkanes. With respect to the
light aromatic components in retrograde condensate
PGD-3 and pristine-like oil TGB-24, no loss of benzene,

Fig. 16. Whole oil gas chromatograms of Group 1 oils illustrating the e€ects of water washing on a retrograde condensate example (a)
formed from a related pristine-like oil (c). (a) and (b) are examples of Group 1 retrograde condensates formed by evaporative fractionation processes, and (c) an inferred pristine-like Group 1 oil.

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H. Napitupulu et al. / Organic Geochemistry 31 (2000) 295±315

toluene or xylene appear to have occurred. These data
suggest that water washing processes have a€ected, 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 e€ect of water washing in these instances can
clearly be discerned against additional post-gen