petroleum systems of indonesia-libre 2

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Marine and Petroleum Geology 25 (2008) 103–129

Petroleum systems of Indonesia

Harry Dousta,, Ron A. Nobleb,1

aVrije Universiteit Amsterdam, The NetherlandsbUnocal Indonesia Company, Jakarta, Indonesia

Received 13 October 2006; received in revised form 13 March 2007; accepted 4 May 2007

Abstract

Indonesia contains many Tertiary basins, several of which have proven to be very prolific producers of oil and gas. The geology andpetroleum systems of these productive basins are reviewed, summarized and updated according to the most recent developments. We

have linked the recognized petroleum systems to common stages in the geological evolution of these synrift to postrift basins and

classified them accordingly. We recognize four Petroleum System Types (PSTs) corresponding to the four main stages of geodynamic

basin development, and developed variably in the different basins depending on their depositional environment history: (i) an oil-prone

Early Synrift Lacustrine PST, found in the Eocene to Oligocene deeper parts of the synrift grabens, (ii) an oil and gas-prone Late Synrift

Transgressive Deltaic PST, located in the shallower Oligocene to early Miocene portions of the synrift grabens, (iii) a gas-prone Early

Postrift Marine PST, characteristic of the overlying early Miocene transgressive period, and (iv) an oil and gas-prone Late Postrift

Regressive Deltaic PST, forming the shallowest late Tertiary basin fills. We have ascribed the petroleum systems in each of the basins to

one of these types, recognizing that considerable mixing of the predominantly lacustrine to terrestrial charge has taken place.

Furthermore, we have grouped the basins according to their predominant PSTs and identified ‘‘basin families’’ that share important

aspects of their hydrocarbon habitat: these have been termed proximal, intermediate, distal, Borneo and eastern Indonesian, according to

their palaeogeographic relationship to the Sunda craton of Southeast Asia.

r 2007 Elsevier Ltd. All rights reserved.

Keywords: Indonesia; Tertiary; Sedimentary basins; Rifts; Petroleum system; Petroleum system types

1. Introduction

Petroleum exploration in Indonesia has had a long and

successful history. Some of the earliest oil production of

the modern age comes from shallow fields in Java and

Sumatra, and discoveries have been made throughout the

past century up to the present day. Knowledge of the

petroleum habitat has been encouraged since the 1970s,partly thanks to an enlightened policy of cooperation by

the petroleum community in Indonesia, through technical

conferences and through publications sponsored by the

Indonesian Petroleum Association (IPA). This cooperation

amongst industry participants has grown from the need to

develop a comprehensive understanding of the large

number of sedimentary basins and petroleum provinces

encountered throughout the archipelago.

Description of the petroleum systems of Indonesia can

thus rest upon a foundation of an extensive, comprehensive

and reliable database that can be found, for the most part, in

the public domain. Many of the publications are detailed,

but several overviews have been published through the

years, concentrating particularly on the various charge andreservoir systems as well as on the common play types

represented in the different basins. In this paper, we make

reference only to a restricted number of ‘‘key’’ publications

that provide good summaries of the various themes or areas.

They all provide access to a much larger literature, which we

have used to prepare both text and figures.

In an early and excellent publication, Soeparjardi et al.

(1975) identified important characteristics of the basins

which were known to contain hydrocarbon accumulations:

namely, Eocene to Miocene transgression, followed by

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0264-8172/$ - see front matterr 2007 Elsevier Ltd. All rights reserved.

doi:10.1016/j.marpetgeo.2007.05.007

Corresponding author.

E-mail address: [email protected] (H. Doust).1Current address: Anadarko Indonesia Company, Jakarta, Indonesia.

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mid-Miocene to Pliocene regression and Quaternary

transgression. They also described the six main reservoir

systems that were known in productive basins-transgressive

clastics, regressive clastics, deltaic deposits, carbonate

platform complexes, pinnacle reefs and fractured volcanics.

Their publication formed the basis for all subsequent

attempts to review the hydrocarbon habitat of Indonesianbasins, and provides the foundation of the approach

presented here.

Following the formalization of the petroleum system

concept (Magoon and Dow, 1994), Howes and Tisnawijaya

(1995) used a modified and more practical approach to

summarize the petroleum systems of Indonesia in a

landmark paper. They tabulated 34 petroleum systems

associated with documented accumulations as well as

others that were thought to exist but in which no

discoveries had yet been made. For the known systems,

they presented plots of cumulative ultimate discovery

volumes (in million barrels of oil equivalent) versus number

of fields in discovery order (so-called creaming curves).

We refer to many of these plots in this publication.

Importantly, they noted that many of the 34 systems did

not contain a single area of mature source rock, but

represented in fact a composite of several distinct source

areas. In order to work with manageable numbers of

systems, and thereby identify the similarities and differ-

ences between them, we believe it is necessary to groupindividual petroleum systems into families. Doust (2003)

presented a proposed framework for the identification of

petroleum systems in southeast (SE) Asia, and this is

applied in the classification presented here.

There are many petroleum-bearing sedimentary basins in

Indonesia (Darman and Hasan Sidi, 2000), the number

depending on whether each individual synrift graben is

counted, or whether they are grouped by province. We

have followed the classification used by the IPA for their

set of field atlases (Indonesian Petroleum Association,

1997–1991), which also represents common usage. Descrip-

tion of the geology and hydrocarbon habitat of these

basins is complicated by the plethora of local formation

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Fig. 1. Location map of Indonesian basins, grouped according to resource volumes. Those with less than 10 MMboe do not contain petroleum systems

described here. MM, million; B, billion; boe, barrels of oil-equivalent.

H. Doust, R.A. Noble / Marine and Petroleum Geology 25 (2008) 103–129104


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names (many of them essentially lithofacies and lithofacies

equivalents) and conflicting age attribution. We have

adopted the stratigraphies from the atlases in general,

though we have modified them where we felt this was

justified. We have reviewed in detail the petroleum systems

with commercial, or soon to be commercial, fields only.

Throughout Indonesia other potential systems are devel-oped (indicated, for instance, by oil seepages in frontier

basins), but our main object here is to identify and emphasize

the main characteristics of the successful and productive

ones, so that the lessons can be applied elsewhere.

2. Tectonostratigraphic evolution of far east Tertiary

petroleum basins

The sedimentary basins of Indonesia form the core of a

family of Tertiary basins developed throughout SE Asia

(Fig. 1). Though they may differ slightly in age and

development, they share many characteristics: nearly all of

them pass through an early Tertiary synrift to late Tertiary

postrift geological history, they all have an almost

exclusively land–plant and/or lacustrine–algal charge

system and they are characterized by rapid short wave-

length sedimentary variations involving a distinct suite of

depositional environments and their associated lithofacies.

In nearly all of the basins, four stages of tectonostrati-

graphic evolution can be recognized (Fig. 2):

1. Early Synrift (typically Eocene to Oligocene)—corre-

sponds with the period of rift graben formation and the

following period of maximum subsidence. Often deposi-

tion is limited to early-formed half-grabens.2. Late Synrift (Late Oligocene to Early Miocene)—

corresponds with the period of waning subsidence in

the graben, when individual rift elements amalgamated

to form extensive lowlands that filled with paralic

sediments.

3. Early Postrift (typically Early to Middle Miocene)—

corresponds with a period of tectonic quiescence

following marine transgression that covered the existing

graben–horst topography.

4. Late Postrift (typically Middle Miocene to Pliocene)—

corresponding to periods of inversion and folding,

during which regressive deltas were formed.

A final transgressive period characterizes the Quatern-

ary, but it has no significance to petroleum habitat and will

not be referred to further.

These stages can be related to the area’s plate tectonic

evolution (Hall, 1997), particularly to early Tertiary

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Fig. 2. Chronostratigraphy of Indonesian petroliferous basins, showing stages, background tectonics and geodynamic events. Seafloor spreading events

and continental collisions are from Longley (1997).

H. Doust, R.A. Noble / Marine and Petroleum Geology 25 (2008) 103–129 105


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transtensional stresses generated by the India–Asia colli-

sion (including opening of the South China Sea (30–20 Ma)

and with late Tertiary uplift and inversions caused by

collisions and plate rotations. They can also be correlated

with the four phases or stages of SE Asian tectonostrati-

graphic evolution as defined by Longley (1997). His Stage I

(50–43.5 Ma) corresponds to a period of early continentalcollision, which led to the formation of many of the older

synrift grabens, while his Stage II (43.5–32 Ma), during

which major plate reorganizations took place, resulted in

the formation and active subsidence of a younger popula-

tion of rifts. Stage III (32–21 Ma), contemporaneous with

sea floor spreading in the South China Sea, was a period

during which rifting ceased, local inversion took place

and a major marine transgression marked the beginning

of postrift development. Stage IV (21–0 Ma) was chara-

cterized by a maximum transgression, followed by several

collision phases that led to inversions, uplift and the

development of regressive deltaic sequences. This is equi-

valent to the early and late postrift stages.

3. Relationship of tectono-stratigraphic history to petroleum

system development

For many years, it has been recognized that most

sedimentary basins have complex histories that can be

divided into stages or cycles (mentioned above). Kingston

et al. (1983) described a method by which various basin

types could be categorized by their sequence of evolu-

tionary stages. SE Asia Tertiary basins were classified as

two-stage wrench or shear basins, in recognition of their

early synrift phase with probable transtensional origin,followed by almost inevitable inversions related to the

inherent instability (reflected in the poor preservation

potential of this basin type). They also noted that each

basin stage typically comprised a transgressive–regressive

sedimentary cycle, which today we can recognize as a

first order sequence, containing lowstand, transgressive

and highstand systems tracts, bounded by regionally cor-

relatable horizons.

It is our belief that in many basins, petroleum systems

can be related directly to basin stage, since first-order

sedimentary sequences often contain source, reservoir and

seal rocks, frequently in a favourable vertical succession.

We have applied this concept to Indonesian petroleum

systems, albeit with some modifications in recognition of

the synrift development (which does not lend itself easily to

the classic model of sequence stratigraphy) and the rapid

facies variations.

Doust and Lijmbach (1997) and Doust (1999) proposed

that almost all of the petroleum systems developed in

Indonesian basins could be ascribed to one of four basic

types, each with its characteristic source, reservoir and seal

facies. By classifying them in this way, it is possible to make

broad comparisons of basin prospectivity. Recognition of

discrete petroleum systems depends on geochemical corre-

lation between source rocks and their related hydrocarbon

accumulations. In Indonesia, this is rendered very difficult

by the fact that: (a) many source rocks are thin and/or

widely distributed within the sequence, (b) most oils and

gases derived from any particular type of source rock (e.g.

deltaic or lacustrine) cannot be readily distinguished from

others in the same group, and (c) a large amount of mixing

of lacustrine and terrestrial oils appears to have takenplace. Ten Haven and Schiefelbein (1995) nevertheless were

able to define whether charge in each basin in Indonesia

was derived from Tertiary lacustrine, terrigenous or marine

source rocks or whether it came from Mesozoic sources: In

fact, they used this to define which petroleum systems were

present, in much the same way as presented here—

although we relate the petroleum systems more specifically

to the basin development stage.

The extensive mixing is probably a consequence of the

limited development of regional seals, and its effect is that

charge from some of the petroleum system types defined

here contributes to accumulations in younger petroleum

system types.

The four basic petroleum system types (or PSTs; for more

detail see Doust and Lijmbach (1997), where they are

referred to as hydrocarbon systems) correlate well with the

four basin stages described in the previous section, and have

the following characteristics (for a summary see Fig. 15):

1. Early Synrift Lacustrine PST : This is strongly oil prone

due to the widespread development of organic-rich

lacustrine type I/II source rocks, and is common in

western Indonesian basins. Reservoirs comprise fluvio-

lacustrine clastics and volcaniclastics of limited quality,

intimately interbedded with non-marine shales. A com-prehensive summary of this PST is given by Sladen (1997).

2. Late Synrift Transgressive Deltaic PST : Deltaic or

paralic sequences with an overall backstepping devel-

opment typify this PST. Source rocks comprise type

II/III coals and coaly shales that produce both oil and

gas, interbedded with fluvio-deltaic sand reservoirs and

seals, often of excellent quality.

3. Early Postrift Marine PST : Source rocks in this principally

marine shale sequence are mainly lean and/or gas-prone.

The main reservoirs comprise open marine carbonates,

including reefal buildups. This PST contains the only

widespread regional seal in many Indonesian basins.

4. Late Postrift Regressive Deltaic PST : This PST has

similar environments and characteristics as the Late

synrift PST except that the overall deltaic development

is typically progradational rather than retrogradational.

In most cases, it lies at depths too shallow for

hydrocarbon generation, but where major deltas are

developed on continent margins, it represents the

dominant system.

4. Aspects of the hydrocarbon system

In this section, we summarize the characteristics of the

main elements common to Indonesian petroleum systems.

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This is possible because the basins share a relatively limited

number of environmentally related lithofacies and have

similar tectonic settings. The basins situated proximal to

the Sunda shelf have a stronger component of proximal

lacustrine–deltaic lithofacies throughout their develop-

ment, while those at the edges of the Tertiary continental

margin develop more marine facies characterized by thickmarine shales and carbonates. This is reflected directly in

their hydrocarbon habitat, so that the petroleum systems

and plays developed in the various basins can be linked

directly to the overall three-dimensional facies/environ-

mental sequence and the tectonic history.

4.1. Source rocks

The geochemistry of oils and source rocks from

Indonesia has been reviewed by many authors, and there

is general consensus that the host organic matter originated

from land–plants and/or algal–lacustrine source material.

A summary of information on source types in the major

petroleum provinces of Indonesia is presented in Fig. 3.

The source rock depositional environments, described in

detail by Todd et al. (1997) and by Schiefelbein and

Cameron (1997), are as follows:

Lacustrine: Lacustrine oils originate from mainly algal

type I/II kerogen, which accumulated in deep or shallow

fresh to brackish water lakes, primarily in the early synrift

stage of basin development. Several sub-families have been

recognized (e.g. in Central Sumatra, Williams and Eubank,1995) which are linked to variable water chemistry and the

admixture of terrestrial organic detritus.

Paralic or deltaic: Hydrocarbons from source rocks of

this type arise from coals and coaly shales deposited in a

variety of fluvial to estuarine lower coastal plain environ-

ments, typically in the late synrift and late postrift basin

stages. The kerogen is mainly of terrigenous (land plant)

origin, type II/III, but may contain some algal elements

derived from floodplain lakes. In general, a mixture of oil

and gas is generated.

Marine: Hydrocarbons generated from marine source

rocks have geochemical characteristics that are broadly

similar to those from the paralic environments in that

they are derived from detrital land plant organic matter.

The typical type II marine source rocks seen extensively in

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Fig. 3. Source rock types in Indonesian basins based on oil typing from Todd et al. (1997), showing lithology, age, and the basin stage in which they are

developed and total associated reserve volumes in million barrels of oil-equivalent. ES, Early Synrift; LS, Late Synrift; EP, Early Postrift; LP, Late

Postrift; HC, hydrocarbons.



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other parts of the world are not present in any abundance

here. However, the presence of marine biomarkers (e.g.

C30-steranes in some oils from Java and North Sumatra)

indicate that the source rocks were deposited in a marine

setting, even though the bulk of the organic material

represents transported land plant material. In the Maha-

kam Delta, source rock facies have been identified recentlyin deep water turbidites where once again, the organic

matter is predominantly of terrestrial origin (Dunham

et al., 2001; Peters et al., 2000; Guritno et al., 2003; Saller

et al., 2006). Away from deltaic depocenters it is likely that

marine shales of the early postrift interval, many of which

contain low percentages of disseminated terrestrial organic

material, have generated significant quantities of gas. In

eastern Indonesia, oils of marine clastic, marly and

carbonate affinities occur. These oils have geochemical

characteristics typical of marine oils globally (Peters et al.,

1999) and are derived from either pre-Tertiary source rocks

(e.g. onshore Seram), or from Miocene marine marls

(e.g. the Salawati Basin).

As was noted by Shaw and Packham (1992), the higher

than average heat flow experienced in several Tertiary

Indonesian basins plays an important role in raising the

hydrocarbon prospectivity of some of the shallower basins.

It is noticeable that many oils show a mixed lacustrine

and paralic geochemical signature (e.g. in South Sumatra).

These may arise from shallow lake margin facies or from

mixing of charge from two distinct source rocks during

vertical migration. This mixing, plus the overall similarity

of geochemical fingerprints, complicates the identification

of a discrete source system for groups of geochemically

related oils, as proposed in the original definition of apetroleum system (Magoon and Dow, 1994).

4.2. Reservoirs

Reservoir rocks are abundant throughout Indonesian

basins in a variety of sedimentary facies. As with source

rocks, their development is closely related to depositional

environment and basin evolution.

Non-marine siliciclastics: These characterize the early

synrift section of proximal basins. They typically comprise

fluvio-deltaic sands that are often thin, with a significant

content of lithic material and limited sorting. Porosities are

below 20% and permeabilities up to 100 mD and, in

general, the quality and development are highly variable.

Alluvial fans adjacent to basin bounding faults may

contain coarse clastics, but are poorly sorted and shale-

out rapidly.

Fluvio-deltaic to shallow marine siliciclastics: These facies

form the best clastic reservoirs of Indonesia, with porosities

up to 25% and often multi-Darcy permeabilities. Delta

plain and coastal sands, derived from older cratonic areas,

provide the best reservoirs. These typically occur within the

late synrift package. Late postrift sands of Sumatra and

Java often have a significant lithic/arkosic component that

reduces the permeability. The cyclic regressive units of the

late postrift deltaic sediments in Kalimantan, on the other

hand, have excellent reservoir properties.

Deep marine siliciclastics: Turbiditic sands have provided

a focus for exploration in recent years, primarily in the

offshore Kutei–Mahakam Delta (Dunham and McKee,

2001). Drilling activity in the deepwater Makassar Straits

has shown that reservoir quality sands were deposited inslope and basin floor settings (Dunham and McKee, 2001).

Sands deposited in channel–levee complexes across the

slope and in unconfined submarine fans have successfully

been targeted using 3D seismic. Study of the link between

the slope and the basin floor provides insights into sand

distribution and the location of potential reservoirs (Saller

et al., 2004).

Platform and reefal carbonates: These reservoirs, char-

acteristic of the more distal late synrift areas and postrift

stages, provide locally high porosity reservoirs (o38% in

places). In general, the reefoid and back-reef facies have the

best reservoir characters, while platform carbonates have

more limited potential.

4.3. Seals

Seals can also be closely related to basin stage and are

either intra-formational or more regionally developed.

Interbedded deltaic seals: Intra-formational shale seals

are typical of deltaic sequences, where they commonly act

as top seals for interbedded sands or, in combination with

faults, as side seals to fault closures (often contributing clay

smear). Those of the late synrift were described in Kaldi

and Atkinson (1997), who reviewed shale interbeds from

the Talang Akar Formation of Northwest Java in terms of seal capacity, geometry and integrity. The main sealing

lithofacies, ranked in order of increasing seal capacity,

comprise delta plain, channel, prodelta and delta front

shales. These conclusions are probably equally applicable

to the deltaic sequences of the late postrift.

Thicker seal formations and regional seals: The marine

shales of the early postrift represent the only genuine

regional seals of the Indonesian basins. They may act as

ultimate seals to the late synrift deltaic sediments or they

may completely encase the carbonate build-ups of the early

postrift.

4.4. Traps

A variety of trap types are present in Indonesian basins,

depending on the location and tectonic history. The

greatest concentration of traps is to be found in the basins

adjacent to the Sumatra–Java arc, where extensive thrust

belts are developed, and in the continent margin sequences

of eastern Kalimantan. Elsewhere, traps are located above

rift boundary faults that have been reactivated during

inversion and in the extensive reefoid carbonate provinces

in distal parts of the foreland basins. The following trap

types are commonly developed—they often define the plays

that are present.

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Folded dip closures: NW–SE to W–E trending anticlinal

dip closures are abundant in Sumatra and Java basins

(which developed into foreland basins in the late postrift

stage), where they may affect the entire syn- and

postrift sequences. They form elongate drag folds, are

frequently cross-faulted and are often bounded by reverse

faults or thrusts nucleated above synrift boundary faults(the so-called ‘‘Sunda folds’’). Many of these structures

are related to wrench inversions of the synrift and

are located adjacent to graben boundary faults. At

shallower levels, unfaulted drape closures may occur,

especially where structural growth has been continuous,

or where structural detachment has taken place in postrift

shales.

Dip/fault closures: Many individual traps related to

anticlinal structures demonstrate fault/dip closure. Foot-

wall closures are especially common: they may be simple or

complex, and are sometimes related to intrabasinal horst

blocks or structural noses.

Synsedimentary structures: In the Kutei and Tarakan

basins growth-fault related structures, many of them

inverted by subsequent movements, are developed. Traps,

usually in the hangingwall block, may be dip closed or fault

related. In the deeper water, toe-thrust anticlinal structures

fall into this category.

Basement topography: A relatively small number of fieldsare found in basement high blocks, where the reservoir is

frequently represented by fractured rocks the pre-rift

sequence. In other cases, onlap onto the basement surface

appears to define the trap morphology.

Reefoid carbonate structures: Carbonate reservoirs occur

in anticlines, but trapping is often assisted by platform

growth or reefoid relief. In most cases, these are of

relatively low relief, but in the East Natuna and Salawati

basins, high relief pinnacle reefs are developed.

Clastic stratigraphic traps: Sedimentary pinch-out often

appears to contribute to trapping, but rarely is the main

constituent of a trap. Exceptions are where channels cut

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Fig. 4. Stratigraphic sections of southern and western Indonesian basins, showing basin stage, common formation names, lithology and predominant

depositional environments (thicknesses are not indicated).



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structural noses in the deltaic sequences of the late syn-

and postrift section. Deep water plays of the Mahakam

Delta may also have a component of stratigraphic

trapping, particularly in ponded mini-basins in intra-slope

environments.

5. Summary of Indonesian petroleum basin geology

In this section, we summarize the stratigraphic and

structural development of the various productive basins of

Indonesia, and relate them to the petroleum system

framework presented above (Figs. 4 and 5). It should be

noted that many of these are composite basins, comprising

a number of separate synrift grabens overlain by a blanket

of postrift deposits. In many cases, the facies vary

considerably across the various provinces, depending on

the proximity to or distance from the contemporary open

ocean (in the synrift) and to zones of active deformation

(in the postrift).

Note that in ascribing reservoir levels to petroleum

system types and basin stages, we have included PST 3

basal carbonates within PST 2 in those areas where,

because there is no regional seal between them, they

essentially form one combined group of reservoirs.

Examples of this include areas where the Batu Raja

Formation directly overlies the Talang Akar Formation

in the South Sumatra Basin. Unless stated, we have

followed the petroleum systems classification as defined

by Howes and Tisnawijaya (1995).

5.1. North Sumatra Basin

The North Sumatra Basin comprises a series of north–

south trending ridges and grabens formed in Early

Oligocene time (Fig. 6). Almost the entire basin fill is

marine, much of it, especially in the north, comprising

basinal deeper marine claystones, shales and shallow water

reefoid limestones, the latter developed on structural highs.

Regressive shallow water deltaic facies are found in the

southeast. The sequence is predominantly argillaceous and

the division into four-basin stages is somewhat arbitrary.

Early Synrift (Early Oligocene): Coarse-grained con-

glomerates and bioclastic limestones are recorded at the

bases of the graben fills and on their adjacent highs.

Late Synrift (Late Oligocene): This comprises thick,

deep marine claystones, mudstones and dark shales of

the Bampo Formation. These represent the main source

rock for the gas in the northern part of the basin:

although lean (1% TOC, type III), they are very thick

and may reach high maturities.

Early Postrift (Early to Middle Miocene): This se-

quence, corresponding to the Peutu Formation, com-

prises thick basinal deeper marine shales and marls, with

extensive reefoid carbonate buildups developed on

structural highs. The latter form excellent reservoirs,

with porosities averaging 16% in the Arun field. Deep

water sandy facies (Belumai Fm) are present in the

south.

Late Postrift (Middle Miocene to Pliocene): This

regressive sequence comprises the argillaceous Baong

Fm (in which turbidite sands occur) and the overlying

paralic shales, silts and sands of the Keutapang and

Seurula formations. In the north, deeper marine faciescontinued, while towards the southeast, these forma-

tions became shallower with the deposition of regressive

deltaic sands of moderate to good reservoir quality.

Tectonic development in the basin is subdued. Following

the Palaeogene rift formation, a Late Oligocene local

unconformity and a Mid Miocene regional unconformity

are recorded, while the deltaic sequence in the southeast

was folded during successive wrench phases in the Middle

Miocene to Pliocene.

5.1.1. Petroleum systems

Two major systems are recognized:

The Bampo – Peutu (!) petroleum system (Buck and

McCulloh, 1994) is present in the north. It is sourced from

the deep marine Bampo Formation, with a possible

secondary contribution from the Miocene Peutu Forma-

tion. The main reservoir/traps are carbonate build-ups of

the Peutu (or Arun) Formation, with minor contribution

from the equivalent sandy Belumai Formation and base-

ment. Fifteen trillion cubic feet (tcf) of gas and 1 billion

barrels (bbl) of condensate, respectively, have been located

in 10 fields, dominated by the Arun field with almost 14 tcf

of gas. This system comprises a late synrift source of earlypostrift affinity and early postrift reservoir and traps.

The Baong – Keutapang (!) petroleum system, located in

the southeast, is more oil-prone and contains many of the

shallow fields that produced the first reserves in Indonesia.

Charge is thought to be derived from marine/deltaic coaly

source rocks of the Baong Formation, but re-migration

from deeper reservoirs may also contribute. Reservoirs

occur in the rather ill-sorted sandy deltaic facies of the late

postrift Keutapang and Seurula formations, representing

cyclic regressive phases. About 75% of the fields produce

or produced both oil and gas, and all hydrocarbons are

characterized by API gravities of over 40. Traps are mainly

dip closures related to NW–SE trending folds, and most

are faulted to some extent (only a few are clearly related to

thrusts). Stratigraphic pinch-outs appear to contribute to

trapping in some cases, but in only one field (Peudawa)

does the trap appear to be primarily stratigraphic.

Howes and Tisnawijaya (1995) distinguished a potential

third petroleum system in the basin, the Miocene – Belumai

( ) petroleum system to which a few fields in the far south

of the basin (e.g. Wampu) may belong.

Creaming curves for oil/condensate and gas (Howes and

Tisnawijaya, 1995) demonstrate that North Sumatra is a

highly mature province that has been explored with

moderate efficiency.

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Fig. 5. Stratigraphic sections of northern and eastern Indonesian basins, showing basin stage, common formation names, lithology and predominant

depositional environments (thicknesses are not indicated).



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5.2. Central Sumatra Basin

The Central Sumatra Basin comprises a number of

separate synrift grabens below a postrift sequence (Williams

and Eubank, 1995). Most of the many hydrocarbon

accumulations present lie directly above or adjacent

to the synrift grabens, a consequence of the relatively

shallow burial and immaturity of the postrift sequence

(Fig. 7).

The five productive grabens (Bengkalis, Aman, Balam,

Tanjung Medan and Kiri/Rangau) contain similar strati-

graphic successions with relatively proximal facies associa-

tions (Williams and Eubank, 1995). They were formed

along pre-Tertiary structural trends (north–south and

WNW–ESE) and originated as half-grabens in an oblique

extension stress regime. The four-stage basin history can be

recognized, as follows:

Early Synrift (Late Eocene to Oligocene): Pematang and

Kelesa formations. These consist of an association of

alluvial, shallow to deep lacustrine and fluvio-deltaic

facies represented by laminated shales, silts and sands

with coals and conglomeratic intervals. Deep lake

organic rich shales containing algal/amorphous material

with thin sands (Brown Shale Formation), and shallow

lake light grey shales with humic coals ensure that

charge from the early synrift is mixed lacustrine and

terrestrial, mainly type I/II, within which four oil

families have been distinguished (Katz, 1995). The best

reservoirs are found in fluvio-deltaic sands, where

porosities and permeabilities may be up to 17% and

100 mD, respectively.

Late Synrift–Early Postrift (Late Oligocene to Early

Miocene): This sequence, equivalent to much of the

Sihapas Group, includes several paralic facies that

record a gradual transgression: The Menggala Forma-

tion is still fluvial, but is overlain by shallow marine

sandy (Bekasap Formation) and argillaceous (Bangko

Formation) facies, the latter forming a regional seal.

The Menggala and Bekasap formations contain the best

reservoirs of the basin, with porosities of the order of

25% and permeabilities of up to four Darcies.

ARTICLE IN PRESS

Fig. 6. North Sumatra Basin—simplified location and structure map

showing depocenters and oil/gas fields classified according to the basin

stage in which they occur.

Fig. 7. Central Sumatra Basin—simplified location and structure map

showing synrift basins (inferred to be areas of hydrocarbon generation)

and oil/gas fields classified according to the basin stage of the reservoir in

which they occur. Oil families (1–4) and typical trap types described by

characteristic fields are from Williams and Eubank (1995).



11/27

Early Postrift (Early to Middle Miocene): This includes

the distal marine facies of the Sihapas Group, which

records the final stages of transgression (Duri Forma-

tion delta front sands and shales) followed by the period

of maximum Tertiary flooding (Telisa Formation shales

and silts).

Late Postrift (Middle Miocene to Quaternary): This stagerepresents the Late Tertiary sedimentary fill of the basin,

and includes regressive deltaic and alluvial sediments

interrupted by several unconformities. Only the deepest

part of this sequence (Petani Formation with marine

shales, sands and coals) has significance for petroleum

accumulation.

Three phases of geodynamic development are recognized:

An Eocene–Oligocene extensional phase with four

sub phases as indicated here (Williams and Eubank,

1995), leading to formation of the synrift grabens and

early deformation of the sedimentary fill (Shaw et al.,

1997). The first three sub-phases correspond to the

early synrift period, while phase 4 belongs to the late

synrift.

1. Early Eocene: N–S and NW–SE shearing and

formation of isolated rifts and half grabens, with

the major boundary faults on the western flanks.

2. Middle Eocene: rapid subsidence.

3. Oligocene: continued subsidence and episodic dextral

wrenching.

4. Late Oligocene–Early Miocene: waning subsidence

accompanied by uplift.

An Early–Middle Miocene phase of uplift and gentlefolding accompanied by wrench faulting along a

NW–SE (Barisan) trend. This period follows the early

postrift. It was responsible for the formation of most of

the structural traps, such as the forced drapes over the

basin margin faults.

Movement continued up to the Plio-Pleistocene in the

form of NW–SE dextral wrench faulting, corresponding

to the final stage of postrift development.


In the Central Sumatra Basin almost all of the

hydrocarbons appear to have been derived from lacustrine

to terrestrial source rocks of the early synrift stage, possibly

with some contribution from coals of the late synrift. Four

families of oils are recognized (Williams and Eubank,

1995), essentially related to variations in the synrift source

facies (Fig. 7). Potential source beds in the postrift are

immature.

Reservoir levels occur throughout the sequence,

although the bulk of the fields are found at multiple levels

below regional seals in the early postrift (Bangko and

Telisa formations). We can thus recognize a single, though

complex, petroleum system, called the Pematang – Sihapas

(!) system as defined by Howes and Tisnawijaya (1995) with

three subdivisions: Pematang – Pematang (approximately

20 accumulations), Pematang – Sihapas (approximately 90

accumulations) and Pematang – Duri (approximately 23

accumulations).

The following trap types can be recognized in the IPA

Atlas (Indonesian Petroleum Association, 1991a, b) listing

of just over 100 fields: (1) dip closures related to simple

folds and drape (59 accumulations), thrusts (44 accumula-tions) and wrench faults (7 accumulations), affecting both

syn- and postrift sequences, (2) fault-dip, mainly footwall

closures (22 accumulations), and (3) basement topography

(2 accumulations only). In 12 accumulations, stratigraphic

pinch-outs appear to contribute to trapping. There appear,

however, to be no fields in which the trapping is primarily

stratigraphic.

Williams and Eubank (1995) noted that most of the

oilfields are concentrated in drape structures over basement

palaeo-highs and along the eastern flanks of the half

graben rifts updip of the basin centre source rocks, while

others are developed in drag and inversion folds (‘‘Sunda

folds’’) adjacent to the basin boundary faults. Repeated

phases of structural movement are evident from variations

in the thickness of the sequence.

In total about 25 billion barrels STOIIP have been

located in the basin, of which 8 and 4 billion barrels are

located in the Minas and Duri fields, respectively. The

Minas field is the largest in SE Asia. Noticeable is the lack

of gas, illustrative of the dominance of the highly oil-prone

lacustrine charge of Petroleum System 1 (Schiefelbein

and Cameron, 1997). The creaming curve (Howes and

Tisnawijaya, 1995) is indicative of efficient exploration and

a very mature province.

5.3. South Sumatra Basin

The South Sumatra Basin also comprises a series of

semi-connected NNW–SSE trending synrift basins

with a common postrift sequence (Bishop, 2000a). Two

main rift provinces are recognized, both of which

contain hydrocarbon fields. The smaller and more prox-

imal of the two is Jambi, whereas the larger and deeper is

situated in the Palembang area. Most of the oil and

gas fields are concentrated along thrust and fold trends

above or close to the areas of active mature source rocks

(Fig. 8).

Early Synrift (Eocene to Early Oligocene): This

comprises the continental Lahat and Lematang forma-

tions. These are separated by an unconformity, indicat-

ing that at least two phases of rift formation were

involved. Facies include alluvial, lacustrine and brack-

ish-water sediments represented by tuffaceous sands,

conglomerates and claystones. In places the sequence

may be over 1 km thick. The Lahat Formation contains

both source and reservoir rocks, both very variable in

character and quality (Williams et al., 1995).

Late Synrift (Late Oligocene to Early Miocene): The

main part of this sequence comprises a retro-regressive

ARTICLE IN PRESS



12/27

deltaic section belonging to the Talang Akar Formation,

by far the most important reservoir in the basin and

strongly time transgressive. Sediments were derived

from the northeast and the facies deepen south-

westwards from fluvial to basinal. Reservoirs include

delta plain to marine sands, silts and shales. Many of the

sands are quartzose (derived from the Sunda shelf) and

are of good quality with porosities of up to 25%. Coals

and coaly shales of the Talang Akar Formation

represent important type II and III source rocks.

Early Postrift (Early to Middle Miocene): During this

transgressive marine period, platform and build-up

carbonates of the Batu Raja Formation accumulated

above the rift shoulders, while deeper marine shales

(Gumai or Telisa Formation) were deposited above the

synrift grabens. Bathyal environments lay to the south-

west, where the sequence is very thick (over 2 km). The

Batu Raja is in an important reservoir, with porosities of

up to 38% in reefoid facies. The Gumai Formation

represents an excellent regional seal for the underlying

deltaic formations.

Late Postrift (Middle Miocene to Quaternary): During

the late postrift stage, two phases of deltaic prograda-

tion, represented by the Air Benakat and Muara Enim

Formations (also called the Lower to Middle Palem-bang) filled the basin, gradually covering larger areas

as the environment became shallower, so that by

Quaternary times widespread alluvial continental sedi-

ments accumulated. The sands contain reservoirs with

good porosities of up to 25%.

Three main tectonic phases are recognized:

Paleocene to Early Miocene extension and graben

formation;

Early Miocene to Early Pliocene quiescence, with some

normal faulting; and

Pliocene to Recent thick-skinned dextral transpression

and inversion, forming extensive sub-parallel WNW–ESE

anticlinal trends.


The South Sumatra Basin is a large and complex area, in

which multiple hydrocarbon source and reservoir systems

are present. Bishop (2000a), however, related all accumula-

tions to the Lahat – Talang Akar (!) petroleum system, while

noting that considerable mixing of oils derived from lacustrine

and paralic sources is evident. Howes and Tisnawijaya (1995)

also recognized only one PS, the Talang Akar (!).

From our analysis, based on Indonesian PetroleumAssociation (1990), we believe that four distinct areas can

be distinguished (Fig. 8). In the absence of more precise

geochemical typing, we cannot clearly ascribe each of these

to an individual petroleum system; however, the primary

reservoir level differs in each case and the accumulations

probably have a mixed charge. We can therefore look upon

these as potentially suggestive for four separate petroleum

subsystems.

1. Mainly developed in the Jambi and Merangan sub-

basins, contains oil and gas accumulations in the late

postrift sequence. Assuming that charge is derived from

deltaic source rocks, this petroleum system may be

referred to as the Talang Akar/Palembang – Palembang

(.) PS.

2. Located in the Jambi sub-basin, comprises a single gas

field (Grissik) located in early postrift reservoirs. This

field could also be sourced from the early postrift section

and, if so, could represent a hypothetical Gumai – Gumai

(?) PS.

3. Located in the Palembang area, contains nearly all of

the larger oil and gas fields in the basin and is developed

in the late synrift Talang Akar and early postrift Batu

Raja formations. This is the Lahat/Talang Akar – Talang

Akar (!) PS.

ARTICLE IN PRESS

Fig. 8. South Sumatra Basin—simplified location and structure map

showing inferred areas of active hydrocarbon generation, and oil/gas fields

classified according to the basin stage in which the main reservoir occurs.

The location of potential petroleum sub-systems are indicated (1–4).

Significant fields (410 million barrels) are numbered.



13/27

4. In the Muara Enim area (close to the mountain front),

contains a number of smaller oil fields. This represents

the same type of petroleum system as 1 (above),

although the fact that almost all the fields produce oil

only suggests that they may be either charged from a

separate source area, or that maturity and retention

define a different oil and gas mix.

Traps in both the synrift and postrift sequences are

dominantly anticlinal, associated with elongate inversion

trends, and many are reverse or thrust faulted, especially

where the WNW–ESE fold trends cross N–S—trending rift

boundary fault trends. Several fields are fault dependant

(largely footwall closures), while the relief of traps in the

Batu Raja carbonates is often enhanced by reefoid facies

developments up to 100 m thick. Stratigraphic pinch-out

on structural noses and basement onlap are responsible for

trapping in a small number of syn- to early postrift

accumulations.

The creaming curve for oil suggests that the basin is

mature (Howes and Tisnawijaya, 1995), but there is little

sign of creaming in the gas discovery trend, and more gas

discoveries could be expected.

5.4. The Natuna Sea

The Natuna Sea is divided into two distinct petroleum

provinces by a broad ridge, the Natuna Arch (Fig. 9). The

two have a common early history, but the western basin

complex remained more proximal than the eastern area in

the postrift period.

Early Synrift (Late Eocene to Early Oligocene): The

sequence comprises fluvio-deltaic to fluvial and alluvial

sands of the Lama Formation overlain by shallow

lacustrine shales of the Benua Formation, which locally

form rich oil and gas source rocks. Above these lie

fluvio-deltaic sands and shales of the Lower Gabus Fm.

Late Synrift (Late Oligocene to Early Miocene): Deposition

of lacustrine to fluvio-deltaic sediments of the Keras and

Upper Gabus formations continued during this period.

Early Postrift (Early to Middle Miocene): This period

was marked by a marine transgression and is repre-

sented by shales of the Barat and Arang formations. In

western Natuna, the former are non-marine with coals,

while in eastern Natuna they are open marine. Condi-

tions on structural highs were favourable for the

later development of platform and reefoid carbonates

(Terumbu Formation).

Late Postrift (Late Miocene to Quaternary): During this

period conditions remained shallow marine, partially

restricted, and claystones of the Muda Formation were

deposited. Minor developments of deltaic sands are

recorded locally.

The tectonic history of the Natuna basins is complex,

being significantly different from west to east. Late Eocene

to Oligocene extension phases were responsible for forma-

tion of the rifts throughout the area, while Early to Middle

Miocene NE–SW and NW–SE wrench movements record-

ing complex plate readjustments affected west Natuna,

producing basin margin inversions. In east Natuna, open-

ing of the South China Sea continued until late in the

Tertiary and there is little evidence for compressional

movements. Local to regional unconformities are present

at the end of the early synrift and during the early postrift

periods.


In West Natuna many hydrocarbon fields are associated

with Sunda-type inversion folds formed in the Miocene

adjacent to the main boundary faults of a number of the

rift basins. These dip-closed anticlinal structures are

sometimes associated with thrusts and are often faulted.

The charge is derived from synrift lacustrine shales and the

main reservoirs comprise paralic to marine sands of the

Gabus Formation. Keras and Barat shales form efficient

regional seals. Most of the fields are shallow (maximum

ARTICLE IN PRESS

Fig. 9. Natuna Sea basins—simplified location and structure map

showing inferred areas of active hydrocarbon generation and oil/gas fields

classified according to the basin stage in which they occur.



14/27

2 km), have high API gravities and produce both oil and

gas. In comparison to other basins with similar stratigra-

phy, there are a few fields. This is due to the fact that traps

are largely limited to complex wrench-reactivated bound-

ary fault zones with NE–SW or NW–SE orientations.

Along such fault trends, several small fault-dependant

fields may be clustered. This petroleum system is known asthe Benua – Gabus (!) PS.

One large, as yet non-productive gas field, ‘‘D-Alpha’’ is

present in a large carbonate buildup in eastern Natuna

(May and Eyles, 1985). The gas contains a high percentage

of CO2, suggesting that the charge is derived from deep-

seated sources associated with crustal faults along the

western margin of the South China Sea. Hydrocarbon

charge for this PS may be derived partly from the pre-rift,

but is more likely to be derived from the synrift and it is

referred to here as the Tertiary – Terumbu (.) PS.

The creaming curves for Natuna presented by Howes

and Tisnawijaya (1995) show no signs of creaming.

However, the number of fields is too small to provide

reliable statistics. The complex geology and continuous

tectonics have led to significant issues related to the timing

of migration versus trap formation. Re-migration may be

common, and this is probably reflected in the apparently

poor finding efficiency.

5.5. Sunda and Asri basins

The geology of these two rich hydrocarbon basins shows

many similarities to one another, as described by Bushnell

and Temansja (1986), Wight et al. (1997) and Sukanto et al.(1998). The location of major fields and structural elements

are shown in Fig. 10. The stratigraphic nomenclature is

similar to that of South Sumatra.

Early Synrift (Early Oligocene): This is represented by

the Banuwati Formation, an excellent lacustrine deep

water type I source rock with TOC of up to 8% and a

hydrogen index (HI) of up to 650 mg/g. A basal

marginal alluvial sandy/conglomeratic facies, without

source potential, also occurs.

Late Synrift (Late Oligocene to Early Miocene): This

stage commences with fluvio-deltaic sediments of the

Talang Akar Formation, and continues with Batu Raja

carbonates, as in South Sumatra. Both form excellent

reservoirs. A coaly-shale potential source horizon is also

present, but although rich, is immature at this level.

Intraformational shale seals are found in the upper part

of the sequence (upper Gita member).

Early Postrift (Middle Miocene): Transgressive marine

shales of the Air Benakat Formation form excellent

seals for the underlying reservoirs.

Late Postrift (Late Miocene to Quaternary): This

regressive sequence (Cisubuh Formation) culminates in

deltaic sediments with coals, but lies too shallow to

contribute to hydrocarbon generation.

The tectonics of these isolated basins is highly subdued

compared to other Sumatran basins. The evolution

includes pre- to Early Oligocene rift formation resulting

in half grabens along en-echelon faults, followed by synrift

subsidence and a quiet postrift stage with limited wrench

reactivation.


The Banuwati – Talang Akar (!) PS. Howes and Tisnawi-

jaya (1995) called this the Banuwati–Batu Raja PS. It

includes all of the hydrocarbons trapped in the Sunda

Basin. Deltaic sands of the Talang Akar Formation as well

as onlapping platform carbonates and reefs of the over-

lying Batu Raja Formation form important reservoirs,

often in combination. The fields are concentrated on inter-

basinal highs and horsts and in footwall closures along

faulted noses on the gentle basin flank. A total of about 950

millionboe (barrels of oil-equivalent) has been discovered,

of which 90% is oil. According to Bishop (2000b) 75% of

reserves are located in the Talang Akar Formation.

ARTICLE IN PRESS

Fig. 10. NW Java, Sunda and Asri basins—simplified location and

structure map showing inferred areas of hydrocarbon generation and oil/

gas fields classified according to the basin stage in which the main reservoir

is developed.



15/27

In the Asri Basin, the same elements of the petroleum

system occur, but all accumulations are in Talang Akar

sands as the Batu Raja reservoir is absent. Approximately

500 millionboe has been discovered in nine fields, mainly

in faulted anticlines on the half-graben dip flank. In

the Widuri Field, trapping is assisted by stratigraphic

pinch-out (Carter, 2003).Sukanto et al. (1998) proposed that oil-saturated sands

in the early synrift indicate that a second PS is present in

the Asri Basin. They referred to this as the Banuwati –

Harriet (.) PS. However, there is as yet no commercial

production from it.

The creaming curves of these two basins are different.

Although the Sunda curve suggests relatively efficient

exploration, the 1988 discovery of the Widuri field

confirmed the prospectivity of the Asri Basin at a very

late stage. Short and abundant migration paths from the

basin centres leading to accumulations in the best

reservoirs (Talang Akar and Batu Raja) on the basin

flanks contribute to the efficiency of the system, as does the

presence of a widespread claystone seal.

5.6. Northwest Java

The Northwest Java Basin (Fig. 10) lies both on and

offshore and comprises two main half graben-defined

depocentres: the rich offshore Ardjuna Basin towards the

west and the onshore Jatibarang Basin in the southeast

(Noble et al., 1997). The onshore and nearshore areas

contain clastic wedges derived from the Java hinterland in

the postrift, while the more distal offshore areas remained

dominated by carbonates.

Early Synrift (Late Eocene to Early Oligocene): This

comprises tuffs and minor interbedded lacustrine shales

of the Jatibarang Formation. Volcaniclastics provide the

reservoir facies for some onshore Java fields, whereas

the source rock appears to have a significant deltaic

component, indicative of major contributions from the

overlying Talang Akar Formation.

Late Synrift (Late Oligocene to Early Miocene): As in

South Sumatra, this sequence comprises a transgressive

sequence of fluvio-deltaic, coastal and shallow marine

sands, shales and coals (Talang Akar Formation),

followed by platform and reefoid carbonates (Batu

Raja Formation), both of which are productive.

Early Postrift (Early to Middle Miocene): In contrast to the

basins further to the west, parts of the Java basins remained

in an open to distal marine carbonate environment longer.

This makes it difficult to distinguish early from late postrift

stages. While a number of regressive clastic deltaic phases

are recognized onshore and nearshore in the Cibulakan

Formation, much of the area is characterized by shelf

marine sands (‘‘Massive’’ and ‘‘Main’’) that are important

reservoirs in offshore northwest Java.

Late Postrift (Late Miocene to Quaternary): Platform

carbonates and regressive clastics of the Parigi and

Cisubuh formations reflect a reduction in subsidence

and the onset of inversion movements linked to Pliocene

folding in the south.

The tectonic history of the area (Gresko et al., 1995) can

be traced back to the earliest Tertiary, when cooling

followed metamorphism of the basement rocks. Riftingrelated to dextral wrenching followed in the Eocene

(50–40 Ma), while Middle to Late Miocene collision events

(dated 17–5 Ma) led to repeated local inversions along the

onshore trend.


Howes and Tisnawijaya (1995) recognized two primary

petroleum systems in the area. The dominant one is the

Talang Akar – Main/Massive (!) PS, and is characteristic of

the offshore Arjuna Basin. Charge is derived from the late

synrift Talang Akar coals and coaly shales, while most of

the accumulations are located in Cibulakan sandstones of

the early postrift (‘‘Massive’’ and ‘‘Main’’). Although

multiple reservoirs are represented, only few fields are

found in early and late synrift or late postrift reservoirs.

The second petroleum system proposed by Howes and

Tisnawijaya (1995) is represented by the early synrift

Jatibarang interval, located in the onshore, and which

includes the Jatibarang Field, the only accumulation to

have been located in this highly faulted tuffaceous

reservoir. However, a more detailed study of Northwest

Java by Noble et al. (1997) indicated that the Talang Akar

source system was overwhelmingly the major contributor

of oil and gas in all of the sub-basins, including the onshore

region. Seven primary depocenters were recognized which,based on geochemical data, showed strong oil-source

correlations with Talang Akar coals and carbonaceous

shales. Facies variations within the Talang Akar source

rocks were noted, ranging from fluviodeltaic to marginal

marine. In contrast to other Sunda-style basins in the

Java–Sumatra region, no evidence was found to support

major charge from the lacustrine synrift sequence.

Of the traps described in the IPA Field Atlas volume IV

(Indonesian Petroleum Association, 1989a, b), at least half

are formed by anticlines, many of them highly faulted.

Fault-dependant closures, mainly footwalls are also

common, while a few fields are trapped in reefoid

carbonate mounds. As in other basins, stratigraphic

trapping plays a minor contributory role only.

A separate petroleum system, referred to as the

Biogenic – Parigi (.) petroleum system, has been proposed

to cover shallow biogenic gas accumulations in carbonates

of the late postrift. The charge for accumulations within

this system comes from biogenic conversion of organic

matter at shallow depth, while reservoirs comprise north–

south trending porous bioherms in the southern part of the

NW Java offshore (e.g. APN field).

The Arjuna Basin, as in many offshore provinces, shows

high exploration efficiency for oil and suggests that little

remains to be found. For gas, the curve suggests that as yet,

ARTICLE IN PRESS



16/27

creaming has not been achieved. The Jatibarang sub-basin

curve is typical of complex situations where one, probably

stratigraphically assisted trap, dominates the basin.

5.7. Northeast Java

The East Java Basin area comprises a complex of NE–SW trending troughs, separated by ridges and arches

(Fig. 11). Several of these basins contain hydrocarbon

accumulations while several others represent, as yet,

frontier provinces. As in West Java, there are significant

differences between the clastic dominated onshore basins in

the southwest and the carbonate-dominated areas below

the East Java Sea.

Early Synrift (Late Eocene to Early Oligocene): This is

represented by the Ngimbang Formation, in which a

basal lacustrine to paralic sequence with source rocks is

rapidly succeeded by open marine shales with sands and

carbonates.

Late Synrift (Late Oligocene to Early Miocene): This

sedimentary unit is dominated by platform and reefoid

carbonates of the Kujung and Prupuh formations with,

at the base, marine shales (with thin sands) indicating

that this basin lay close to the continent margin at this

time.

Early Postrift (Early to Late Miocene): At the beginningof this period, the carbonate platforms were drowned

and extensive deeper marine clastics (Tuban and

Woncolo Formation shales and Ngrayong Formation

sands) were deposited. Locally, carbonates persisted and

volcaniclastics are present.

Late Postrift (Late Miocene to Quaternary): Local

tectonics and widespread active volcanism dominated

this period, so that a variety of sequences is developed,

including marine clays, volcaniclastics, carbonates and

sands, deposited in a variety of shallow to deeper water

environments.

The tectonic history passes through Eocene to Early

Oligocene rifting stages, during which a number of half

grabens were formed, followed by a phase of quiescence

and, starting in the late Miocene (at 7 Ma), local

deformation and active volcanism. The onshore fold belt

is complex, and is thought to originate from oblique

wrenching of basement and inversion involving unstable

shale sequences (possibly including gravity-induced growth

faults). In the offshore area east of Madura, active

wrenching along E–W trends has resulted in the formation

of extensive and very young inversion structures (e.g. in the

Kangean Island area north of Bali).


Five petroleum systems have been recognized in North-

east Java, as originally proposed by Howes and Tisnawi-

jaya (1995) and subsequently updated:

1. Ngimbang – OK Ngrayong (.) PS in the Cepu area of East

Java;

2. Ngimbang – Ngimbang (!) PS in the Kangean area

offshore area north of Bali;

3. Ngimbang – Kujung (!) PS in the Cepu amd Madura

basins;

4. Tertiary – Miocene (.) PS in the Muriah Basin—this is

largely a biogenic gas system; and

5. Tertiary – Pliocene (!) PS in the southeast Madura and

north Bali areas, a biogenic gas system.

Fields in the IPA Field Atlas volume IV (Indonesian

Petroleum Association, 1989b) comprise mainly older oil

accumulations from onshore east Java. By far, the majority

of these are located in sandstones and calcareous sand-

stones of the early postrift Ngrayong, OK, Tuban and

Woncolo formations, and with a few exceptions, they occur

in shallow faulted and detached thrust anticlines of small

dimensions and now are shut-in or abandoned. A few fields

occur in reef limestone of the late synrift, while some others

ARTICLE IN PRESS

Fig. 11. East Java Basin—simplified location and structure map showing

inferred areas of hydrocarbon generation and oil/gas fields classified

according to the basin stage in which the main reservoir occurs.



17/27

are found in calcareous and volcanic sands of the late

postrift.

The three petroleum systems of greatest commercial

significance at the present time are the Ngimbang – Kujung

(!), Ngimbang – Ngimbang (!) and Tertiary – Pliocene (!). The

Ngimbang–Kujung PS is actively being pursued in the

Madura and East Java basins, targeting the Kujung andCD carbonate reservoirs (Essam Sharaf et al., 2005).

Further to the east, large offshore gas discoveries have

been made in the late synrift section (e.g. Pagerungan,

Kangean Barat). The origin of this gas is likely to be from

over mature Ngimbang fluvio-deltaic coaly source rocks,

which have also sourced oil accumulations (e.g. JS53).

Biogenic gas fields from the Tertiary–Pliocene system, such

as Terang–Sirasun (1.1 tcf) are also attracting industry

interest.

Exploration in East Java has a long history, dating from

the late 19th century, when many of the small onshore

fields were discovered. Following a long period without

success, the move offshore in the late 1970s has resulted in

a significant rejuvenation of oil discoveries and spectacular

success in locating large gas fields. Onshore exploration has

also been rekindled, with the Kujung play in the Cepu area

bringing new life to an old basin. Recent discoveries in the

Cepu area rank amongst the largest made in Indonesia over

the past 20 years.

5.8. Barito Basin

The Barito Basin of southern Kalimantan (Fig. 12),

though older than most other basins in West Indonesia,

passed through a similar history, with syn- and postriftstages. The maximum transgression interval appears to be

late Oligocene in age. The bulk of the synrift sequence

belongs to cycles of the Tanjung Group.

Early Synrift (Paleocene to Early Eocene): In at least five

rift basins, alluvial to lacustrine sediments, with good

source rock potential accumulated.

Late Synrift (Middle to Late Eocene): During this

period, retroregressive fluvio-deltaic sediments with

coals, followed by marine shales with carbonates were

deposited.

Early Postrift (Oligocene to Early Miocene): During this

period, stable marine conditions prevailed and shallow

marine carbonates of the Berai Formation covered

much of the area. A minor regressive phase is recorded

in the Late Oligocene.

Late Postrift (Middle Miocene to Quaternary): Uplifts

led to the development of regressive deltaic conditions

and the carbonates were drowned by regressive clastics

of the Warukin and Dahor formations.

Early Tertiary rifting along NW–SE trends followed

Late Jurassic to Cretaceous emplacement of the Meratus

ophiolitic complex along the southeast margin of Sunda-

land (Hutchinson, 1996), and led to the development of

horsts and grabens in the Barito Basin. In the Late

Tertiary, continuous compression and uplift of the

Meratus mountains led to the sinistral reactivation of the

graben boundary faults (Satyana et al., 1999).


Tanjung – Tanjung (!) petroleum system: the few fields in

the basin produce oil (with API gravities of 30–401) and gas

and are probably sourced from either highly mature

Tanjung Formation source rocks or a mixture of early

and late synrift lacustrine and deltaic source rocks.

In this complexly deformed basin, hydrocarbons are

trapped in prerift to postrift reservoir levels (basement

and Eocene to Miocene sands) in thrusted and highly

faulted anticlinal structures. At least half of the hydro-

carbons are located in one field (Tanjung, discovered in

1937) and the creaming curve (Howes and Tisnawijaya,

1995) reflects this.

ARTICLE IN PRESS

Fig. 12. East Kalimantan, Barito and Kutei–Mahakam basins—simplified

location and structure map showing Barito Basin depocenter, Mahakam

Delta field trends and oil/gas fields classified according to the basin stage

in which they occur.



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5.9. Kutei–Mahakam Delta Basin

The Kutei–Mahakam Delta Basin is the largest basin in

Indonesia (165,000 km2) and one of its richest hydrocarbon

provinces with several giant fields (Fig. 12). It has a

complex history (Moss et al., 1997), and is one of the only

Indonesian basins to have evolved from a rifted internalfracture/foreland basin into a marginal-sag. Much of the

early basin fill in the Kutei Basin has been inverted and

exposed (Satyana et al., 1999), and the late postrift

Mahakam Delta dominates the prospectivity. The latter

also contains a deepwater continental margin play rare in

other Indonesian basins.

Early Synrift (Paleocene to Early Eocene): Sediments of this

stage comprise alluvial sediments filling in the topography

of NE–SW and NNE–SSW trending rifts in the onshore

Kutei Basin. They overlie a basement comprising late

Cretaceous to early Tertiary deep marine sequences.

Late Synrift (Middle to Late Eocene): During this

period, a major transgression took place in the Kutei

Basin, partly related to rifting in the Makassar Strait,

and bathyal shales with thin sands accumulated.

Early Postrift (Oligocene to Early Miocene): During this

period, bathyal conditions continued to dominate and

several thousand meters of predominantly shales accu-

mulated. On structurally shallow areas open marine

carbonate platforms were developed.

Late Postrift (Middle Miocene to Quaternary): From

Middle Miocene onwards a major passive margin deltaic

sequence prograded into the deep water Makassar Strait,

forming the Mahakam Delta sequence, the primaryhydrocarbon-bearing portion of the basin. A variety of

on- and offshore deltaic depositional environments are

developed in the Balikpapan and Kampung Baru forma-

tions, including deeper water slope and basin floor facies.

Excellent source and reservoir rocks are present, with

interbedded sealing shales. During this period, erosion

reworked large parts of the Kutei synrift sequence.

The tectonic history may be summarized as follows:

Following deformation of the late Cretaceous to earliest

Tertiary basement, extension and rifting associated with

opening of the Makassar Straits continued through to the

end of the Eocene. Oligocene subsidence and sag were

followed by inversion of the early Kutei Basin fill along its

initial boundary faults in the early Miocene, resulting in the

erosion of several thousand meters of the synrift sequence

(Satyana et al., 1999). This in turn led to a major deltaic

progradation over the continent margin to the east (to

form the Mahakam Delta sequence). Continental collisions

in the area are thought to have been responsible for

younger inversions affecting the early Miocene sequence.

Within the shelf Mahakam Delta sequence, the dominant

trap-forming mechanism comprises syn-sedimentary

growth faulting. The slope to basin floor section is chara-

cterized by toe-thrust structures.


In this basin, a number of petroleum systems can be

recognized, each with associated sub-systems:

1. In the onshore Kutei Basin, largely comprising inverted

synrift sequences where as yet few hydrocarbons have

been located, Howes and Tisnawijaya (1995) suggestedthat an early synrift to early postrift petroleum system,

the Tanjung – Berai (.) PS may be developed. However, it

remains speculative.

2. The onshore to offshore Mahakam Delta, which

includes the majority of prospective sequences, belongs

to a thick, late postrift continental margin stage of

development. In this rich oil and gas province, almost all

of the hydrocarbons are sourced from and trapped in

reservoirs of the late postrift stage. Accordingly, the

deltaic Balikpapan – Balikpapan (!) PS is overwhelmingly

the dominant one in this area. Reservoir sands,

belonging to a series of stacked regressive deltaic

progradational sequences range in age from Middle

Miocene to Pleistocene (Balikpapan to Kampung Baru

formations), and most accumulations occur at several

levels, separated by intraformational sealing shales

representing maximum flooding surfaces. As in other

Tertiary deltas, a range of trap types is represented,

including:

(a) Hangingwall anticlinal rollovers associated with

growth faults, many cut by synthetic and antithetic

faults to form ‘‘collapsed crest’’ structures. Trap-

ping of individual stacked accumulations is partly-

fault dependant (i.e. in footwall or hanging wall

blocks). The structures are frequently dome-shapedor oval in shape and occur mainly in nearshore and

shallow offshore areas.

(b) Elongated inverted anticlinal deltaic rollover struc-

tures with a NNE–SSW trend, related to thrusts and

reverse faults, often on both flanks. These occur

primarily in the onshore part of the delta and

contain many of the larger fields. Characteristic of

many fields are cross faults that divide the

accumulations into separate units. McClay et al.

(2000) demonstrated that many of these structures

originate from inversion of growth-faulted struc-

tures above a ductile substrate.

(c) Stratigraphic traps related to deltaic sand bodies

encased in shales. In many cases stratigraphic

changes contribute to trapping only, for instance

where deltaic channels are draped over anticlinal

trends, but in a few cases sand pinch-out appears to

define the trap (e.g. in the Bongkaran and Tambora

fields), while a hydrodynamic effect can sometimes

be identified.

Duval et al. (1998) summarized some of the most

important parameters that impact hydrocarbon pro-

spectivity. They indicated that the main charge for fields

in the Tambora and Tunu trends is derived from thick

ARTICLE IN PRESS



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deltaic coals and coaly shales in the intervening syncline,

with minor contributions from a marine and leaner

source rock in the offshore trend between the Tunu and

Sisi fields. They noted that efficient short migration

paths up to 15 km in length lead from these charge

kitchens into adjacent structures. They noted a gradual

transition from oil, in more proximal anticlinal fields(Tambora, Handil) to gas/condensate rich fields in more

distal trends, where source rocks are leaner, and thicker

shale packages restrict migration of heavier hydrocar-

bons. These observations relate to the shallow progra-

dational deltaic sequences.A number of anticlinal

structures contain oil and gas fields in early Miocene

regressive sands, for instance in the Wailawi field. These

deltaic sands, with interbedded shales and coals (Klinjau

Formation) were deposited during the period of maxi-

mum transgression when carbonate facies were exten-

sively developed in the Kutei/Makakam area. They

provide evidence for the local strength of the deltaic

system and suggest that an early postrift petroleum

system exists in places. This can be referred to as the

Klinjau – Klinjau (.) PS.

3. Recently, the focus of exploration has moved into the

deeper water portions of the delta, where fields are being

discovered in turbidite reservoirs deposited in slope

channel and basin floor systems. The discoveries belong

to a new petroleum system called the Miocene – Mio/

Pliocene (.) PS. Reservoir quality sands have been found

widely distributed in the Middle Miocene to Pliocene

section. The oil and gas accumulations are thought to

have received charge from organic matter of land plant

origin, transported into deep water settings by turbidityflows (Dunham et al., 2001; Lin et al., 2000). Peters et al.

(2000) distinguished two maturity-related families of oil

derived from deep water systems, both less waxy than

the onshore oils.

Compressional anticlines and toe thrusts form the

primary structural traps in the Mahakam deepwater

system. Reservoir sands occur in confined amalgamated

channel–levee complexes (e.g. Merah Besar and West

Seno discoveries), and as unconfined sheet-like sub-

marine fans (Dunham and McKee, 2001). Due to the

nature of the sand bodies, opportunities clearly exist for

stratigraphic trapping. There is still much to be learned

about the geometry and productivity of these sand

bodies as additional discoveries are made and appraised.

The West Seno field, discovered by Unocal in the late

1990s, is Indonesia’s first deepwater development, the

first barrel of oil being produced in mid-2003.

The Kutei–Mahakam Delta province is one of the richest

in Indonesia, with discoveries totalling more than 3.5

billion barrels of oil and 35tcf of gas. It supports an

important and expanding LNG project. The creaming

curve for oil suggests that, unless significant new reserves

are identified in the deep water, only small incremental

accumulations can be expected in the future. The gas curve,

on the other hand, which is characterized by a series of

steps reflecting major discoveries, shows little evidence for

creaming. Such a ‘‘relatively efficient’’ creaming curve is

typical for deltaic areas in which there is a gradual seaward

shift in exploration as new technologies become available.

5.10. Tarakan Basin

The Tarakan Basin has a similar development to the

Kutei–Mahakam Basin (Lentini and Darman, 1996), which

it resembles in many ways (Fig. 13). It comprises four sub-

basins, two onshore (the Tidung and Berau synrift basins—

mainly Late Eocene to Middle Miocene), and two offshore

(the Belungan–Tarakan and Muara postrift basins with

mainly younger fill). As in the Kutei–Mahakam Basin,

hydrocarbons have been located in the late postrift stage

only.

Early Synrift (Middle Eocene): This sequence is domi-nated by volcanics and volcaniclastics of the Sembakang

Formation. It is highly tectonized.

ARTICLE IN PRESS

Fig. 13. Tarakan Basin—simplified location and structure map showing

inferred areas of active hydrocarbon generation and Late Postrift oil/gas

field trends.



20/27

Late Synrift (Late Eocene): This comprises fluvio-deltaic

to shallow marine shales, marking a rapid transgressive

phase.

Early Postrift (Oligocene to Early Miocene): This period

is dominated by open marine carbonate platform

development on shallow blocks, with deeper marine

environments represented by shales and marls in theintervening depressions. Local late Oligocene uplift can

be linked to a minor clastic progradation from the west.

Late Postrift (Middle Miocene to Quaternary): This

forms the main hydrocarbon-bearing sequence and is

composed of a number of regressive progradations of

interbedded fluvio-deltaic sands, shales and coals.

NE–SW trending growth faults intersect with four

NW–SE trending fold trends. To the south and north

of the deltaic depocenters, carbonates continued to

accumulate.

Eocene rifting was followed by a generally quiescentbasin history, interrupted by a phase of uplift in the

onshore area in the Late Oligocene. Traps were formed in

the Pliocene and Pleistocene and rely on a combination of

growth faults and discrete NW–SE trending compressional

folds and faults produced during a series of uplift and

inversion events.


All hydrocarbons in the Tarakan basin are derived from

and trapped in late postrift stage sediments. Source rocks

are Middle to Late Miocene coals and coaly shales of the

Tabul Formation, while fluvio-deltaic sands belonging to

the Late Miocene Tabul and Plio-Pleistocene Tarakan

formations form the main reservoirs. A variety of trap

types are present, concentrated at points where growth

faults culminate above the NW–SE trending anticlinal

arches. Several hangingwall dip closures, assisted or not by

fault closure are represented, as well as local pure footwall

closures. All accumulations belong to the Tabul – Tarakan

(!) PS. The deepwater area remains largely unexplored to

date with only a few wells having been drilled, so far

without commercial success.

The creaming curve for this basin is dominated by the

discovery of the Bunyu field in 1922. Since then only minor

quantities of mainly gas have been added.

5.11. Eastern Indonesia: Bula (Seram), Salawati, Bintuni

and East Sulawesi Basins

Eastern Indonesian Basins (Indonesian Petroleum Asso-

ciation, 1998) differ from those of western Indonesia

(Fig. 14). They include significantly older sedimentary

sequences derived from slices of the Australian continental

margin that were incorporated in the eastern Indonesian

collision zone during the Middle and Late Tertiary

(Hutchinson, 1996). Thus, although Tertiary depositional

environment and lithofacies developments are recognizable,

the Tertiary synrift to postrift basin development cannot be

readily applied to the petroleum habitat.

The Bula Basin in Seram overlies and is partly

incorporated in a fold/thrust and zone formed where the

outer margin of Australian continental shelf collided

with Irian Jaya in the mid-Tertairy (Hutchinson, 1996).

The bulk of the sequ

petroleum systems of indonesia-libre 2

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