Petroleum systems of Indonesia · Marine and Petroleum Geology 25 (2008) 103–129 Petroleum systems of Indonesia Harry Dousta,, Ron A. Nobleb,1 aVrije Universiteit Amsterdam, The

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Marine and Petroleum Geology 25 (2008) 103–129

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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 and

petroleum 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 andsuccessful history. Some of the earliest oil production ofthe modern age comes from shallow fields in Java andSumatra, and discoveries have been made throughout thepast century up to the present day. Knowledge of thepetroleum habitat has been encouraged since the 1970s,partly thanks to an enlightened policy of cooperation bythe petroleum community in Indonesia, through technicalconferences and through publications sponsored by theIndonesian Petroleum Association (IPA). This cooperationamongst industry participants has grown from the need todevelop a comprehensive understanding of the large

e front matter r 2007 Elsevier Ltd. All rights reserved.

arpetgeo.2007.05.007

ing author.

ess: [email protected] (H. Doust).

ess: Anadarko Indonesia Company, Jakarta, Indonesia.

number of sedimentary basins and petroleum provincesencountered throughout the archipelago.Description of the petroleum systems of Indonesia can

thus rest upon a foundation of an extensive, comprehensiveand reliable database that can be found, for the most part, inthe public domain. Many of the publications are detailed,but several overviews have been published through theyears, concentrating particularly on the various charge andreservoir systems as well as on the common play typesrepresented in the different basins. In this paper, we makereference only to a restricted number of ‘‘key’’ publicationsthat provide good summaries of the various themes or areas.They all provide access to a much larger literature, which wehave used to prepare both text and figures.In an early and excellent publication, Soeparjardi et al.

(1975) identified important characteristics of the basinswhich were known to contain hydrocarbon accumulations:namely, Eocene to Miocene transgression, followed by

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

mid-Miocene to Pliocene regression and Quaternarytransgression. They also described the six main reservoirsystems that were known in productive basins-transgressiveclastics, regressive clastics, deltaic deposits, carbonateplatform complexes, pinnacle reefs and fractured volcanics.Their publication formed the basis for all subsequentattempts to review the hydrocarbon habitat of Indonesianbasins, and provides the foundation of the approachpresented here.

Following the formalization of the petroleum systemconcept (Magoon and Dow, 1994), Howes and Tisnawijaya(1995) used a modified and more practical approach tosummarize the petroleum systems of Indonesia in alandmark paper. They tabulated 34 petroleum systemsassociated with documented accumulations as well asothers that were thought to exist but in which nodiscoveries had yet been made. For the known systems,they presented plots of cumulative ultimate discoveryvolumes (in million barrels of oil equivalent) versus numberof fields in discovery order (so-called creaming curves).

Fig. 1. Location map of Indonesian basins, grouped according to resource vo

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

We refer to many of these plots in this publication.Importantly, they noted that many of the 34 systems didnot contain a single area of mature source rock, butrepresented in fact a composite of several distinct sourceareas. In order to work with manageable numbers ofsystems, 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 ofpetroleum systems in southeast (SE) Asia, and this isapplied in the classification presented here.There are many petroleum-bearing sedimentary basins in

Indonesia (Darman and Hasan Sidi, 2000), the numberdepending on whether each individual synrift graben iscounted, or whether they are grouped by province. Wehave followed the classification used by the IPA for theirset of field atlases (Indonesian Petroleum Association,1997–1991), which also represents common usage. Descrip-tion of the geology and hydrocarbon habitat of thesebasins is complicated by the plethora of local formation

lumes. Those with less than 10MMboe do not contain petroleum systems

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

names (many of them essentially lithofacies and lithofaciesequivalents) and conflicting age attribution. We haveadopted the stratigraphies from the atlases in general,though we have modified them where we felt this wasjustified. We have reviewed in detail the petroleum systemswith commercial, or soon to be commercial, fields only.Throughout Indonesia other potential systems are devel-oped (indicated, for instance, by oil seepages in frontierbasins), but our main object here is to identify and emphasizethe main characteristics of the successful and productiveones, 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 afamily of Tertiary basins developed throughout SE Asia(Fig. 1). Though they may differ slightly in age anddevelopment, they share many characteristics: nearly all ofthem pass through an early Tertiary synrift to late Tertiarypostrift geological history, they all have an almostexclusively land–plant and/or lacustrine–algal chargesystem and they are characterized by rapid short wave-length sedimentary variations involving a distinct suite ofdepositional environments and their associated lithofacies.

Fig. 2. Chronostratigraphy of Indonesian petroliferous basins, showing stages

and continental collisions are from Longley (1997).

In nearly all of the basins, four stages of tectonostrati-graphic evolution can be recognized (Fig. 2):

1.

, ba

Early Synrift (typically Eocene to Oligocene)—corre-sponds with the period of rift graben formation and thefollowing 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 inthe graben, when individual rift elements amalgamatedto form extensive lowlands that filled with paralicsediments.
3.
Early Postrift (typically Early to Middle Miocene)—corresponds with a period of tectonic quiescencefollowing marine transgression that covered the existinggraben–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 willnot be referred to further.These stages can be related to the area’s plate tectonic

evolution (Hall, 1997), particularly to early Tertiary

ckground tectonics and geodynamic events. Seafloor spreading events


transtensional stresses generated by the India–Asia colli-sion (including opening of the South China Sea (30–20Ma)and with late Tertiary uplift and inversions caused bycollisions and plate rotations. They can also be correlatedwith the four phases or stages of SE Asian tectonostrati-graphic evolution as defined by Longley (1997). His Stage I

(50–43.5Ma) corresponds to a period of early continentalcollision, which led to the formation of many of the oldersynrift grabens, while his Stage II (43.5–32Ma), duringwhich major plate reorganizations took place, resulted inthe formation and active subsidence of a younger popula-tion of rifts. Stage III (32–21Ma), contemporaneous withsea floor spreading in the South China Sea, was a periodduring which rifting ceased, local inversion took placeand a major marine transgression marked the beginningof postrift development. Stage IV (21–0Ma) was chara-cterized by a maximum transgression, followed by severalcollision phases that led to inversions, uplift and thedevelopment 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 mostsedimentary basins have complex histories that can bedivided into stages or cycles (mentioned above). Kingstonet al. (1983) described a method by which various basintypes could be categorized by their sequence of evolu-tionary stages. SE Asia Tertiary basins were classified astwo-stage wrench or shear basins, in recognition of theirearly synrift phase with probable transtensional origin,followed by almost inevitable inversions related to theinherent instability (reflected in the poor preservationpotential of this basin type). They also noted that eachbasin stage typically comprised a transgressive–regressivesedimentary cycle, which today we can recognize as afirst order sequence, containing lowstand, transgressiveand highstand systems tracts, bounded by regionally cor-relatable horizons.

It is our belief that in many basins, petroleum systemscan be related directly to basin stage, since first-ordersedimentary sequences often contain source, reservoir andseal rocks, frequently in a favourable vertical succession.We have applied this concept to Indonesian petroleumsystems, albeit with some modifications in recognition ofthe synrift development (which does not lend itself easily tothe classic model of sequence stratigraphy) and the rapidfacies variations.

Doust and Lijmbach (1997) and Doust (1999) proposedthat almost all of the petroleum systems developed inIndonesian basins could be ascribed to one of four basictypes, each with its characteristic source, reservoir and sealfacies. By classifying them in this way, it is possible to makebroad comparisons of basin prospectivity. Recognition ofdiscrete petroleum systems depends on geochemical corre-lation between source rocks and their related hydrocarbon

accumulations. In Indonesia, this is rendered very difficultby the fact that: (a) many source rocks are thin and/orwidely distributed within the sequence, (b) most oils andgases derived from any particular type of source rock (e.g.deltaic or lacustrine) cannot be readily distinguished fromothers in the same group, and (c) a large amount of mixingof lacustrine and terrestrial oils appears to have takenplace. Ten Haven and Schiefelbein (1995) nevertheless wereable to define whether charge in each basin in Indonesiawas derived from Tertiary lacustrine, terrigenous or marinesource rocks or whether it came from Mesozoic sources: Infact, they used this to define which petroleum systems werepresent, in much the same way as presented here—although we relate the petroleum systems more specificallyto the basin development stage.The extensive mixing is probably a consequence of the

limited development of regional seals, and its effect is thatcharge from some of the petroleum system types definedhere contributes to accumulations in younger petroleumsystem types.The four basic petroleum system types (or PSTs; for more

detail see Doust and Lijmbach (1997), where they arereferred to as hydrocarbon systems) correlate well with thefour basin stages described in the previous section, and havethe following characteristics (for a summary see Fig. 15):

1.
Early Synrift Lacustrine PST: This is strongly oil pronedue to the widespread development of organic-richlacustrine type I/II source rocks, and is common inwestern 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 orparalic sequences with an overall backstepping devel-opment typify this PST. Source rocks comprise typeII/III coals and coaly shales that produce both oil andgas, interbedded with fluvio-deltaic sand reservoirs andseals, often of excellent quality.
3.
Early Postrift Marine PST: Source rocks in this principallymarine shale sequence are mainly lean and/or gas-prone.The main reservoirs comprise open marine carbonates,including reefal buildups. This PST contains the onlywidespread regional seal in many Indonesian basins.
4.
Late Postrift Regressive Deltaic PST: This PST hassimilar environments and characteristics as the Latesynrift PST except that the overall deltaic developmentis typically progradational rather than retrogradational.In most cases, it lies at depths too shallow forhydrocarbon generation, but where major deltas aredeveloped on continent margins, it represents thedominant system.
4. Aspects of the hydrocarbon system

In this section, we summarize the characteristics of themain elements common to Indonesian petroleum systems.


This is possible because the basins share a relatively limitednumber of environmentally related lithofacies and havesimilar tectonic settings. The basins situated proximal tothe Sunda shelf have a stronger component of proximallacustrine–deltaic lithofacies throughout their develop-ment, while those at the edges of the Tertiary continentalmargin develop more marine facies characterized by thickmarine shales and carbonates. This is reflected directly intheir hydrocarbon habitat, so that the petroleum systemsand plays developed in the various basins can be linkeddirectly to the overall three-dimensional facies/environ-mental sequence and the tectonic history.

4.1. Source rocks

The geochemistry of oils and source rocks fromIndonesia has been reviewed by many authors, and thereis general consensus that the host organic matter originatedfrom land–plants and/or algal–lacustrine source material.A summary of information on source types in the majorpetroleum provinces of Indonesia is presented in Fig. 3.The source rock depositional environments, described in

Fig. 3. Source rock types in Indonesian basins based on oil typing from Todd

developed and total associated reserve volumes in million barrels of oil-equi

Postrift; HC, hydrocarbons.

detail by Todd et al. (1997) and by Schiefelbein andCameron (1997), are as follows:

Lacustrine: Lacustrine oils originate from mainly algaltype I/II kerogen, which accumulated in deep or shallowfresh to brackish water lakes, primarily in the early synriftstage of basin development. Several sub-families have beenrecognized (e.g. in Central Sumatra, Williams and Eubank,1995) which are linked to variable water chemistry and theadmixture of terrestrial organic detritus.

Paralic or deltaic: Hydrocarbons from source rocks ofthis type arise from coals and coaly shales deposited in avariety of fluvial to estuarine lower coastal plain environ-ments, typically in the late synrift and late postrift basinstages. The kerogen is mainly of terrigenous (land plant)origin, type II/III, but may contain some algal elementsderived from floodplain lakes. In general, a mixture of oiland gas is generated.

Marine: Hydrocarbons generated from marine sourcerocks have geochemical characteristics that are broadlysimilar to those from the paralic environments in thatthey are derived from detrital land plant organic matter.The typical type II marine source rocks seen extensively in

et al. (1997), showing lithology, age, and the basin stage in which they are

valent. ES, Early Synrift; LS, Late Synrift; EP, Early Postrift; LP, Late


other parts of the world are not present in any abundancehere. 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 marinesetting, even though the bulk of the organic materialrepresents transported land plant material. In the Maha-kam Delta, source rock facies have been identified recentlyin deep water turbidites where once again, the organicmatter is predominantly of terrestrial origin (Dunhamet al., 2001; Peters et al., 2000; Guritno et al., 2003; Salleret al., 2006). Away from deltaic depocenters it is likely thatmarine shales of the early postrift interval, many of whichcontain low percentages of disseminated terrestrial organicmaterial, have generated significant quantities of gas. Ineastern Indonesia, oils of marine clastic, marly andcarbonate affinities occur. These oils have geochemicalcharacteristics 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 higherthan average heat flow experienced in several TertiaryIndonesian basins plays an important role in raising thehydrocarbon prospectivity of some of the shallower basins.

It is noticeable that many oils show a mixed lacustrineand paralic geochemical signature (e.g. in South Sumatra).These may arise from shallow lake margin facies or frommixing of charge from two distinct source rocks duringvertical migration. This mixing, plus the overall similarityof geochemical fingerprints, complicates the identificationof a discrete source system for groups of geochemicallyrelated oils, as proposed in the original definition of apetroleum system (Magoon and Dow, 1994).

4.2. Reservoirs

Reservoir rocks are abundant throughout Indonesianbasins in a variety of sedimentary facies. As with sourcerocks, their development is closely related to depositionalenvironment and basin evolution.

Non-marine siliciclastics: These characterize the earlysynrift section of proximal basins. They typically comprisefluvio-deltaic sands that are often thin, with a significantcontent of lithic material and limited sorting. Porosities arebelow 20% and permeabilities up to 100mD and, ingeneral, the quality and development are highly variable.Alluvial fans adjacent to basin bounding faults maycontain coarse clastics, but are poorly sorted and shale-out rapidly.

Fluvio-deltaic to shallow marine siliciclastics: These faciesform the best clastic reservoirs of Indonesia, with porositiesup to 25% and often multi-Darcy permeabilities. Deltaplain and coastal sands, derived from older cratonic areas,provide the best reservoirs. These typically occur within thelate synrift package. Late postrift sands of Sumatra andJava often have a significant lithic/arkosic component thatreduces the permeability. The cyclic regressive units of the

late postrift deltaic sediments in Kalimantan, on the otherhand, have excellent reservoir properties.

Deep marine siliciclastics: Turbiditic sands have provideda focus for exploration in recent years, primarily in theoffshore Kutei–Mahakam Delta (Dunham and McKee,2001). Drilling activity in the deepwater Makassar Straitshas shown that reservoir quality sands were deposited inslope and basin floor settings (Dunham and McKee, 2001).Sands deposited in channel–levee complexes across theslope and in unconfined submarine fans have successfullybeen targeted using 3D seismic. Study of the link betweenthe slope and the basin floor provides insights into sanddistribution and the location of potential reservoirs (Salleret al., 2004).

Platform and reefal carbonates: These reservoirs, char-acteristic of the more distal late synrift areas and postriftstages, provide locally high porosity reservoirs (o38% inplaces). In general, the reefoid and back-reef facies have thebest reservoir characters, while platform carbonates havemore limited potential.

4.3. Seals

Seals can also be closely related to basin stage and areeither intra-formational or more regionally developed.

Interbedded deltaic seals: Intra-formational shale sealsare typical of deltaic sequences, where they commonly actas top seals for interbedded sands or, in combination withfaults, as side seals to fault closures (often contributing claysmear). Those of the late synrift were described in Kaldiand Atkinson (1997), who reviewed shale interbeds fromthe Talang Akar Formation of Northwest Java in terms ofseal capacity, geometry and integrity. The main sealinglithofacies, ranked in order of increasing seal capacity,comprise delta plain, channel, prodelta and delta frontshales. These conclusions are probably equally applicableto the deltaic sequences of the late postrift.

Thicker seal formations and regional seals: The marineshales of the early postrift represent the only genuineregional seals of the Indonesian basins. They may act asultimate seals to the late synrift deltaic sediments or theymay completely encase the carbonate build-ups of the earlypostrift.

4.4. Traps

A variety of trap types are present in Indonesian basins,depending on the location and tectonic history. Thegreatest concentration of traps is to be found in the basinsadjacent to the Sumatra–Java arc, where extensive thrustbelts are developed, and in the continent margin sequencesof eastern Kalimantan. Elsewhere, traps are located aboverift boundary faults that have been reactivated duringinversion and in the extensive reefoid carbonate provincesin distal parts of the foreland basins. The following traptypes are commonly developed—they often define the playsthat are present.


Folded dip closures: NW–SE to W–E trending anticlinaldip closures are abundant in Sumatra and Java basins(which developed into foreland basins in the late postriftstage), where they may affect the entire syn- andpostrift sequences. They form elongate drag folds, arefrequently cross-faulted and are often bounded by reversefaults or thrusts nucleated above synrift boundary faults(the so-called ‘‘Sunda folds’’). Many of these structuresare related to wrench inversions of the synrift andare located adjacent to graben boundary faults. Atshallower levels, unfaulted drape closures may occur,especially where structural growth has been continuous,or where structural detachment has taken place in postriftshales.

Dip/fault closures: Many individual traps related toanticlinal structures demonstrate fault/dip closure. Foot-wall closures are especially common: they may be simple orcomplex, and are sometimes related to intrabasinal horstblocks or structural noses.

Fig. 4. Stratigraphic sections of southern and western Indonesian basins, sho

depositional environments (thicknesses are not indicated).

Synsedimentary structures: In the Kutei and Tarakanbasins growth-fault related structures, many of theminverted by subsequent movements, are developed. Traps,usually in the hangingwall block, may be dip closed or faultrelated. In the deeper water, toe-thrust anticlinal structuresfall into this category.

Basement topography: A relatively small number of fieldsare found in basement high blocks, where the reservoir isfrequently represented by fractured rocks the pre-riftsequence. In other cases, onlap onto the basement surfaceappears to define the trap morphology.

Reefoid carbonate structures: Carbonate reservoirs occurin anticlines, but trapping is often assisted by platformgrowth or reefoid relief. In most cases, these are ofrelatively low relief, but in the East Natuna and Salawatibasins, high relief pinnacle reefs are developed.

Clastic stratigraphic traps: Sedimentary pinch-out oftenappears to contribute to trapping, but rarely is the mainconstituent of a trap. Exceptions are where channels cut

wing basin stage, common formation names, lithology and predominant


structural noses in the deltaic sequences of the late syn-and postrift section. Deep water plays of the MahakamDelta may also have a component of stratigraphictrapping, particularly in ponded mini-basins in intra-slopeenvironments.

5. Summary of Indonesian petroleum basin geology

In this section, we summarize the stratigraphic andstructural development of the various productive basins ofIndonesia, and relate them to the petroleum systemframework presented above (Figs. 4 and 5). It should benoted that many of these are composite basins, comprisinga number of separate synrift grabens overlain by a blanketof postrift deposits. In many cases, the facies varyconsiderably across the various provinces, depending onthe proximity to or distance from the contemporary openocean (in the synrift) and to zones of active deformation(in the postrift).

Note that in ascribing reservoir levels to petroleumsystem types and basin stages, we have included PST 3basal carbonates within PST 2 in those areas where,because there is no regional seal between them, theyessentially form one combined group of reservoirs.Examples of this include areas where the Batu RajaFormation directly overlies the Talang Akar Formationin the South Sumatra Basin. Unless stated, we havefollowed the petroleum systems classification as definedby 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 EarlyOligocene time (Fig. 6). Almost the entire basin fill ismarine, much of it, especially in the north, comprisingbasinal deeper marine claystones, shales and shallow waterreefoid limestones, the latter developed on structural highs.Regressive shallow water deltaic facies are found in thesoutheast. The sequence is predominantly argillaceous andthe division into four-basin stages is somewhat arbitrary.

�
Early Synrift (Early Oligocene): Coarse-grained con-glomerates and bioclastic limestones are recorded at thebases of the graben fills and on their adjacent highs. � Late Synrift (Late Oligocene): This comprises thick,
deep marine claystones, mudstones and dark shales ofthe Bampo Formation. These represent the main sourcerock for the gas in the northern part of the basin:although lean (�1% TOC, type III), they are very thickand 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, withextensive reefoid carbonate buildups developed onstructural highs. The latter form excellent reservoirs,with porosities averaging 16% in the Arun field. Deep

water sandy facies (Belumai Fm) are present in thesouth.
� Late Postrift (Middle Miocene to Pliocene): This
regressive sequence comprises the argillaceous BaongFm (in which turbidite sands occur) and the overlyingparalic shales, silts and sands of the Keutapang andSeurula formations. In the north, deeper marine faciescontinued, while towards the southeast, these forma-tions became shallower with the deposition of regressivedeltaic sands of moderate to good reservoir quality.

Tectonic development in the basin is subdued. Followingthe Palaeogene rift formation, a Late Oligocene localunconformity and a Mid Miocene regional unconformityare recorded, while the deltaic sequence in the southeastwas folded during successive wrench phases in the MiddleMiocene 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 fromthe deep marine Bampo Formation, with a possiblesecondary contribution from the Miocene Peutu Forma-tion. The main reservoir/traps are carbonate build-ups ofthe Peutu (or Arun) Formation, with minor contributionfrom the equivalent sandy Belumai Formation and base-ment. Fifteen trillion cubic feet (tcf) of gas and 1 billionbarrels (bbl) of condensate, respectively, have been locatedin 10 fields, dominated by the Arun field with almost 14 tcfof 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 theshallow fields that produced the first reserves in Indonesia.Charge is thought to be derived from marine/deltaic coalysource rocks of the Baong Formation, but re-migrationfrom deeper reservoirs may also contribute. Reservoirsoccur in the rather ill-sorted sandy deltaic facies of the latepostrift Keutapang and Seurula formations, representingcyclic regressive phases. About 75% of the fields produceor produced both oil and gas, and all hydrocarbons arecharacterized by API gravities of over 40. Traps are mainlydip closures related to NW–SE trending folds, and mostare faulted to some extent (only a few are clearly related tothrusts). Stratigraphic pinch-outs appear to contribute totrapping 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 southof the basin (e.g. Wampu) may belong.Creaming curves for oil/condensate and gas (Howes and

Tisnawijaya, 1995) demonstrate that North Sumatra is ahighly mature province that has been explored withmoderate efficiency.

ARTICLE IN PRESS

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).

H. Doust, R.A. Noble / Marine and Petroleum Geology 25 (2008) 103–129 111

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).

H. Doust, R.A. Noble / Marine and Petroleum Geology 25 (2008) 103–129112

5.2. Central Sumatra Basin

The Central Sumatra Basin comprises a number ofseparate synrift grabens below a postrift sequence (Williamsand Eubank, 1995). Most of the many hydrocarbonaccumulations present lie directly above or adjacentto the synrift grabens, a consequence of the relativelyshallow 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 formedalong pre-Tertiary structural trends (north–south andWNW–ESE) and originated as half-grabens in an obliqueextension stress regime. The four-stage basin history can berecognized, as follows:

�
Early Synrift (Late Eocene to Oligocene): Pematang andKelesa formations. These consist of an association ofalluvial, shallow to deep lacustrine and fluvio-deltaicfacies represented by laminated shales, silts and sandswith coals and conglomeratic intervals. Deep lakeorganic rich shales containing algal/amorphous material
with thin sands (Brown Shale Formation), and shallowlake light grey shales with humic coals ensure thatcharge from the early synrift is mixed lacustrine andterrestrial, mainly type I/II, within which four oilfamilies have been distinguished (Katz, 1995). The bestreservoirs are found in fluvio-deltaic sands, whereporosities and permeabilities may be up to 17% and100mD, respectively.
� Late Synrift–Early Postrift (Late Oligocene to Early
Miocene): This sequence, equivalent to much of theSihapas Group, includes several paralic facies thatrecord a gradual transgression: The Menggala Forma-tion is still fluvial, but is overlain by shallow marinesandy (Bekasap Formation) and argillaceous (BangkoFormation) facies, the latter forming a regional seal.The Menggala and Bekasap formations contain the bestreservoirs of the basin, with porosities of the order of25% and permeabilities of up to four Darcies.


�
Early Postrift (Early to Middle Miocene): This includesthe distal marine facies of the Sihapas Group, whichrecords the final stages of transgression (Duri Forma-tion delta front sands and shales) followed by the periodof maximum Tertiary flooding (Telisa Formation shalesand silts). � Late Postrift (Middle Miocene to Quaternary): This stage
represents the Late Tertiary sedimentary fill of the basin,and includes regressive deltaic and alluvial sedimentsinterrupted by several unconformities. Only the deepestpart of this sequence (Petani Formation with marineshales, sands and coals) has significance for petroleumaccumulation.

Three phases of geodynamic development are recognized:

�
An Eocene–Oligocene extensional phase with foursub phases as indicated here (Williams and Eubank,1995), leading to formation of the synrift grabens andearly deformation of the sedimentary fill (Shaw et al.,1997). The first three sub-phases correspond to theearly synrift period, while phase 4 belongs to the latesynrift.1. Early Eocene: N–S and NW–SE shearing and
formation of isolated rifts and half grabens, withthe 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 gentle
folding accompanied by wrench faulting along aNW–SE (Barisan) trend. This period follows the earlypostrift. It was responsible for the formation of most ofthe structural traps, such as the forced drapes over thebasin margin faults.
� Movement continued up to the Plio-Pleistocene in the
form of NW–SE dextral wrench faulting, correspondingto the final stage of postrift development.


In the Central Sumatra Basin almost all of thehydrocarbons appear to have been derived from lacustrineto terrestrial source rocks of the early synrift stage, possiblywith some contribution from coals of the late synrift. Fourfamilies of oils are recognized (Williams and Eubank,1995), essentially related to variations in the synrift sourcefacies (Fig. 7). Potential source beds in the postrift areimmature.

Reservoir levels occur throughout the sequence,although the bulk of the fields are found at multiple levelsbelow regional seals in the early postrift (Bangko andTelisa formations). We can thus recognize a single, thoughcomplex, petroleum system, called the Pematang–Sihapas

(!) system as defined by Howes and Tisnawijaya (1995) withthree subdivisions: Pematang–Pematang (approximately

20 accumulations), Pematang–Sihapas (approximately 90accumulations) and Pematang–Duri (approximately 23accumulations).The following trap types can be recognized in the IPA

Atlas (Indonesian Petroleum Association, 1991a, b) listingof just over 100 fields: (1) dip closures related to simplefolds and drape (59 accumulations), thrusts (44 accumula-tions) and wrench faults (7 accumulations), affecting bothsyn- and postrift sequences, (2) fault-dip, mainly footwallclosures (22 accumulations), and (3) basement topography(2 accumulations only). In 12 accumulations, stratigraphicpinch-outs appear to contribute to trapping. There appear,however, to be no fields in which the trapping is primarilystratigraphic.Williams and Eubank (1995) noted that most of the

oilfields are concentrated in drape structures over basementpalaeo-highs and along the eastern flanks of the halfgraben rifts updip of the basin centre source rocks, whileothers are developed in drag and inversion folds (‘‘Sundafolds’’) adjacent to the basin boundary faults. Repeatedphases of structural movement are evident from variationsin 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 arelocated in the Minas and Duri fields, respectively. TheMinas field is the largest in SE Asia. Noticeable is the lackof gas, illustrative of the dominance of the highly oil-pronelacustrine charge of Petroleum System 1 (Schiefelbeinand Cameron, 1997). The creaming curve (Howes andTisnawijaya, 1995) is indicative of efficient exploration anda very mature province.

5.3. South Sumatra Basin

The South Sumatra Basin also comprises a series ofsemi-connected NNW–SSE trending synrift basinswith a common postrift sequence (Bishop, 2000a). Twomain rift provinces are recognized, both of whichcontain hydrocarbon fields. The smaller and more prox-imal of the two is Jambi, whereas the larger and deeper issituated in the Palembang area. Most of the oil andgas fields are concentrated along thrust and fold trendsabove or close to the areas of active mature source rocks(Fig. 8).

�
Early Synrift (Eocene to Early Oligocene): Thiscomprises the continental Lahat and Lematang forma-tions. These are separated by an unconformity, indicat-ing that at least two phases of rift formation wereinvolved. Facies include alluvial, lacustrine and brack-ish-water sediments represented by tuffaceous sands,conglomerates and claystones. In places the sequencemay be over 1 km thick. The Lahat Formation containsboth source and reservoir rocks, both very variable incharacter 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

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.

H. Doust, R.A. Noble / Marine and Petroleum Geology 25 (2008) 103–129114

deltaic section belonging to the Talang Akar Formation,by far the most important reservoir in the basin andstrongly time transgressive. Sediments were derivedfrom the northeast and the facies deepen south-westwards from fluvial to basinal. Reservoirs includedelta plain to marine sands, silts and shales. Many of thesands are quartzose (derived from the Sunda shelf) andare of good quality with porosities of up to 25%. Coalsand coaly shales of the Talang Akar Formationrepresent important type II and III source rocks.
� Early Postrift (Early to Middle Miocene): During this
transgressive marine period, platform and build-upcarbonates of the Batu Raja Formation accumulatedabove the rift shoulders, while deeper marine shales(Gumai or Telisa Formation) were deposited above thesynrift grabens. Bathyal environments lay to the south-west, where the sequence is very thick (over 2 km). TheBatu Raja is in an important reservoir, with porosities of

up to 38% in reefoid facies. The Gumai Formationrepresents an excellent regional seal for the underlyingdeltaic 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 EnimFormations (also called the Lower to Middle Palem-bang) filled the basin, gradually covering larger areasas the environment became shallower, so that byQuaternary times widespread alluvial continental sedi-ments accumulated. The sands contain reservoirs withgood porosities of up to 25%.

Three main tectonic phases are recognized:

�
Paleocene to Early Miocene extension and grabenformation; � 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–ESEanticlinal trends.


The South Sumatra Basin is a large and complex area, inwhich multiple hydrocarbon source and reservoir systemsare present. Bishop (2000a), however, related all accumula-tions to the Lahat–Talang Akar (!) petroleum system, whilenoting that considerable mixing of oils derived from lacustrineand paralic sources is evident. Howes and Tisnawijaya (1995)also recognized only one PS, the Talang Akar (!).From our analysis, based on Indonesian Petroleum

Association (1990), we believe that four distinct areas canbe distinguished (Fig. 8). In the absence of more precisegeochemical typing, we cannot clearly ascribe each of theseto an individual petroleum system; however, the primaryreservoir level differs in each case and the accumulationsprobably have a mixed charge. We can therefore look uponthese as potentially suggestive for four separate petroleumsubsystems.

1.
Mainly developed in the Jambi and Merangan sub-basins, contains oil and gas accumulations in the latepostrift sequence. Assuming that charge is derived fromdeltaic source rocks, this petroleum system may bereferred 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. Thisfield could also be sourced from the early postrift sectionand, 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 developedin the late synrift Talang Akar and early postrift BatuRaja formations. This is the Lahat/Talang Akar–Talang

Akar (!) PS.


4.
In the Muara Enim area (close to the mountain front),contains a number of smaller oil fields. This representsthe same type of petroleum system as 1 (above),although the fact that almost all the fields produce oilonly suggests that they may be either charged from aseparate source area, or that maturity and retentiondefine a different oil and gas mix.
Traps in both the synrift and postrift sequences aredominantly anticlinal, associated with elongate inversiontrends, and many are reverse or thrust faulted, especiallywhere the WNW–ESE fold trends cross N–S—trending riftboundary fault trends. Several fields are fault dependant(largely footwall closures), while the relief of traps in theBatu Raja carbonates is often enhanced by reefoid faciesdevelopments up to 100m thick. Stratigraphic pinch-outon structural noses and basement onlap are responsible fortrapping in a small number of syn- to early postriftaccumulations.

The creaming curve for oil suggests that the basin ismature (Howes and Tisnawijaya, 1995), but there is littlesign of creaming in the gas discovery trend, and more gasdiscoveries could be expected.

5.4. The Natuna Sea

The Natuna Sea is divided into two distinct petroleumprovinces by a broad ridge, the Natuna Arch (Fig. 9). Thetwo have a common early history, but the western basincomplex remained more proximal than the eastern area inthe postrift period.

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.

Early Synrift (Late Eocene to Early Oligocene): Thesequence comprises fluvio-deltaic to fluvial and alluvialsands of the Lama Formation overlain by shallowlacustrine shales of the Benua Formation, which locallyform rich oil and gas source rocks. Above these liefluvio-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 andUpper 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. Inwestern Natuna, the former are non-marine with coals,while in eastern Natuna they are open marine. Condi-tions on structural highs were favourable for thelater development of platform and reefoid carbonates(Terumbu Formation).
� Late Postrift (Late Miocene to Quaternary): During this
period conditions remained shallow marine, partiallyrestricted, and claystones of the Muda Formation weredeposited. Minor developments of deltaic sands arerecorded 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 MiddleMiocene 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 theTertiary and there is little evidence for compressionalmovements. Local to regional unconformities are presentat the end of the early synrift and during the early postriftperiods.


In West Natuna many hydrocarbon fields are associatedwith Sunda-type inversion folds formed in the Mioceneadjacent to the main boundary faults of a number of therift basins. These dip-closed anticlinal structures aresometimes associated with thrusts and are often faulted.The charge is derived from synrift lacustrine shales and themain reservoirs comprise paralic to marine sands of theGabus Formation. Keras and Barat shales form efficientregional seals. Most of the fields are shallow (maximum


2 km), have high API gravities and produce both oil andgas. In comparison to other basins with similar stratigra-phy, there are a few fields. This is due to the fact that trapsare largely limited to complex wrench-reactivated bound-ary fault zones with NE–SW or NW–SE orientations.Along such fault trends, several small fault-dependantfields may be clustered. This petroleum system is known asthe Benua–Gabus (!) PS.

One large, as yet non-productive gas field, ‘‘D-Alpha’’ ispresent in a large carbonate buildup in eastern Natuna(May and Eyles, 1985). The gas contains a high percentageof CO2, suggesting that the charge is derived from deep-seated sources associated with crustal faults along thewestern margin of the South China Sea. Hydrocarboncharge for this PS may be derived partly from the pre-rift,but is more likely to be derived from the synrift and it isreferred to here as the Tertiary–Terumbu (.) PS.

The creaming curves for Natuna presented by Howesand Tisnawijaya (1995) show no signs of creaming.However, the number of fields is too small to providereliable statistics. The complex geology and continuoustectonics have led to significant issues related to the timingof migration versus trap formation. Re-migration may becommon, and this is probably reflected in the apparentlypoor finding efficiency.

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

5.5. Sunda and Asri basins

The geology of these two rich hydrocarbon basins showsmany similarities to one another, as described by Bushnelland Temansja (1986), Wight et al. (1997) and Sukanto et al.(1998). The location of major fields and structural elementsare shown in Fig. 10. The stratigraphic nomenclature issimilar to that of South Sumatra.

is developed.

�
Early Synrift (Early Oligocene): This is represented bythe Banuwati Formation, an excellent lacustrine deepwater type I source rock with TOC of up to 8% and ahydrogen index (HI) of up to 650mg/g. A basalmarginal alluvial sandy/conglomeratic facies, withoutsource potential, also occurs. � Late Synrift (Late Oligocene to Early Miocene): This
stage commences with fluvio-deltaic sediments of theTalang Akar Formation, and continues with Batu Rajacarbonates, as in South Sumatra. Both form excellentreservoirs. A coaly-shale potential source horizon is alsopresent, but although rich, is immature at this level.Intraformational shale seals are found in the upper partof the sequence (upper Gita member).
� Early Postrift (Middle Miocene): Transgressive marine
shales of the Air Benakat Formation form excellentseals for the underlying reservoirs.
� Late Postrift (Late Miocene to Quaternary): This
regressive sequence (Cisubuh Formation) culminates indeltaic sediments with coals, but lies too shallow tocontribute to hydrocarbon generation.

The tectonics of these isolated basins is highly subduedcompared to other Sumatran basins. The evolutionincludes pre- to Early Oligocene rift formation resultingin half grabens along en-echelon faults, followed by synriftsubsidence and a quiet postrift stage with limited wrenchreactivation.


The Banuwati–Talang Akar (!) PS. Howes and Tisnawi-jaya (1995) called this the Banuwati–Batu Raja PS. Itincludes all of the hydrocarbons trapped in the SundaBasin. Deltaic sands of the Talang Akar Formation as wellas 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 alongfaulted noses on the gentle basin flank. A total of about 950millionboe (barrels of oil-equivalent) has been discovered,of which 90% is oil. According to Bishop (2000b) 75% ofreserves are located in the Talang Akar Formation.


In the Asri Basin, the same elements of the petroleumsystem occur, but all accumulations are in Talang Akarsands as the Batu Raja reservoir is absent. Approximately500 millionboe has been discovered in nine fields, mainlyin faulted anticlines on the half-graben dip flank. Inthe Widuri Field, trapping is assisted by stratigraphicpinch-out (Carter, 2003).

Sukanto et al. (1998) proposed that oil-saturated sandsin the early synrift indicate that a second PS is present inthe Asri Basin. They referred to this as the Banuwati–Harriet (.) PS. However, there is as yet no commercialproduction from it.

The creaming curves of these two basins are different.Although the Sunda curve suggests relatively efficientexploration, the 1988 discovery of the Widuri fieldconfirmed the prospectivity of the Asri Basin at a verylate stage. Short and abundant migration paths from thebasin centres leading to accumulations in the bestreservoirs (Talang Akar and Batu Raja) on the basinflanks contribute to the efficiency of the system, as does thepresence of a widespread claystone seal.

5.6. Northwest Java

The Northwest Java Basin (Fig. 10) lies both on andoffshore and comprises two main half graben-defineddepocentres: the rich offshore Ardjuna Basin towards thewest and the onshore Jatibarang Basin in the southeast(Noble et al., 1997). The onshore and nearshore areascontain clastic wedges derived from the Java hinterland inthe postrift, while the more distal offshore areas remaineddominated by carbonates.

�
Early Synrift (Late Eocene to Early Oligocene): Thiscomprises tuffs and minor interbedded lacustrine shalesof the Jatibarang Formation. Volcaniclastics provide thereservoir facies for some onshore Java fields, whereasthe source rock appears to have a significant deltaiccomponent, indicative of major contributions from theoverlying Talang Akar Formation. � Late Synrift (Late Oligocene to Early Miocene): As in
South Sumatra, this sequence comprises a transgressivesequence of fluvio-deltaic, coastal and shallow marinesands, shales and coals (Talang Akar Formation),followed by platform and reefoid carbonates (BatuRaja 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 remainedin an open to distal marine carbonate environment longer.This makes it difficult to distinguish early from late postriftstages. While a number of regressive clastic deltaic phasesare recognized onshore and nearshore in the CibulakanFormation, much of the area is characterized by shelfmarine sands (‘‘Massive’’ and ‘‘Main’’) that are importantreservoirs 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 subsidenceand the onset of inversion movements linked to Pliocenefolding in the south.

The tectonic history of the area (Gresko et al., 1995) canbe traced back to the earliest Tertiary, when coolingfollowed metamorphism of the basement rocks. Riftingrelated to dextral wrenching followed in the Eocene(50–40Ma), while Middle to Late Miocene collision events(dated 17–5Ma) led to repeated local inversions along theonshore trend.


Howes and Tisnawijaya (1995) recognized two primarypetroleum systems in the area. The dominant one is theTalang Akar–Main/Massive (!) PS, and is characteristic ofthe offshore Arjuna Basin. Charge is derived from the latesynrift Talang Akar coals and coaly shales, while most ofthe accumulations are located in Cibulakan sandstones ofthe early postrift (‘‘Massive’’ and ‘‘Main’’). Althoughmultiple reservoirs are represented, only few fields arefound in early and late synrift or late postrift reservoirs.The second petroleum system proposed by Howes andTisnawijaya (1995) is represented by the early synriftJatibarang interval, located in the onshore, and whichincludes the Jatibarang Field, the only accumulation tohave been located in this highly faulted tuffaceousreservoir. However, a more detailed study of NorthwestJava by Noble et al. (1997) indicated that the Talang Akarsource system was overwhelmingly the major contributorof oil and gas in all of the sub-basins, including the onshoreregion. Seven primary depocenters were recognized which,based on geochemical data, showed strong oil-sourcecorrelations with Talang Akar coals and carbonaceousshales. Facies variations within the Talang Akar sourcerocks were noted, ranging from fluviodeltaic to marginalmarine. In contrast to other Sunda-style basins in theJava–Sumatra region, no evidence was found to supportmajor charge from the lacustrine synrift sequence.Of the traps described in the IPA Field Atlas volume IV

(Indonesian Petroleum Association, 1989a, b), at least halfare formed by anticlines, many of them highly faulted.Fault-dependant closures, mainly footwalls are alsocommon, while a few fields are trapped in reefoidcarbonate mounds. As in other basins, stratigraphictrapping plays a minor contributory role only.A separate petroleum system, referred to as the

Biogenic–Parigi (.) petroleum system, has been proposedto cover shallow biogenic gas accumulations in carbonatesof the late postrift. The charge for accumulations withinthis system comes from biogenic conversion of organicmatter at shallow depth, while reservoirs comprise north–south trending porous bioherms in the southern part of theNW Java offshore (e.g. APN field).The Arjuna Basin, as in many offshore provinces, shows

high exploration efficiency for oil and suggests that littleremains to be found. For gas, the curve suggests that as yet,


creaming has not been achieved. The Jatibarang sub-basincurve is typical of complex situations where one, probablystratigraphically assisted trap, dominates the basin.

5.7. Northeast Java

The East Java Basin area comprises a complex ofNE–SW trending troughs, separated by ridges and arches(Fig. 11). Several of these basins contain hydrocarbonaccumulations while several others represent, as yet,frontier provinces. As in West Java, there are significantdifferences between the clastic dominated onshore basins inthe southwest and the carbonate-dominated areas belowthe East Java Sea.

�

Fig

infe

acc

Early Synrift (Late Eocene to Early Oligocene): This isrepresented by the Ngimbang Formation, in which abasal lacustrine to paralic sequence with source rocks israpidly succeeded by open marine shales with sands andcarbonates.

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

rred areas of hydrocarbon generation and oil/gas fields classified

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

�
Late Synrift (Late Oligocene to Early Miocene): Thissedimentary unit is dominated by platform and reefoidcarbonates of the Kujung and Prupuh formations with,at the base, marine shales (with thin sands) indicatingthat this basin lay close to the continent margin at thistime. � Early Postrift (Early to Late Miocene): At the beginning
of this period, the carbonate platforms were drownedand extensive deeper marine clastics (Tuban andWoncolo Formation shales and Ngrayong Formationsands) were deposited. Locally, carbonates persisted andvolcaniclastics are present.
� Late Postrift (Late Miocene to Quaternary): Local
tectonics and widespread active volcanism dominatedthis period, so that a variety of sequences is developed,including marine clays, volcaniclastics, carbonates andsands, deposited in a variety of shallow to deeper waterenvironments.

The tectonic history passes through Eocene to EarlyOligocene rifting stages, during which a number of halfgrabens were formed, followed by a phase of quiescenceand, starting in the late Miocene (at 7Ma), localdeformation and active volcanism. The onshore fold beltis complex, and is thought to originate from obliquewrenching of basement and inversion involving unstableshale sequences (possibly including gravity-induced growthfaults). In the offshore area east of Madura, activewrenching along E–W trends has resulted in the formationof extensive and very young inversion structures (e.g. in theKangean 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 EastJava;
2.
Ngimbang–Ngimbang (!) PS in the Kangean areaoffshore area north of Bali;
3.
Ngimbang–Kujung (!) PS in the Cepu amd Madurabasins;
4.
Tertiary–Miocene (.) PS in the Muriah Basin—this islargely a biogenic gas system; and
5.
Tertiary–Pliocene (!) PS in the southeast Madura andnorth Bali areas, a biogenic gas system.
Fields in the IPA Field Atlas volume IV (IndonesianPetroleum Association, 1989b) comprise mainly older oilaccumulations from onshore east Java. By far, the majorityof these are located in sandstones and calcareous sand-stones of the early postrift Ngrayong, OK, Tuban andWoncolo formations, and with a few exceptions, they occurin shallow faulted and detached thrust anticlines of smalldimensions and now are shut-in or abandoned. A few fieldsoccur in reef limestone of the late synrift, while some others

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


are found in calcareous and volcanic sands of the latepostrift.

The three petroleum systems of greatest commercialsignificance at the present time are the Ngimbang–Kujung

(!), Ngimbang–Ngimbang (!) and Tertiary–Pliocene (!). TheNgimbang–Kujung PS is actively being pursued in theMadura and East Java basins, targeting the Kujung andCD carbonate reservoirs (Essam Sharaf et al., 2005).Further to the east, large offshore gas discoveries havebeen made in the late synrift section (e.g. Pagerungan,Kangean Barat). The origin of this gas is likely to be fromover mature Ngimbang fluvio-deltaic coaly source rocks,which have also sourced oil accumulations (e.g. JS53).Biogenic gas fields from the Tertiary–Pliocene system, suchas Terang–Sirasun (1.1 tcf) are also attracting industryinterest.

Exploration in East Java has a long history, dating fromthe late 19th century, when many of the small onshorefields were discovered. Following a long period withoutsuccess, the move offshore in the late 1970s has resulted ina significant rejuvenation of oil discoveries and spectacularsuccess in locating large gas fields. Onshore exploration hasalso been rekindled, with the Kujung play in the Cepu areabringing new life to an old basin. Recent discoveries in theCepu area rank amongst the largest made in Indonesia overthe 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 belate Oligocene in age. The bulk of the synrift sequencebelongs to cycles of the Tanjung Group.

in which they occur.

�
Early Synrift (Paleocene to Early Eocene): In at least fiverift basins, alluvial to lacustrine sediments, with goodsource rock potential accumulated. � Late Synrift (Middle to Late Eocene): During this
period, retroregressive fluvio-deltaic sediments withcoals, followed by marine shales with carbonates weredeposited.
� Early Postrift (Oligocene to Early Miocene): During this
period, stable marine conditions prevailed and shallowmarine carbonates of the Berai Formation coveredmuch of the area. A minor regressive phase is recordedin the Late Oligocene.
� Late Postrift (Middle Miocene to Quaternary): Uplifts
led to the development of regressive deltaic conditionsand the carbonates were drowned by regressive clasticsof the Warukin and Dahor formations.

Early Tertiary rifting along NW–SE trends followedLate Jurassic to Cretaceous emplacement of the Meratusophiolitic 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 LateTertiary, continuous compression and uplift of theMeratus mountains led to the sinistral reactivation of thegraben boundary faults (Satyana et al., 1999).


Tanjung–Tanjung (!) petroleum system: the few fields inthe basin produce oil (with API gravities of 30–401) and gasand are probably sourced from either highly matureTanjung Formation source rocks or a mixture of earlyand late synrift lacustrine and deltaic source rocks.In this complexly deformed basin, hydrocarbons aretrapped in prerift to postrift reservoir levels (basementand Eocene to Miocene sands) in thrusted and highlyfaulted anticlinal structures. At least half of the hydro-carbons are located in one field (Tanjung, discovered in1937) and the creaming curve (Howes and Tisnawijaya,1995) reflects this.


5.9. Kutei–Mahakam Delta Basin

The Kutei–Mahakam Delta Basin is the largest basin inIndonesia (165,000 km2) and one of its richest hydrocarbonprovinces with several giant fields (Fig. 12). It has acomplex history (Moss et al., 1997), and is one of the onlyIndonesian basins to have evolved from a rifted internalfracture/foreland basin into a marginal-sag. Much of theearly basin fill in the Kutei Basin has been inverted andexposed (Satyana et al., 1999), and the late postriftMahakam Delta dominates the prospectivity. The latteralso contains a deepwater continental margin play rare inother Indonesian basins.

�
Early Synrift (Paleocene to Early Eocene): Sediments of thisstage comprise alluvial sediments filling in the topographyof NE–SW and NNE–SSW trending rifts in the onshoreKutei Basin. They overlie a basement comprising lateCretaceous to early Tertiary deep marine sequences. � Late Synrift (Middle to Late Eocene): During this
period, a major transgression took place in the KuteiBasin, 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 andseveral thousand meters of predominantly shales accu-mulated. On structurally shallow areas open marinecarbonate platforms were developed.
� Late Postrift (Middle Miocene to Quaternary): From
Middle Miocene onwards a major passive margin deltaicsequence prograded into the deep water Makassar Strait,forming the Mahakam Delta sequence, the primaryhydrocarbon-bearing portion of the basin. A variety ofon- and offshore deltaic depositional environments aredeveloped in the Balikpapan and Kampung Baru forma-tions, including deeper water slope and basin floor facies.Excellent source and reservoir rocks are present, withinterbedded sealing shales. During this period, erosionreworked large parts of the Kutei synrift sequence.

The tectonic history may be summarized as follows:
Following deformation of the late Cretaceous to earliestTertiary basement, extension and rifting associated withopening of the Makassar Straits continued through to theend of the Eocene. Oligocene subsidence and sag werefollowed by inversion of the early Kutei Basin fill along itsinitial boundary faults in the early Miocene, resulting in theerosion of several thousand meters of the synrift sequence(Satyana et al., 1999). This in turn led to a major deltaicprogradation over the continent margin to the east (toform the Mahakam Delta sequence). Continental collisionsin the area are thought to have been responsible foryounger inversions affecting the early Miocene sequence.Within the shelf Mahakam Delta sequence, the dominanttrap-forming mechanism comprises syn-sedimentarygrowth faulting. The slope to basin floor section is chara-cterized by toe-thrust structures.

In this basin, a number of petroleum systems can berecognized, each with associated sub-systems:

1.
In the onshore Kutei Basin, largely comprising invertedsynrift sequences where as yet few hydrocarbons havebeen located, Howes and Tisnawijaya (1995) suggestedthat an early synrift to early postrift petroleum system,the Tanjung–Berai (.) PS may be developed. However, itremains speculative.
2.
The onshore to offshore Mahakam Delta, whichincludes the majority of prospective sequences, belongsto a thick, late postrift continental margin stage ofdevelopment. In this rich oil and gas province, almost allof the hydrocarbons are sourced from and trapped inreservoirs of the late postrift stage. Accordingly, thedeltaic Balikpapan–Balikpapan (!) PS is overwhelminglythe dominant one in this area. Reservoir sands,belonging to a series of stacked regressive deltaicprogradational sequences range in age from MiddleMiocene to Pleistocene (Balikpapan to Kampung Baruformations), and most accumulations occur at severallevels, separated by intraformational sealing shalesrepresenting maximum flooding surfaces. As in otherTertiary deltas, a range of trap types is represented,including:(a) Hangingwall anticlinal rollovers associated with
growth faults, many cut by synthetic and antitheticfaults to form ‘‘collapsed crest’’ structures. Trap-ping of individual stacked accumulations is partly-fault dependant (i.e. in footwall or hanging wallblocks). The structures are frequently dome-shapedor oval in shape and occur mainly in nearshore andshallow offshore areas.

(b) Elongated inverted anticlinal deltaic rollover struc-tures with a NNE–SSW trend, related to thrusts andreverse faults, often on both flanks. These occurprimarily in the onshore part of the delta andcontain many of the larger fields. Characteristic ofmany fields are cross faults that divide theaccumulations into separate units. McClay et al.(2000) demonstrated that many of these structuresoriginate from inversion of growth-faulted struc-tures above a ductile substrate.

(c) Stratigraphic traps related to deltaic sand bodiesencased in shales. In many cases stratigraphicchanges contribute to trapping only, for instancewhere deltaic channels are draped over anticlinaltrends, but in a few cases sand pinch-out appears todefine the trap (e.g. in the Bongkaran and Tamborafields), while a hydrodynamic effect can sometimesbe identified.

Duval et al. (1998) summarized some of the mostimportant parameters that impact hydrocarbon pro-spectivity. They indicated that the main charge for fieldsin the Tambora and Tunu trends is derived from thick


deltaic coals and coaly shales in the intervening syncline,with minor contributions from a marine and leanersource rock in the offshore trend between the Tunu andSisi fields. They noted that efficient short migrationpaths up to 15 km in length lead from these chargekitchens into adjacent structures. They noted a gradualtransition from oil, in more proximal anticlinal fields(Tambora, Handil) to gas/condensate rich fields in moredistal trends, where source rocks are leaner, and thickershale packages restrict migration of heavier hydrocar-bons. These observations relate to the shallow progra-dational deltaic sequences.A number of anticlinalstructures contain oil and gas fields in early Mioceneregressive sands, for instance in the Wailawi field. Thesedeltaic sands, with interbedded shales and coals (KlinjauFormation) were deposited during the period of maxi-mum transgression when carbonate facies were exten-sively developed in the Kutei/Makakam area. Theyprovide evidence for the local strength of the deltaicsystem and suggest that an early postrift petroleumsystem exists in places. This can be referred to as theKlinjau–Klinjau (.) PS.

3.

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

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

field trends.

Recently, the focus of exploration has moved into thedeeper water portions of the delta, where fields are beingdiscovered in turbidite reservoirs deposited in slopechannel and basin floor systems. The discoveries belongto a new petroleum system called the Miocene–Mio/

Pliocene (.) PS. Reservoir quality sands have been foundwidely distributed in the Middle Miocene to Pliocenesection. The oil and gas accumulations are thought tohave received charge from organic matter of land plantorigin, 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 oilderived from deep water systems, both less waxy thanthe onshore oils.Compressional anticlines and toe thrusts form theprimary structural traps in the Mahakam deepwatersystem. Reservoir sands occur in confined amalgamatedchannel–levee complexes (e.g. Merah Besar and WestSeno discoveries), and as unconfined sheet-like sub-marine fans (Dunham and McKee, 2001). Due to thenature of the sand bodies, opportunities clearly exist forstratigraphic trapping. There is still much to be learnedabout the geometry and productivity of these sandbodies as additional discoveries are made and appraised.The West Seno field, discovered by Unocal in the late1990s, is Indonesia’s first deepwater development, thefirst barrel of oil being produced in mid-2003.

The Kutei–Mahakam Delta province is one of the richestin Indonesia, with discoveries totalling more than 3.5billion barrels of oil and 35 tcf of gas. It supports animportant and expanding LNG project. The creamingcurve for oil suggests that, unless significant new reservesare identified in the deep water, only small incrementalaccumulations can be expected in the future. The gas curve,

on the other hand, which is characterized by a series ofsteps reflecting major discoveries, shows little evidence forcreaming. Such a ‘‘relatively efficient’’ creaming curve istypical for deltaic areas in which there is a gradual seawardshift in exploration as new technologies become available.

5.10. Tarakan Basin

The Tarakan Basin has a similar development to theKutei–Mahakam Basin (Lentini and Darman, 1996), whichit 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 withmainly younger fill). As in the Kutei–Mahakam Basin,hydrocarbons have been located in the late postrift stageonly.

�
Early Synrift (Middle Eocene): This sequence is domi-nated by volcanics and volcaniclastics of the SembakangFormation. It is highly tectonized.


�
Late Synrift (Late Eocene): This comprises fluvio-deltaicto shallow marine shales, marking a rapid transgressivephase. � Early Postrift (Oligocene to Early Miocene): This period
is dominated by open marine carbonate platformdevelopment on shallow blocks, with deeper marineenvironments represented by shales and marls in theintervening depressions. Local late Oligocene uplift canbe linked to a minor clastic progradation from the west.
� Late Postrift (Middle Miocene to Quaternary): This
forms the main hydrocarbon-bearing sequence and iscomposed of a number of regressive progradations ofinterbedded fluvio-deltaic sands, shales and coals.NE–SW trending growth faults intersect with fourNW–SE trending fold trends. To the south and northof the deltaic depocenters, carbonates continued toaccumulate.

Eocene rifting was followed by a generally quiescentbasin history, interrupted by a phase of uplift in theonshore area in the Late Oligocene. Traps were formed inthe Pliocene and Pleistocene and rely on a combination ofgrowth faults and discrete NW–SE trending compressionalfolds and faults produced during a series of uplift andinversion events.


All hydrocarbons in the Tarakan basin are derived fromand trapped in late postrift stage sediments. Source rocksare Middle to Late Miocene coals and coaly shales of theTabul Formation, while fluvio-deltaic sands belonging tothe Late Miocene Tabul and Plio-Pleistocene Tarakanformations form the main reservoirs. A variety of traptypes are present, concentrated at points where growthfaults culminate above the NW–SE trending anticlinalarches. Several hangingwall dip closures, assisted or not byfault closure are represented, as well as local pure footwallclosures. All accumulations belong to the Tabul–Tarakan

(!) PS. The deepwater area remains largely unexplored todate with only a few wells having been drilled, so farwithout commercial success.

The creaming curve for this basin is dominated by thediscovery of the Bunyu field in 1922. Since then only minorquantities 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 sedimentarysequences derived from slices of the Australian continentalmargin that were incorporated in the eastern Indonesiancollision zone during the Middle and Late Tertiary(Hutchinson, 1996). Thus, although Tertiary depositionalenvironment and lithofacies developments are recognizable,

the Tertiary synrift to postrift basin development cannot bereadily applied to the petroleum habitat.The Bula Basin in Seram overlies and is partly

incorporated in a fold/thrust and zone formed where theouter margin of Australian continental shelf collidedwith Irian Jaya in the mid-Tertairy (Hutchinson, 1996).The bulk of the sequence is composed of a variety ofMesozoic to Middle Tertiary open marine pelagic andoceanic deposits, including clays, limestones and thinsands. The first oil discoveries, which were made by theDutch in the early 1900s, focussed on Pliocene toPleistocene marginal marine sands and limestones. Morerecent discoveries in the complex fold and thrustbelt successfully located oil in fractured Jurassic lime-stones (e.g. Oseil Field; Charlton, 2004). Geochemicalstudies (Peters et al., 1999) demonstrate that the oil isderived from Triassic–Jurassic marine carbonate type IIsource rocks.Two hydrocarbon-bearing late Tertiary successor basins,

the Salawati and Bintuni basins, are found in the Bird’sHead region of West Papua (formerly called Irian Jaya).Both overlie Australian continental basement. Permian andMesozoic are known to occur in the Bintuni Basin andprovide an important hydrocarbon habitat.In the Salawati Basin the pre-Tertiary does not

contribute to the petroleum system and if present, occursat depths of no commercial consequence:

�
Early Synrift (Paleocene to Eocene): During this period,outer neritic to bathyal shales and carbonates of theWaripi Formation were deposited, indicating that riftformation took place in deep water. � Late Synrift (Late Eocene to Oligocene): The deepwater
environments were succeeded by a carbonate platform(Fauma Formation) and deltaic clastics (Sirga Forma-tion) as the rift was in-filled.
� Early Postrift (Miocene): This period represents a
transgressive period during which extensive carbonateplatforms and reefs of the Kais Formation developed.The reefs are surrounded by marginal clastics of thedeep water Klamogun Formation. This shoaled intothe Late Miocene. Rapid subsidence is evidencedby high-standing pinnacle reefs. Charge in the basinmay be derived from marine type II/III source rockmarls and shales of the Klasafet Formation (Peterset al., 1999).
� Late Postrift (Plio-Pleistocene): A rapidly deposited and
very thick sequence of regressive clastics, includingsands and shales of the Klasaman Formation accumu-lated. The underlying Late Miocene Klasafet sourcerock attained maturity as a result of this thicksedimentary wedge.

Following accretion of the basement sequence in thePaleocene, subsidence was rapid in this continent margin
basin. Transcurrent movements along the Sorong faultcommenced in the late Miocene and led to uplift and

ARTICLE IN PRESS

Fig. 14. East Indonesia basins—location map (top left), West Papua and Seram basins (Salawati, Bintuni and Bula, respectively, top right) and Tomori

Basin, Sulawesi (bottom left). Oil and gas fields are classified according to the basin stage in which they occur.


erosion adjacent to the basin—this provided the sedimentsfor the late postrift that covered the Miocene carbonates.Wrench movements have continued up to the present day.

The Tertiary section Wiriagar area (Fig. 14) of theBintuni Basin has a similar stratigraphy to the SalawatiBasin, with the exception that pinnacle reefs did notdevelop to the same degree, perhaps due to excessivesubsidence rates. Low relief Kais Formation reefs, wherepresent, are known to contain oil, but the volumes are lesssignificant than in the Salawati trend. The main petroleumsystem of the Bintuni basin occurs within the Mesozoicsection, as indicated by the huge gas discoveries atWiriagar (Dolan and Hermany, 1988), Vorwata andUbadari (collectively known as the Tagguh field). Thesource for these hydrocarbons lies within a thick Permiansequence, rich in type III coals, with some contributionsfrom overmature marine argillaceous type II/III sourcerocks of the Mid-Late Jurassic.

The Tomori Basin of eastern Sulawesi (Fig. 14) bearsmany similarities to the Salawati and Tertiary Bintunibasinal areas. Left lateral strike–slip movements along theSorong fault have resulted in accretion of Australianmicrocontinental fragments into the East Sulawesi andBanggai-Sula regions (Milsom et al., 1999). Collision (Hall,1997) and obduction of ophiolitic material in EastSulawesi, thought to have occurred during the Pliocene,created a fold–thrust system with an associated foreland

basin called the Tomori Basin. In the Senoro-Toiliand Tiaka regions, both oil and gas have been foundin Miocene biohermal reservoirs of similar age to thereservoirs in the Salawati and Buntuni basins (Davies,1990).


In the Bula Basin, only one small producing field ispresent (Bula-Lemun, approximately 15millionbbl). Itbelongs to a petroleum system that can be defined ashaving been charged from a Triassic–Jurassic marinecarbonate type II mudstone source rock and having aPleistocene reefoid sandy limestone reservoir. It is definedhere as the Mesozoic–Fufa (!) PS. Two small oil fields, nowclosed in, are located in marginal marine sandstonereservoirs in the thrusted Jurassic and Triassic sequences,indicating that a second petroleum system is present. Thiswe refer to the Mesozoic–Manusela (.) PS, as defined byHowes and Tisnawijaya (1995). A new discovery in thispetroleum system, the Oseil field, is currently underdevelopment (Nilandaroe et al., 2001).The Salawati Basin is characterized by a compact area

with a rich petroleum system, from which more than300millionbbl of oil have been produced from 15 fields(half of it from one field, Walio). We refer to it as theKlasafet–Kais (!) PS. It is characterized by the followingelements: Source rock—late Miocene marine shales and


marlstones (type II/III) of the Klasafet Formation;reservoir rock/trap—Kais Formation limestones and do-lomitic limestones in pinnacle reefs underlying surfacedrape anticlines composed of sealing shales. The pinnaclereefs are situated updip of the probable source kitchen tothe north, allowing for efficient migration from overlyingshales into porous migration conduits. In this smallprovince with a single play, exploration has been highlyefficient, as can be seen from the creaming curve (Howesand Tisnawijaya, 1995). Following the mid-1970s few newdiscoveries have been made and, as in many carbonateprovinces, the production has since been in steep decline.

Two petroleum systems are developed in the BintuniBasin area: the Tertiary–Kais (.) PS and the Aifam–Roabiba

(!) PS in the pre-Tertiary sequence. The Tertiary–Kaissystem has yielded little in the way of commercial oildiscoveries, although with improved seismic, better defini-tion and location of reefal facies may be possible. TheAifam–Roabiba system is by far the more important,giving rise to a major new LNG project based on the over18 tcf of certified gas reserves of the Tangguh field area.The Roabiba sands, which form the primary reservoir, aresimilar in age and properties to the highly productivePlover Fm, well known from Timor Sea region ofthe Northwest shelf of Australia (Whittam et al., 1996).A secondary reservoir in Paleocene turbiditic sands is alsopresent, but the reservoir properties appear less uniformthan those of the primary Roabiba sands.

Structural development in the Tangguh area was twofold: an early phase of Late Mesozoic postrift folding,followed by Plio-Pleistocene compression associated withthe development of the Lengguru fold and thrust belt to theeast. Charge from the Permian/Jurassic source system wasinitiated during the Pliocene by rapid subsidence and burialwithin a foreland setting west of the Lengguru thrust front.

In the Tomori basin of East Sulawesi, two petroleumsystems have been observed to date. The first is theTomori–Tomori (.) PS in which oil has been found infractured limestones of the Lower Miocene TomoriFormation (Davies, 1990). The reservoir facies is aplatform limestone, with lower porosity and permeabilitythan the reefoid facies seen elsewhere in the region. Chargefor this system is derived from marine shales and marls ofthe Lower Miocene Tomori Formation, which hasgeochemical properties similar to those of the KlasafetFormation in the Salawati basin (albeit of slightly differentage). The second system is the Minahaki–Mantawa (.) PS.This system encompasses a series of gas discoveries inbiohermal reservoirs of the Late Miocene Mantawamember of the Minahaki Formation. The gas appears tobe largely of biogenic origin, being derived from bacterialconversion of organic matter in the surrounding Minahakiand Matindok claystones. Some of the gas accumulationshave a small oil rim and elevated condensate yield,indicating that a mixed source system is active, with oilcharge derived from the underlying Tomori shales (Nobleet al., 2000). Gas resources in this region are being

appraised with the possibility of future commercialdevelopment for local or export markets.

6. Common petroleum systems and their development

In the above discussion, we have limited the petroleumsystems identified and discussed to those that occur inproductive hydrocarbon basins in Indonesia and which arerepresented by fields or potentially commercial accumula-tions. Indications for other systems that could, forinstance, be evidenced by promising source rock horizonsand/or seepages have not been included, nor have potentialpetroleum systems in non-productive basins (of which thereare several). The reason for this is that the uncertaintiesrelated to these potential and speculative petroleumsystems are so great that there is little to be learned fromthem—rather, the lessons derived from the known systemsdiscussed above should be applied to evaluate theirpotential. For a more complete list of potential andspeculative systems (those without discoveries to date),the reader should consult Howes and Tisnawijaya (1995)and Bradshaw et al. (1997). The latter includes a list ofpetroleum systems in the Indonesian–Australian Zone ofCooperation (ZOCA).The list of petroleum systems presented represents our

best estimate based on the principle of clustering thosewithin one basin area (as currently in common usage inIndonesia) supported by geochemical correlation studies.As the latter improve, the list will need constant revision.

6.1. Petroleum systems in their basin stage context

Most of the petroleum systems identified above can begrouped into one of the four petroleum system typesdescribed from SE Asia in general by Doust and Lijmbach(1997) and shown in Fig. 15. We thus make a link betweenthe petroleum geology and the basin evolution, so that wecan identify the common elements of petroleum systemsdeveloped in the four basin stages and bring out thevariations within them—the latter usually being related todifferences in the sequence of depositional environments. Wecan recognize two categories in each petroleum system type:

Category (i): Those in which both source and reservoirlie within the same basin stage (i.e. the PS is integral tothat stage).Category (ii): Those in which the reservoir lies inanother, usually younger, basin stage than the source.

The basic petroleum system types described beloware sometimes shortened in the text and figures to PST 1,PST 2, PST 3 and PST 4:

1.
Early Synrift Lacustrine petroleum system type (PST 1)Category (i)Pematang—Pematang (!) PS (Central SumatraBasin).

ARTICLE IN PRESS

Fig. 15. The four petroleum system types (PSTs) typical of Southeast Asian Tertiary basins and their relation to basin stages, from Doust and Lijmbach,

(1997). A number of the most important characteristics of each are shown.


Banuwati–Harriet Mbr (.) PS, (Sunda/Asribasins).Tanjung–Tanjung (!) PS, (Barito Basin).

Category (ii)Pematang–Sihapas (!) PS, reservoir in PST 2(Central Sumatra Basin).Pematang–Duri (!) PS, reservoir in PST 3 (CentralSumatra Basin).Benua–Gabus (!) PS, reservoir in PST 2 (WestNatuna Sea).Banuwati–Talang Akar (!) PS, reservoir in PST 2(Sunda/Asri basins).Ngimbang–Kujung (.) PS, reservoir in PST 2(NE Java Basin).Ngimbang–Ngrayong (.) PS, reservoir in PST 3(NE Java Basin).Ngimbang–Pliocene (.) PS, reservoir in PST 4(NE Java Basin).Tanjung–Kutei (.) PS, reservoir in PST 3 (KuteiBasin).

2.
Late Synrift Transgressive Fluvio-deltaic petroleumsystem type (PST 2)
Category (i)Talang Akar–Talang Akar (!) PS, includes possiblecharge from PST 1 (South Sumatra Basin).

Category (ii)Bampo–Peutu (!) PS, reservoir in PST 3 (NorthSumatra Basin).

Talang Akar–Palembang (.) PS, reservoir in PST 4(South Sumatra Basin).Talang Akar–Main/Massive (!) PS, reservoir inPST 3 (NW Java Basin).Talang Akar–Jatibarang (.) PS, reservoir in PST 1(Jatibarang tuffs onshore Java).

3.
Early Postrift Marine petroleum system type (PST 3)Category (i)Gumai–Gumai (.) PS (South Sumatra Basin).Tertiary–Terumbu (.) PS, origin of chargeunknown (East Natuna Sea).Klinjau–Klinjau (.) PS (Mahakam Delta Basin).Klasafet–Kais (!) PS (Salawati Basin).Tertiary–Kais (.) PS Bintuni Basin.Tomori–Tomori (.) PS Tomori Basin.
4.
Late Postrift Regressive Deltaic petroleum system type(PST 4)
Category (i)Baong–Keutapang (!) PS (North Sumatra Basin).Balikpapan–Balikpapan (!) PS (Mahakam DeltaBasin).Miocene–Mio/Pliocene (.) PS (Deepwater Makas-sar Straits).Tabul–Tarakan (!) PS (Tarakan Basin).

Category (ii)Tertiary–Belumai (.) PS, source possible Baong,reservoir in PST 3 (North Sumatra Basin).


A number of petroleum systems do not lend themselvesto classification in the four PSTs. These include:

Biogenic–Parigi (.) PS, for which the charge is biogenicrather than thermogenic (NW Java);

Mesozoic–Fufa (!) PS, charge from prerift Mesozoic intoreservoir in PST 4 (Bula Basin);

Mesozoic–Manusela (.) PS, charge and reservoir in theprerift Mesozoic (Bula Basin);

Aifam–Roabiba (!) PS, charge from pre-Mesozoic,reservoir in Mesozoic early post rift (Bintuni Basin); and

Minahaki–Mantawa (.) PS, biogenic charge from LateMiocene sediments (Tomori BSIN).

7. Basin families, their tectonostratigraphic evolution and

prospectivity

The distribution of the petroleum systems identified isdependent on the sedimentary basin history. Knowledge ofthe syn- and postrift basin evolution and the succession ofdepositional environments makes it possible to identifyand/or predict which petroleum systems (and theirconstituent plays) may be present. To aid this, we havedistinguished a number of characteristic Indonesian basinfamilies, which have distinct ‘‘trajectories’’ (Doust, 2003)through a matrix of deepening depositional environmentand basin development phase (Fig. 16).

Proximal basins: These are basins that throughout theirdevelopment maintained relatively proximal depositionalenvironments. They are located close to the core of the pre-Tertiary Sunda Craton.

�

Fig

aft

Evolution: Early Synrift, lacustrine; Late Synrift, deltaic;Early Postrift, marine (clastic); Late Postrift, deltaic.
� Dominant petroleum system type(s): PST 1 Early Synrift
Lacustrine.
� Example basins: Central Sumatra, West Natuna, Asri.
. 16. Petroleum systems types in Indonesia grouped into families showing t

er Doust (2003). ‘‘Trajectories’’ of Proximal, Intermediate, Distal and Born

from rich early synrift lacustrine to deltaic source rocks.
Proximal basins are strongly oil-prone, receiving charge
The best reservoirs and most of the hydrocarbon accumu-lations are situated in late synrift deltaic clastics, under-lying the regional early postrift seal. The maintenance ofproximal environments implies that subsidence was lim-ited, and maturity is often a crucial issue: typically fieldsare located directly above active early synrift sourcekitchens.

Intermediate basins: These have a typically proximalsynrift development, but underwent greater subsidence inthe postrift, where they are characterized by more distalenvironments.

�

he d

eo

Evolution: Early Synrift, lacustrine to deltaic; LateSynrift, deltaic; Early Postrift, marine (clastic andcarbonate); Late Postrift, deltaic.
� Dominant petroleum system type(s): PST 2 Late Synrift
Transgressive Deltaic, PST 1 Early Synrift Lacustrine,with minor PST 3 Early Postrift Marine.
� Example basins: South Sumatra, East Natuna, Sunda,
NW Java onshore, NE Java onshore, Barito.

Intermediate basins contain the greatest diversity ofpetroleum system types, thanks to their mixture of richsynrift charge and postrift reservoirs. They are both oil andgas prone thanks to the enhanced subsidence, which bringsthe late synrift to maturity, thus allowing for a charge frommixed early and late synrift lacustrine and deltaic sources.The presence of marine clastic and carbonate reservoirscovered by regional marine shales enhances the efficiencyof these basins. The late postrift deltaic sequence containscoaly source rocks and reservoir sands, but maturity is notreached, so charge to this level can be achieved only wherethe early postrift seal is proximal and breached (as in theJambi area of South Sumatra).

epositional environment evolution in relation to tectonic basin stages,

(Kalimantan) basins are shown.


Distal basins: Distal basins occupy the edges of the pre-Tertiary Sunda craton, and have either a history ofsubstantial subsidence or are located distally with respectto postrift uplift and delta developments.

�
Evolution: Early Synrift, deltaic; Late Synrift, marine;Early Postrift, marine (carbonate and clastic); LatePostrift, deltaic to deeper marine. � Dominant petroleum system type(s): PST 2 Late Synrift
Transgressive Deltaic, PST 3 Early Postrift Marine, PST4 Late Postrift Regressive Deltaic.
� Example basins: North Sumatra, NW Java offshore, NE
Java offshore.

Distal basins were open to the ocean in the early synriftand miss the lacustrine development, so most of the chargeis terrestrial (deltaic and/or marine). As a result, they tendto be more gas prone (except in the case of the southernpart of North Sumatra, where the source and reservoir arein the postrift stage). In many cases, the main reservoirs areearly postrift carbonates—these basins lie outside theinfluence of the Tertiary clastic wedges.

Borneo basins: The Kutei–Mahakam and Tarakan basinsof Kalimantan belong to a family that developed on LateMesozoic to Tertiary crust and subsequently came to liealong a passive continental margin. Early stages of basinevolution were subjected to extensive inversion and onlythe late postrift contributes to the petroleum geology.

�
Evolution: Early Synrift, alluvial; Late Synrift, deepmarine; Early Postrift, deep marine (carbonate andclastic); Late Postrift, deltaic to deeper marine. � Dominant petroleum system type(s): PST 4 Late Postrift
Regressive Deltaic.
� Example basins: Kutei–Mahakam, Tarakan.
These basins show the late postrift prospectivity best—they are very rich, with excellent deltaic reservoirs andsource rocks. The interbedded nature of the source,reservoir and seals results in multiple stacked accumula-tions, containing major reserves of both oil and gas.

Eastern Indonesian basins: These basins have complexand variable histories, in which the tectonic development isspread over the Mesozoic and Tertiary. Nevertheless, wecan still identify similar patterns as in the other basins inthe Tertiary.

�
Evolution: Early Synrift, open marine to deep water;Late Synrift, carbonates and deltaics; Early Postrift,carbonate platforms and marine clastics; Late Postrift,deltaic. � Dominant Petroleum system type(s): Mesozoic–Tertiary,
PST 3 Early Postrift Marine.
� Example basins: Tomori, Bula, Salawati, Bintuni.
In the Salawati, Tertiary Bintuni and Tomori basins, thecharge appears to arise from Miocene source rocks. In

other areas, Mesozoic and pre-Mesozoic rocks with strongaffinity to Australian sequences provide both source andreservoir.

More detail on the hydrocarbon habitat parametersrelated to the environments represented in the variousbasin types are described above in the section on aspects ofthe hydrocarbon system.It is interesting to note that, as with many basins,

Indonesian basins usually comprise suites of proximal todistal environments at each stage in their history. Thecharacteristics of the various basin types noted above,therefore, can be applied to the description and evaluationof portions of basins as much as to that of the basins as awhole. The basin families referred to are elements of amuch larger system of similar basins, developed through-out the Tertiary of the Far East and SE Asia (Doust andSumner, 2007).

8. Summary and conclusions

Indonesian petroliferous basins share a number ofimportant characteristics: most are Tertiary in age and passthrough early Tertiary synrift to late Tertiary postrift stagesof geological development. They are filled with non-marineto marine sediments subject to rapid environmentally-controlled facies variations and receive charge almostexclusively from terrestrial and/or lacustrine source material.The petroleum systems present in the various basins can

be classified into four PSTs, which can be related directly tothe main stages of basin development. These PSTs are:

�
Early Synrift Lacustrine PST—strongly oil-prone,thanks to charge from rich lacustrine source rocks,located in the deeper Eocene to Oligocene parts of therift basins. � Late Synrift Transgressive Deltaic PST—commonly
with oil and gas derived from terrestrial deltaic sourcerocks, occupying the shallower Oligocene to earlyMiocene parts of the rift basins.
� Early Postrift Marine PST—mainly gas prone, with
charge from marine shales, corresponding to an earlyMiocene period of transgression that flooded the synriftgrabens and their surrounding platforms.
� Late Postrift Regressive Deltaic PST—oil and gas prone,
derived from rich deltaic terrestrial source rocks depositedin deltas that prograded out over the basins in the lateTertiary in response to collisional and inversion events.

The development and distribution of petroleum systemsin Indonesian basins is dependent on a number of factors,including the source rock facies and maturity, variability inthe development of reservoir facies, whether the sealinghorizons are intra-formational or regional in extent and onthe style and development of structural traps. Chargecannot in general be ascribed to individual source horizons


and it is clear that considerable mixing has taken place.This is reflected in the fact that in many cases an older anddeeper-lying PST has apparently charged reservoirs be-longing to shallower PSTs.

Not surprisingly, the predominant depositional environ-ment and lithofacies of the basins dictates the predominantpetroleum system type that is present. We have recognizedthe following ‘‘basin families’’, based on their location withrespect to the continental core of SE Asia, the SundaCraton:

�
Proximal basins (e.g., Central Sumatra, West Natuna,Asri) in which the Early Synrift Lacustrine PST ispredominant. � Intermediate basins (e.g. South Sumatra, East Natuna,
Sunda, onshore Java, Barito), which contain bothsynrift PSTs as well as, in some cases, a contributionfrom the Early Postrift Marine PST.
� Distal basins (e.g. North Sumatra, Java offshore) in
which the dominant PSTs are the Late Synrift Trans-gressive Deltaic and the Marine and Regressive DeltaicPSTs of the postrift.
� Borneo basins (e.g. Kutei–Mahakam, Tarakan) in which
only the Late Postrift Regressive Deltaic PST isdeveloped.
� Eastern Indonesian basins (e.g. Tomori, Bula, Salawati,
Bintuni) in which the petroleum system is eitherMesozoic or belongs to the Early Postrift Marine PST.

Acknowledgements

We are grateful to all of the authors whose work over theyears has contributed so abundantly to knowledge ofIndonesian petroleum geology—without them a synthesisof the main trends, as we have attempted here, would beimpossible. One of us (H.D.) is also grateful to ShellInternational Petroleum Company for the opportunity(in the 1990s) to study, with an outstanding team, thefascinating geology of Far East Tertiary basins. Some ofthe ideas presented here were conceived during this period.R.A.N. is grateful for the support of Unocal IndonesiaCompany and for their permission to publish this article.Finally, we are very grateful to anonymous reviewers whohelped us in many ways to increase the quality andconsistency of the text.

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Documents

Petroleum systems of Indonesia · Marine and Petroleum Geology 25 (2008) 103–129 Petroleum systems of Indonesia Harry Dousta,, Ron A. Nobleb,1 aVrije Universiteit Amsterdam, The