Geology Indonesia

A Geological Overview of Indonesia

Chapter 4

The Petroleum Geology of Indonesia

Indonesia is diverse in terms of culture, geography and geology. It is a sprawlingnation of 9.5 million km2 and, with 80% of its area being water and more than17,000 islands, it is the largest archipelago in the world. It traces the path of theequator for over 5400 km east to west across three time zones and extends for over1800 km from north to south.

I ndonesias development as a nation hasbeen strongly influenced by its geographyand geology, with the interplay between

climate, rainfall and volcanic activity

shaping agricultural and population patterns

in different ways throughout the islands.

Java and Bali, for example, are endowed

with some of the most fertile volcanic soils

on Earth. For this reason they are

population and cultural centers. Out of the

total population of over 200 million, nearly

50% live on the relatively small island of

Java, which represents only 7% of the total

land area.

Other regions, such as Kalimantan and

Sumatra with their dense rain forests, or

the Nusa Tenggara (Lesser Sunda) islands

with their more arid climate, are less

densely populated.

In the nineteenth century the British

botanist Sir Alfred Russell Wallace (who

together with Darwin is credited with the

theory of evolution) determined a precise

line of demarcation that separates the flora

and fauna found throughout Asia from those

unique to Australasia. This divide is termed

the Wallace line and passes between Bali

and Lombok and then northward between

Borneo and the Celebes (Sulawesi). It is no

coincidence that the Wallace line is also a

major geological divide. The islands to the

west represent the tectonically disrupted

southeastern promontory of the continental

Asian plate (the Sunda shield or

Sundaland), whereas those to the east are

fragments of the ancient continental

Australian plate (Australian craton). These

two plates started to collide only about

8 million years ago (mybp) towards the end

of the Miocene epoch which, in geological

terms, is relatively recent. Before this time,

the flora and fauna of these two landmasses

had developed in very different directions

and remain distinct to this day.

Controlled largely by the different

geological regimes of Eastern and Western

Indonesia, the pattern of hydrocarbon

exploration and exploitation differs across

the archipelago. Indonesia contains more

than 60 sedimentary basins and inter-basin

areas in which hydrocarbon accumulations

are either proven or possible (Figure 1).

This is a significant number considering that

there are estimated to be only 600

sedimentary basins worldwide (Pattinama

and Samuel, 1992). Indonesia is also

probably the most diverse nation in the

world in terms of petroleum systems. There

are at least 50 proven and probably more

than 100 speculative (lightly explored or

unexplored) petroleum systems (Howes,

1999). These vary greatly with regard to

their age and geological characteristics. Most

of the proven and exploited hydrocarbon

systems occur in Western Indonesia and are

at a relatively mature stage of exploration.

Eastern Indonesia remains, however,

relatively underexplored and almost half of

the basins have not been drilled.

Indonesia is the fifteenth largest oil

producer in the world and the only OPEC

member in Southeast Asia, producing over

80% of all oil for this region. Indonesian oil

is in high demand on the world market

because of its low (

Overview of Indonesias oil and gas industry Geology 175

0 400 800 1000km

Producing (14)

Discovery (10)

No discovery (14)

Undrilled (22)

Tertiary petroleum

Pre-Tertiary petroleum

Eastern Indonesia

Indonesian sedimentary basins

Western Indonesia

NEH

EH

SEHSW

MOSE

BTW/W

CIJAK

AR

AKT

W

CAB NWS

ZOCTI

BD

BUB

F

SS

L

K/MS

AA/P

MU

CE

KE

Kalimantan

Irian Jaya

Java

JF

PEBIS/ASSF

NSF

NSB

SSB

CSB

NWJ

MEUK

ENWN

TA

EJ

PN

BA

SBL

S/M

B/S

GO

SM/NM

Malaysia

Malaysiaand Brunei

Singapore

Philippines

SA

TBASulawesi

Sumatra

Western Indonesia(22 basins)

Eastern Indonesia(38 basins)

38 (63.3%)

22 (36.7%)

Producing(50.0%)

Producing(7.9%)

Discoveries(Non-producing)

(13.6%)

Discoveries(Non-producing)

(15.8%)Drilled(No discoveries)

(22.7%)

Drilled(No discoveries)

(26.3%)

Undrilled(13.6%)

Undrilled(50.0%)

Eastern Indonesia

Western Indonesia

Western Indonesia

NSB - North SumatraCSB - Central SumatraSSB - South SumatraNSF - North Sumatra fore arcSSF - South Sumatra fore arc/BengkuluS/A - Sunda/AsriNWJ - Northwest JavaJF - Java fore arcEJ - East Java/Java SeaBI - BillitongPE - PembuangBA - BaritoPN - Pater Noster platformAA/P - Asem-Asem/PasirUK - Upper KuteiK/MS - Kutei/Makassar StraitsMU - MuaraTA - TarakanCE - CelebesKE - KetungauME - MelawaiWN - West NatunaEN - East Natuna

Eastern Indonesia

SM/NM - South/North MinahasaGO - GorontaloB/S - BanggaiSulaS/M - SalabangkaManuiBU - ButonBD - BandaB - BoneF - FloresSS - Spermonde/SelayarL - LariangSBL - South BaliLombokSA - SavuTI - TimorNWSZOC - Northwest Shelf zone

of cooperationW - WeberSE - SeramNEH - Northeast HalmaheraEH - East HalmaheraSEH - Southeast HalmaheraSW - SalawatiBT - BintuniMO - Misool-OninTBA - Teluk BerauAjumaruKT - Kai TanimbarA - AruAK - AkmeugahAR - ArafuraCIJ - Central Irian JayaW/W - Waipoga/Waropen

Wal

lace

line

Moluccas

TImorNusa Tenggara

Figure 1: Simplified map of Indonesias basins and theirexploration status (after Sujanto, 1997 and Sumantriand Sjahbuddin, 1994).

to Japan, but also to Taiwan and Korea.

Howes (1999) estimates ultimate discovered

reserves of 55 BBOE (billion barrels oil

equivalent) split approximately equally

between oil and gas. Sujanto (1997)

estimates current remaining reserves at

approximately 93 BBO (billion barrels oil)

and 123 TcfG (trillion cubic feet of gas).

Indonesia consumes almost 140 MBO

(million barrels of oil) each year for power

generation alone and, until recently, the

power demand had been increasing by 7%

every year. The focus must obviously be on

supplementing and replacing the

dependence on oil-generated power with

cleaner and/or replenishable fuels, and also

replacing declining oil reserves to postpone

the day when Indonesia ultimately becomes

a net oil importer. Over the past decade, oil

exploration has not been successful in

replacing oil reserves. In contrast, gas

reserves have made up for this shortfall in

terms of BBOE and, at present, gas would

appear to be one of the main energy sources

of the future in Indonesia. Geothermal

energy also holds hope for the future, with

over 100 prospects recognized in the highly

volcanic areas, especially Sumatra and Java,

where energy demand is also highest.

Geological evolution of theIndonesian archipelagoUnderstanding the geological evolution of the

Indonesian archipelago and how the various

sedimentary basins developed, are the keys to

understanding the petroleum systems within

the individual basins and for developing

future exploration plays and strategies.

Indonesia has a dynamic and complex

geological history, which has resulted in an

abundance of sedimentary basins with wide-

ranging geological diversity. Basins and the

nature of their sediments demonstrate close

similarities within, and to a much lesser

degree between, Western and Eastern

Indonesia. This is because many of the

regional tectonic events have extended

similar influences across wide areas of the

Indonesian archipelago, controlling basin

architecture, fills and trapping mechanisms

for hydrocarbons. Plate tectonic models for

the region have continuously been refined

since the first model was developed for

Western Indonesia by Katili (1973). Recent

notable contributions come from Longley

(1997) who compiled and synthesized a wide

range of geological data throughout

Southeast Asia (Figure 2), and Hall (1995,

1997a, b) who presents progressively refined

computer-generated models (Figure 3). The

work of these two authors forms the basis

for the discussion of Indonesian tectonics

that follows.

Since the advent of seismic and sequence

stratigraphy (Vail et al., 1977), eustatic sea-

level fluctuations (e.g., Haq et al., 1988)

have been recognized as exerting a strong

influence on the evolution of Indonesian

sedimentary basin fills, including the types

and distributions of source, reservoir and

seal lithologies. Longley (1997) argues that

it is always possible to correlate apparent

eustatic events between basins because of

the large number of available correlation

options and the often significant inaccuracy

of geological dates. In general, however, the

geology of Asia supports the premise that

eustatic events have a major and observable

Overview of Indonesias oil and gas industry Geology176

0

5

10

15

20

25

30

35

40

45

50

55

60

65

Ma

Global eustatic curve

Major events

Overallregression

Rotation of N and Earms of Sulawesi.Northwardmovement ofBird's Head relativeto Australia

3Ma Timor andBanda arc collide

Transgression onto Sunda shelf.Eustatic and tectonic increased convergence alongSunda arc led to inversion andthen thermal sag

Slow southern oceanspreading. Subductionalong west Sundalandmargin

Slowed convergence leadsto second stage of riftingalong Sundaland margin

Slowed convergence leadsto rifting along Sundalandmargin

c21Ma South China Seaspreading endsc25Ma New Guinea passive margin collideswith arc system to North.Sorong fault forms.Emplacement ofSulawesi ophiolites

c32Ma South China Seaspreading

c43Ma Major platereorganization. India andAustralia plates combine.Subduction of Indiabeneath Eurasia ends

c50Ma India Eurasia collisioncommences

Increased convergencewith CCW rotation ofSumatra and developmentof Sumatra wrench fault.Sulawesi forms emplacement of continentalcrust along Sorong fault

Middle Miocene maximum transgression

Pale

ocen

eEo

cene

Olig

ocen

eM

ioce

nePl

ioce

neEp

och

QHol

Terti

ary

Perio

d

Low

erLo

wer

Low

erLo

wer

LU

Uppe

rUp

per

Uppe

rUp

per

Mid

dle

Mid

dle

2nd order sequenceboundaries

0+100m+200m

5Ma Luzon arc collideswith Asian plate

10Ma Australian cratoncollides with AsianPlate inversion

5.2(5.5)

10.6(10.5)

21.5(21.0)

29.5(30.0)

38.6(39.5)

51.0(49.5)

59.5(58.5)

Figure 2: Chronostratigraphic summary of major geological events in the Cenozoic (eventstaken from Longley, 1997 and Hall, 1997. Eustatic curve modified from Haq et al., 1998).

effect on stratigraphy, and does not prove or

disprove the detailed Haq et al. (1988)

eustatic curve.

The Indonesian archipelago is a jigsaw

puzzle of tectonically derived pieces,

including microplates, continental

fragments, mini-ocean basins, accretionary

prisms and island-arc systems, that have

been jostled and squeezed together and, in

some cases newly formed, as a result of the

complex interaction of three major tectonic

plates (Figure 4).

The continental Eurasian/Asian plate

(the southeast promontory of which is

termed the Sunda shield or Sundaland)

demonstrates a relative southeast motion

that is accommodated by the Great

Sumatra/Mentawai duplex, and the

Sulawesi and Philippine transform-fault

systems. The obliquely opposing, relative

northward motion of the Indo-Australian

plate is accommodated by right-lateral

movement along the Great

Sumatra/Mentawai fault systems, and by

subduction of oceanic crust in the west

and the Australian craton in the east,

along the SumatraJavaTimorAru


30MaMid Oligocene

EURASIAN PLATE

INDIAN PLATE

Proto-SouthChina Sea

AustraliaBird's Headmicrocontinent

PACIFIC PLATE

Opening ofParece Velabasin begins

Opening ofSouth China Seanorth of Macclesfield Bank

NorthPawalanExtension

driven by slab-pulland Indochina extrusion

Ophiolite approachingSulawesi west arm

Red River fault

Indochinaextruded to SE

ThreePagodassystem

50MaEnd Early Eocene

EURASIAN PLATE

NorthPalawan

Mindoro

Taiwan

Proto-SouthChina Sea

Malaysia

Sumatra

Java

SouthBorneo

Zamboanga

West Sulawesi

Oki Daitoridges

East Philippines

NORTH NEW GUINEA PLATE

Indochina

South China

INDIANAUSTRALIAN PLATE

South and East Sulawesi

PHILIPPINE SEA PLATE

PACIFIC PLATE

40MaMiddle Eocene

EURASIAN PLATE

INDIANAUSTRALIAN PLATE

Leading edge ofBird's Head microcontinent

PACIFIC PLATE

Izupeninsula

CelebesSea

WestPhilippine

Sea

West Philippine Seaspreading extendsto Celebes Sea

Subduction ofProto-SCS begins

No rotation ofPhilippine Seaplate

Arc activity at south edgeof Philippine Sea plate

? ?

??

10MaLate Miocene

EURASIAN PLATE

INDIAN PLATE

Australia

CAROLINE PLATE

PACIFIC PLATE

Subductionat Manila trench

SuluSea

Sulu arc activityends

Borneorotationcomplete

Malaya blocksrotation complete

Andaman spreading

Molucca Seadouble subductionestablished

Ayu trough spreading

N BandaSula

PhilippineSea platerotates

20MaEarly Miocene

EURASIAN PLATE

INDIAN PLATE

Australia

CAROLINE PLATE

PACIFIC PLATESpreadingin Shikoku

basinClockwise rotation

of PhilippineSea plate

Spreadingin Parece

Vela basin

Sorong faultsystem initiated

Molucca Sea formspart of Philippine Sea plate

Continentalcrust thrustbeneathSulawesi

Bird's Headmicrocontinentdismembered bySorong fault splays

Inversionin Natunabasins

Cagayan ridgeseparates from Sulu arc

Finalspreadingof SouthChina Sea

Borneorotationbegins

Figure 3: Plate tectonic reconstructions forSoutheast Asia and Indonesia region from 50 Mato 10 Ma (after Hall, 1995 and 1997).

(Sunda) trench system. This extensive

subduction system (combined with the

Great Sumatra/Mentawai transform fault

duplex) marks the southern geological

limit of Indonesia from the western tip of

Sumatra, to near the eastern boundary of

Irian Jaya. The Pacific Ocean plate

demonstrates a westerly motion that is

accommodated by slippage along the left-

lateral transform Sorong fault system, and

the trench and transform fault system of

the eastern Philippines, which together

define the northeastern geological limit of

Indonesia. There is no obvious geological

limit to northwest Indonesia, and the

political boundary separating Malaysia and

Indonesia passes through central Borneo,

across the southern part of the South China

Sea (the relatively stable Sunda shield) and

to the northwest along the Malacca Strait

that separates peninsular Malaysia from

Sumatra. Although Indonesia is tectonically

complex, convergence of the Asian plate

(Sunda shield) with the continental part

(Australian craton) of the Australian plate

ultimately defined two major geological

provinces. Western Indonesia represents

the southeast margin of the Sunda shield

and Eastern Indonesia represents the

highly fragmented and tectonized northern

margin of the Australian craton.


0 80 160 320 480m

0 160 320 640km

PHILIPPINE SEA PLATE

PACIFIC PLATE

CAROLINE PLATE

Strikeslip fault

Oceanic spreading axis

Subduction zone

Australian crust

Transitional, attenuated or sutured

Oceanic or island arc

Pre-Mesozoic continental crust

Quaternaryrecent volcano

SUNDALAND

EURASIAN PLATE

AUSTRALIAN INDIAN PLATE

AUSTRALIA CRATON

5cm/yr

7cm/yr

Sunda trench system

Mentawai fault

Java trench

Sumatra trench

Great Sumatra fault system

South China Sea

Philippines

Pacific Ocean

Palau

tren

ch

Mar

iana

tren

ch

Sorong fault West Melanesian trench

Seram trough

Aru

troug

h

Timor t

rough

Australia

Meratus suture,Late Cretaceouscollision

Three Pagodas and

Wang Chao faults

Hain

zee

Saga

ing

faul

t

Red River fault

Walanea fault

Figure 4: Simplified tectonicelements and crustal distribution forIndonesia (after Coffield et al., 1993and Nugrahanto and Noble, 1997).

Tectonic evolutionThe Cenozoic geological history of Indonesia

is divided into stages based on major

tectonic collision events:

1. Encroachment and collision of the Indian

and the Asian continental plates starting

at approximately 50 mybp and

reorganization of the Southern, Indian and

Pacific plates at about 43 mybp when

there was an end to subduction along the

Indo-Eurasian collision belt.

2. Onset of South China Sea spreading at

about 32 mybp, and collision of the

northern leading edge of the Australian

craton (New Guinea passive margin) with

the PhilippineHalmaheraNew Guinea

arc system at about 25 mybp (although

arguably this was not a regional event

according to Longley, pers. comm.).

3. Collision of the Australian craton with the

Asian plate starting at about 8 mybp and

continuing until major collision at about

3 mybp; and collision of the Luzon arc

west of the Philippines with the Asia plate

margin near Taiwan at about 5 mybp.

Stage I. >5043 mybp (middle Eocene and older)Prior to 43 mybp (middle Eocene) Java,

Sumatra, Kalimantan and western Sulawesi

were part of the southeast Sunda shield

continental promontory, with northward

motion and subduction of the Indian plate

oceanic crust beneath the southern edge of

the Sunda shield continent along the

northwestsoutheast trending Sunda

trench. This trench system extended to the

west into the Indian Ocean with an element

of right-lateral slip. In the east it connected

with the Pacific Ocean intra-oceanic-arc

system. Slowing of convergence after about

50 mybp, as the Indian subcontinent

approached the Asian plate and continental

collision was initiated, led to an initial stage

of rifting along the Sundaland margin.

Eastern Indonesia had not started to form

at this time. The Birds Head (present-day

western-most promontory) of Irian Jaya was

probably a microcontinental fragment on

the northwest edge of the Australia plate

(Hall, 1997a, b). New Guinea represented

the passive northern margin of the

Australian craton, which was moving

northward as oceanic crust was consumed

beneath the southern edge of the oceanic

Philippine Sea plate. The present-day

eastern island of Halmahera was still

thousands of kilometers to the east and part

of the Philippine Sea plate.

Stage II. 4325 mybp (middle Eocenelatest lateOligocene)

In the late middle Eocene (at about

43.5 mybp according to Longley, 1997 and

42 mybp according to Hall, 1997a, b) there

was final collision between the Indian plate

subcontinent and the Asian plate. This

slowed the rate of convergence and also

changed the angle of subduction from an

essentially northward to a more

northnortheast vector along the Sunda

trench. This was in response to a major

reorganization of the converging Southern,

Indian and Pacific plates.

Subduction of India beneath Asia stopped

and the Indian and Australian plates were

combined. The resulting relaxation of the

compressional forces at the edge of the

Sunda shield produced further northsouth

oriented rifting. Isolated rifts in a fore-arc

setting and in East Java filled with

transgressive and then open-marine

sediments, being situated on the distal

low-lying edge of the Sunda shield. Fluvio-

lacustrine sediments developed in the

northwest Java, Sumatra, Kalimantan, west

Sulawesi and Natuna Sea rifts, as the middle

Eocene sea did not extend to the west onto

the Sundaland margin (Longley, 1997).

Towards the end of this period, starting at

32 mybp and continuing through to

21 mybp, there was clockwise rotation

around a pole in the northern part of the

Gulf of Thailand associated with the

opening of the South China Sea. The West

Philippine basin, Celebes Sea and Makassar

Strait also opened as a single basin within

the Philippine Sea plate accompanied by

subduction of the South China Sea to the

northeast of Borneo (Hall, 1997a, b).

Spreading in the South China Sea, the West

Philippine Sea, the Celebes Sea and

Makassar Strait areas eventually stopped.

There was a return to more rapid plate

convergence and increased compression led

to inversion along the Sunda arc. The

isolated rift basins of East Kalimantan were

filled with deltaic and marine sediments

that were transgressed by post-rift marine

shales due to a combination of eustatic gain

and post-rift thermal sag.

Stage III. 258 mybp (latest late OligocenelateMiocene)

In the late Oligocene, at about 25 mybp, the

leading edge of the New Guinea passive

margin (Australian craton) collided with the

PhilippineHalmaheraNew Guinea arc

system. This prevented any further

subduction at this plate boundary, which

developed into a listric transform (the

Sorong fault) as the Philippine Sea plate slid

westward across the northern end of the

Indo-Australian plate. The Birds Head

microcontinental fragment within the Indo-

Australian plate was close to collision with

the margin of Sundaland near west

Sulawesi. Ophiolites were emplaced along

the eastern edge of this western Sulawesi

arm. Oceanic crust trapped between

Sulawesi and Halmahera was rotated

clockwise and subducted beneath the

eastern margin of Sulawesi.

The tectonic development of the region

was further influenced by the continued

northward motion of the Indo-Australian

plate following collision. Counter-clockwise

rotation of the entire Sunda shield

promontory including peninsular Malaysia,

Sumatra, Java and Borneo occurred. The

effective increase in rate of convergence

between the Indo-Australian plate with

respect to Sumatra stimulated magmatic

activity that weakened the upper plate and

led to right-lateral dislocation along the

Great Sumatra fault system. During

rotation, a bend and half-graben developed

in the Sunda Straits separating South

Sumatra from West Java.

In northwest Borneo a delta was

established and turbidites poured into the

proto-South China Sea. Increased

subsidence east of Borneo resulted in arc

splitting and the opening of the Sulu Sea as

a back-arc basin. Halmahera and the

Philippine plate were carried towards the

subduction zone below north Sulawesi, and

fragments of the Australian continental

crust were added to the developing

Sulawesi along the Sorong fault system.


Stage IV. 80 mybp (late MiocenePresent)

In the late-middle to late Miocene (about

8 mybp) gentle compression caused by the

collision of the Australian craton with the

Asian plate, accompanied by continuous

movement along the Great Sumatra fault

system, resulted in extensive inversion and

the formation of compressional anticlines.

Encroachment continued until 3 mybp when

the main collision event happened (Longley,

pers. comm.).

By this time Indonesia was probably

recognizable in its present form. At about

5 mybp collision of the Luzon arc with the

Asian plate near Taiwan also caused further

changes to plate motions in the region.

Along the Sorong fault zone accretion of the

Tukang Besi platform to Sulawesi locked

strands of the Sorong fault, causing new

splays to develop south of the Sula platform

and the collision of the Sula platform with

Sulawesi. Rotation of the east and north

arms of Sulawesi to their present positions

resulted in the southward subduction of the

Celebes Sea at the north Sulawesi trench.

There was also continued subduction of the

northward moving Indo-Australian plate

along the Sunda trench system, extending

from northwest Sumatra to Irian Jaya, and

also subduction north of Seram and in the

Sulu Sea.

Eustatic effectsLongley (1997) and previous authors have

observed a remarkable degree of correlation

between regional collision events and the

second-order sequence boundaries of Haq

et al. (1988). It is, however, generally

accepted that a major and progressive

late Oligocene to early Miocene

(3013 mybp) transgression occurred

throughout the Indonesian basins, with

maximum transgression at 15 mybp being

marked by regionally developed marine

shales. Similarly, middle Miocene to

Pliocene regression is also easily recognized.

These major eustatic cycles, along with

regionally developed sequence boundaries

at 29.5 mybp, 21.5 mybp, 10.5 mybp and

5.5 mybp, have had a strong influence on

the development of reservoir sands and

carbonate buildups, and also source rocks

and extensive sealing shales throughout

Indonesia. Third- and even fourth-order

eustatic events are often recognizable on a

basin-wide scale. These are widely

correlatable in both clastic sedimentary

packages, where they may result in

development of lowstand reservoirs, and in

carbonates where dissolution porosity zones

have, in some cases, developed. There are,

however, also many examples where

eustatic effects are not recognized because

of over-printing by intense tectonism that

has controlled the sedimentation in some

Indonesian basins.

The Indonesian basins andtheir petroleum systems

The complex geological history of Indonesia

has resulted in over 60 sedimentary basins

that are the subject of petroleum

exploration today. By the end of 1996,

following nearly 130 years of drilling

activity, 38 of these basins had been widely

explored, 14 were producing oil and gas, 10

had shown promise with subeconomic

discoveries and 22 (over one-third)

remained poorly explored or unexplored

(Sujanto, 1997, see Figure 1). Of the 22

basins in Western Indonesia, only two are

undrilled. In Eastern Indonesia there are 38

basins of which 20 are undrilled.

Although large areas of Indonesia,

particularly in the west, are considered to

be mature with respect to hydrocarbon

exploration, the majority of basins in the

east remain underexplored. This reflects

both the relatively sparse knowledge of the

geology of Eastern Indonesia and its

remoteness with respect to world markets.

There are logistical difficulties and high

costs associated with the exploration of

sparsely populated wilderness areas with


little or no infrastructure and exploration in

deep (>200 m) water.

The majority of explorationists, therefore,

have concentrated their efforts on the

highly productive but more mature basins of

Western Indonesia. These include the North

Sumatra, Central Sumatra (the most prolific

basin by an order of magnitude), South

Sumatra, Sunda-Asri, Northwest Java, East

Java, Barito, Kutei, Tarakan and East and

West Natuna basins. All of the most prolific

petroleum systems discovered to date are

located in Western Indonesia, with 85% of

all Indonesian recoverable oil reserves being

in the hot back-arc basins of Sumatra and

Java. Gas is more evenly distributed in fore-

land and deltaic basins and, with the recent

Tangguh gas project in western Irian Jaya,

in Eastern Indonesia.

In the east only the Salawati basin of the

Birds Head peninsula of Irian Jaya is

considered to be mature. As our knowledge

of Eastern Indonesian geology improves,

and technological and intellectual

advancements reduce the costs of

exploration in remote areas and deep water,

the exploration emphasis will move away

from the Western to the Eastern Indonesia

basins. This is already being realized. In the

1990s there were successful Mesozoic

discoveries in mountainous Seram (the

Oseil oil field); in the Bintuni basin of Irian

Jaya (the Tangguh gas project); and in deep

water of the Timor Gap zone of cooperation

(ZOC the Elang oil field and a number of

other oil, condensate and gas discoveries).

Although in a smaller league than, for

example, the Middle East, on the global scale

Indonesia is still a significant hydrocarbon

province. The Gulf area contains a blanket of

marine source facies that is extremely

prolific and mature over wide areas, with

widely developed reservoir facies, large-scale

anticlinal structures and, most importantly, a

highly effective regional salt seal.

Indonesia is extremely complicated

geologically, and source rocks, kitchens and

reservoirs are restricted in their distribution,

occurring as pods of limited areal extent

within numerous, structurally complex and

isolated basins. The more prolific petroleum

systems of Western Indonesia are products of

extrusion tectonics and widespread

Paleogene extension on the Sunda shield,

modified by later inversion. In Eastern

Indonesia the majority of petroleum systems

are pre-Tertiary. They are related to the north

Australian passive margin, which has been

affected by microplate accretion, large-scale

strike-slip faulting and collision tectonics.

The Western and Eastern Indonesian

petroleum systems together demonstrate

the extreme variability of petroleum

systems in Indonesia. Source-rock age

varies from possible Paleozoic (Eastern

Indonesia) to Pliocene (biogenic gas in

Western Indonesia). Depositional settings

include shallow- and deep-marine clastics

and carbonates, deltaic deposits including

coals, and lacustrine shales, which are the

most prolific source in Western Indonesia

and, in fact, throughout Southeast Asia.

Hydrocarbon types are also diverse,

including waxy lacustrine-sourced crudes,

light marine oils, thermogenic and biogenic

gas, asphalt deposits (e.g., Buton Island)

and even deep-marine gas.

Reservoirs are dominated by deltaic sands

and large shallow-marine Tertiary carbonate

buildups that are the main gas reservoir

types. Less common are alluvial-fan, fluvial,

shallow- and deep-marine fan sands, and

more exotic types such as fractured granite

and metamorphic basements, fractured

volcanics and, in the East Java basin, highly

porous, foraminiferal-sand contourites and

diagenetically enhanced volcaniclastic

sands. Oil and gas accumulations occur in

strike-slip, extensional, compressional fore-

arc, back-arc, passive and convergent

margin settings, in both structural and

stratigraphic traps, and may demonstrate

elements of pressure seals and hydrodynamic

effects (Howes, 1999). Geothermal gradients

range from low in cool fore-arc basins to high

in the back-arc areas, and have varied

considerably through time, influencing the

timing of expulsion and migration.


0+100m+200m

2nd order sequenceboundariesAge

mybp

Quaternary

Pliocene

Late

Late

Late

Mid

dle

Mid

dle

Early

Early

Mio

cene

Olig

ocen

eEo

cene

Pre-Tertiary basement

Eustaticcurve after

Haq et al., 1988.

5

10

15

20

25

30

35

4038.6

(39.5)

29.5

(30.0)

21.5

(21.0)

10.6(10.5)

5.2(5.5)

45

North

Alluvium Alluvium Alluvium

Kasai

Muara Enim

Air Benakat

Gumai

PendopoUpper Talang

Akar

LowerTalangAkar

Lemat

Talang Akar(Lower Zelda)

Banuwati

Talang Akar(Upper Zelda)

TAF (Gita)

Batu Raja

Gumai

Air Benakat

Parigi

Cisubuh

Cisubuh

LidahKawengan Karren

Wonocolo

Ngrayong

Rancak

KUI/UK

KUII/MK

KUIII/LoK

CD

Parigi

Pre-Parigi

Mid main

Unit II

Massive

Batu Raja(M. Cibulakan)

Upper Talang Akar(Lower Cibulakan)

Lower Talang Akar

Jati Barang

U.Cibulakan

Lahat(Kikim Tuffs)

Middle Kikim Sand

Lahat

BatuRaja

Toba Tuffs

Julurayeu

Seurula

Keutapang

M B SandUpper Baong Shale

Lower Baong ShaleLower Baong Sand

Peutu(Arun)

Belumai

Bampo

Parapat

Meucampli

Pematang

Menggala

Bekasap

Duri

Bangko

Telisa

(Binio)

Petani

Minas

(Korinci)

Siha

pas

Tampur

NW SE SW

Sumatra

CentralNE NW

South

Java

SE ONSH. OFFSNorthwest NortheastSunda Asri

Sub-basin

After Alexanders & Nellia, 1993,Fainstein, 1996,

Riadhy et al., 1998.

After Kelsch et al., 1998,Wain & Jackson, 1995.

After Rashid et al., 1998,Sitompul et al., 1992,

Tamtomo, 1997.

After Aldrich et al., 1995. After Sukamto et al., 1995,Napitupulu et al., 1997.

After Ardhana et al., 1993,PT Rocktech Sejahtera, 1994.

Tuban

Kujung

Ngi

mbang

v v v v v

v v v v

v v v

+ + +++++++++++ + + +

+ ++ + + + + +

v vv

Western Indonesian basinsThe petroliferous basins of Western

Indonesia occur mostly onshore, or else in

shallow water (30% of basins occur offshore

at depths 1000 km

from the subduction) are those of East

Kalimantan (Barito, Asem-Asem, Mahakam

and Tarakan), West Kalimantan (Melawai and

Ketunggau although there is little

information for these basins) and the Natuna

Sea (East and West Natuna basins). These

basins still demonstrate subduction control

and strong similarities to the more proximal

back-arc basins, but have been affected by

their relative proximity to more localized,

smaller-scale plate tectonic events such as

seafloor spreading in the Makassar Straits and

rifting and spreading in the South China Sea.


Figure 5: Stratigraphic summary for the major basins of Western Indonesia.

The fore-arc basinsThe fore-arc of Western Indonesia (the

Sunda trench system) extends from the

Andaman Sea northwest of Sumatra,

southeastward along the west coast of

Sumatra to the Sunda Straits. It then bends

eastward along the south coast of Java and

Bali, where it continues as the TimorAru

trench system all the way to Irian Jaya (see

Figure 4). The fore-arc basins represent the

subsiding, down-dragged leading edge of

the Sunda shield between the inner volcanic

arc and the outer-arc melange or

subduction-wedge (the emergent Mentawai

Islands in West Sumatra). The inner

volcanic arc is represented by the volcanic

mountain chain that extends the full length

of both Sumatra (Barisan Mountains) and

Java, and continues further eastwards

through the Lesser Sunda Islands (Figure

4). The fore-arc basins in places contain

over 6000 m of sedimentary fill. The

bounding volcanic arc and accretionary

wedge in the Sumatra fore-arc system are

characterized by a regional-scale, right-

lateral, duplex transform system comprising

the Great Sumatra and the Mentawai fault

zones. The accretionary wedge itself has

been studied on the Mentawai Islands of

Nias and Simeuleu (e.g., Moore and Karig,

1980; Situmorang et al., 1987; Situmorang

and Yulihanto, 1992). It consists of Eocene

and younger shallow marine sands and

shales, reefal carbonates, younger turbidites

interpreted as accreted trench fill, and

ophiolitic gabbros and ultramafic rocks

(harzburgites). Oil seeps are known from

the accretionary prism on Nias Island but do

not necessarily indicate the presence of oil

in the fore-arc basin to the east. The

accretionary wedge and fore-arc basins,

although closely related and situated next

to each other, are known to be very

different from seismic studies. A highly

thrusted, accreted wedge becomes a steep

monocline entering the fore arc, which is

more typically defined by strike-slip faults

rather than thrusts.

Fore-arc basins have traditionally been

considered poorly prospective for

hydrocarbons for three main reasons:

It was thought that source-rock facies

were unlikely to develop in these

essentially shallow, oxygenated, open-

marine basins, and limited onshore space

between coast and mountains was not

conducive to a sufficient supply of non-

marine terrestrial plant material.

Reservoir quality was assumed to be a

problem because nearby volcanic arcs

should, in theory, have supplied a

predominance of poor reservoir-quality,

volcaniclastic sediments dominated by

labile volcanic lithic fragments and

swelling smectitic clays.

Geothermal gradients in fore-arc basins

are relatively low.

Exploration wells have been drilled in five

segments of the Western Indonesian fore-

arc system. These are south of Central Java,

the Southwest Java basin, the Bengkulu

basin (southwest Sumatra fore-arc), the

Mentawai basin (central Sumatra fore-arc)

and the Sibolga basin (west of Nias in the

northwest Sumatra fore-arc). There is little

available information regarding Central Java

fore-arc exploration, but limited material

has been published on Sumatra and

Southwest Java. This information in some

ways fuels optimism for the existence of

economic petroleum reserves in the

Western Indonesian fore-arc.


Alluvial Mahakam Bunyu

Tarakan

Domaring

Tabul

MeliatMeliatSS

Latih

NaintupoTaballar

Tempilan

Mesaloi

Gabus SSGabus

Belut

Barat Shale Barat

Udang

Arang SS

Upper Arang

Upper Arang

Lower Arang

Terumbu

MudaMuda

Seilok

Sujau Mang Kabua

Sembakung

Danau

Kampung Baru

Balikpapan

Landasan

PuluBalang

Lamaku

Bebulu

Marah

Kedango

BeriunKihamHaloq

Mangkupa

Pamalusan

Dahor

U. Warukin

Middle Warukin

L. Warukin

Upper Berai

Middle Berai

Upper Tanjung

Lower Berai

Kalimantan Natuna

West EastBarito

West EastKutai

West EastTarakan

South NorthEast West

After Satyana, 1995,Satyana & Silitonga, 1994,

Heriyanto et al., 1996.

After Courntey et al., 1991,Kadar et al., 1996.

After Courtney et al., 1991,Lentini & Darman, 1996.

After Fainstein &Meyer, 1998.

After Fainstein & Meyer, 1998,Michael & Adrian, 1996,

Phillips et al., 1997.

L.Tanjung

Antan

Ujoh

Bilang

Sembulu

(

(

BatuHidup

Lst.

+ + ++ + ++

vv v v v vv

Cratonic

Coal

Shales and claystones

Volcanics/volcaniclasticsReefal and platform carbonates (and dolomites)Sandstones

Conglomerates

Argillaceous

Volcanic input

Gas

Oil and gas

Oil

v vvv

East Natuna

West Natuna

NorthSumatra

CentralSumatra

SouthSumatra

SundaNorth WestJava

North EastJava

Barito

Kutai

Tarakan

0 500km

Bengkulu basin (including theMentawai and Sibolga basins)The Bengkulu basin is the most widely

explored fore-arc basin in Indonesia. In the

1970s a total of 10 wells were drilled by

Amin Oil, Jenny Oil and Marathon Oil,

targeting biogenic gas in large Miocene

carbonate buildups a similar play to those

drilled by Unocal at about the same time to

the north in the Sibolga basin. Biogenic gas

in carbonates was also targeted by the 1972

Jenny Oil Mentawai A-1 and Mentawai C-1

exploration wells in the southern sector of

the central Sumatra fore-arc, the Mentawai

basin. These wells contained biogenic

methane shows (Yulihanto and Wiyanto,

1999) but all the Bengulu basin carbonate

targets proved to be water-filled. Oil shows,

however, were encountered in the Jenny Oil

well Bengkulu 1 (Howles, 1986). This well is

also close to an onshore oil seep, and good

oil shows were also described in the Arwana

1 well drilled by Fina in 1992 that also

penetrated good marine source rocks. Hall

et al. (1993) notes that in Arwana 1

OligoceneMiocene shales are within the oil

window and the geothermal gradient is

between 4.5 and 5C/100 m, which is

significantly higher than would normally be

expected in this tectonic setting. The origin

of the Bengkulu basin is not strictly fore-

arc, however, which may explain these

unexpected but favorable findings.

Stage I. Syn-rift (Eocenelate Oligocene)An early stage of Paleogene rifting is

recognized from onshore fieldwork and

offshore seismic and gravity surveys

(Howles, 1986; Mulhadiono and Asikin,

1989; Hall et al., 1993; Yulihanto et al.,

1995). It is feasible that these grabens,

which strike northeastsouthwest,

represent an extension of the early South

Sumatra basin rift system prior to the

development of the more recent volcanic

arc. Mulhadiono and Asikin (1989) note a

similar orientation to the South Sumatra

basin Jambi-Bengkalis graben, a pull-apart

basin related to westnorthwesteastsoutheast,

right-lateral movement along the Lematang

fault trend. Howles (1986) suggest that these

two graben systems are offset by

approximately 100 km along the Great

Sumatra fault system.

It has been speculated that the Bengkulu

basin may originally have been in a back-arc

setting and that a Paleogene graben fill could

include the same prolific lacustrine source

rocks that occur in the Central and South

Sumatra basins and also possible fluvio-

lacustrine reservoirs. Such source and

reservoir facies have not been penetrated in

the Bengkulu basin wells. The lower 60 m of

sediments penetrated in the Arwana 1 well

are late Eocene and comprise shallow marine

volcaniclastics and shales (Hall et al., 1993).

Stage II. Syn-rift (late Oligoceneearly Miocene) A second stage of rifting took place in the

late Oligocene to early Miocene and marks a

change from orthogonal extension to

oblique northwestsoutheast slip.

Northsouth oriented pull-apart graben sub-

basins developed and are also recognized in

the Bose and Sipora grabens of the

Mentawai basin, and the Pini and Singkel

grabens in the Sibolga basin to the north

(Figure 6). Although it is thought that

movement on the Great Sumatra fault did

not start until middle Miocene times, it is

likely that the Sumatra fore-arc has

experienced transtensional stresses as a

result of continuous oblique subduction

since the initial development of the Sunda

arc in the pre-Tertiary.

Fieldwork in the outer-arc ridge

(Mentawai Islands) and regional seismic

demonstrate that the marine Oligocene

graben fill in the Mentawai basin has source

potential. Basin modeling suggests that

these sediments may have entered the oil

window as early as the middle Miocene

(Yulihanto and Wiyanto, 1999). These


Figure 6: Simplified map of structural elements and hydrocarbon occurrencein the Sumatra fore arc (modified from Yulihanto et al., 1995).

0 100

5cm/year

200km

North Sumatrabasin

Central Sumatrabasin

Sibolga basin

Simeulue

Nias

Siberut

South Sumatrabasin

Pinigraben

Singapore

Singkelgraben

Sundatrench

Sumatra forearc basin

Sumatra

fault zone

Pagar Jatigraben

Bengkulubasin

Mentawai fault zone

12 3 4

56

Keduranggraben

Arwana #1(Fina)

Mentawai A#1(Jenny)

Mentawai C#1(Jenny)

Pagar Jatigraben

Bengkulu X#2(Jenny)

Bengkulu X#1(Jenny)

Bengkulu A#2x(Amin Oil)

Bengkulu A#1x(Amin Oil)

Malaysia

1. Palembak 1 Union Oil2. Singkel 1 Union Oil3. Telaga 1 Union Oil4. Lakota 1 Union Oil5. Suma 1 Union Oil6. IbuSuma 1 Caltex

WellsOil seeps

Volcanoes

Volcanics

authors also recognize an early to middle

Miocene potential marine source.

Shallow marine conditions continued

through the early Miocene in the Bengkulu

basin. In Arwana 1, lower Miocene Batu

Raja formation-equivalent dolomites (see

Figure 5 South Sumatra, Sunda-Asri and

Northwest Java basin stratigraphies) are

overlain by lower Miocene clays and sands

of volcaniclastic origin. The entire

OligoceneMiocene section contains oil

shows. Mulhadiono and Asikin (1989)

describe the upper Oligocenelower

Miocene graben fill as sandstones,

conglomerates and a few limestones, and

Yulihanto et al. (1995) note a close

stratigraphic similarity to the South

Sumatra basin. Early Miocene buildups are

considered a potential reservoir target in

the Mentawai basin (Yulihanto and Wiyanto,

1999), although earlier drilled carbonate

buildups in the Bengkulu and Sibolga basins

are of middle Miocene age.

Stage III. Post-rift (middle MiocenePliocene)The middle to late Miocene saw the onset of

open-marine deposition within a unified fore-

arc, and sediments comprise marine shales,

silts and limestones, including some major

buildups equivalent to the Parigi formation (see

Figure 5). Such large-scale carbonate buildups

have been targeted as potential biogenic gas

reservoirs in both the Bengkulu and the Sibolga

basins. The Bengkulu basin wells were all dry

but Union Oils Suma 1 and Singkel 1 wells and,

the more recent Caltex Ibu Suma 1 well

(Figure 7), encountered subeconomic

quantities of biogenic gas (e.g. Dobson et al.,

1998). As may be expected with such large

carbonate buildups, top seal shales were

probably not deposited until after much of the

gas had been generated and escaped. Biogenic

gas was not encountered in the Bengkulu

wells possibly because of the higher


2km

Inline 1515L-6036

Ibusuma prospect

Back lagoonal fill

Back reef stormand talus deposits

Wave-resistantreef facies

200

400

600

800

1000120014001600180020002200240026002800300032003400

0

Figure 7: Seismic section and interpretation of the middle Miocene Ibu Suma buildup, Sibolga basin, north Sumatra fore-arc (Dobson et al., 1998).

SumatraSunda basin

Serib

u plat

form

Tangeranghigh

West Java

WestMalimping

low

Honjehigh

UjungKulonhigh

UjungKulonlow

Pull-aparthalf-graben

UjungKulon 1a

Bayahhigh

Bayah

Ciletuhhigh

DDH-2

DDH-1Fig.9a

Fig.9b

Sund

a stra

it

Malimping block

Krakatau

0 50km

Cimand

iri fault

(>4.5C/100 m) geothermal gradient. In the

Mentawai basin Yulihanto and Wiyanto (1999)

consider middle Miocene lowstand fans to be

potential reservoirs.

Yulihanto et al. (1995) recognized the

rejuvenation of pre-existing tensional faults

in the Bengkulu basin during this period,

with accompanying deposition of shallow

marine and lagoonal sands and clays, and

coaly intercalations of potential source

rock (Lemau formation) occurring in

outcrop. During the late Miocene to

Pliocene, basin subsidence continued with

deposition of littoral sands of the

Simpangaur formation. In the Mentawai

basin southerly prograding deltaics may

provide reservoir opportunities (Yulihanto

and Wiyanto, 1999).

Stage IV. Uplift(PliocenePleistocene)Starting in the early Pliocene and

continuing through to the Present-day,

basin uplift and volcanism have been

prevalent accompanying the development of

the Barisan Mountain chain.

Southwest Java basinThere is very little published on the

Southwest Java basin and it was only lightly

explored by Amoco in the 1970s (Ujung

Kulon 1) and very recently by British Gas

(Malimping 1). Both wells were plugged and

abandoned as dry holes.

According to Keetley et al. (1997) the

basin comprises a series of roughly

northsouth-trending half-grabens. These

developed during Eocene to Oligocene

times and extend northward into the Sunda

Strait (Figure 8), with beds thickening to

the east in one of the half-grabens. Coastal

outcrops of middle to late Eocene Bayah

formation thick-deltaic sands (Figure 9a)

and a coaly potential source facies occur in

the Bayah area in the eastern part of the

basin. Schiller et al. (1991) describe the

thick section of middle to late Eocene

Ciletuh formation, which crops-out on the

eastern extremity of the basin, as a sand-

dominated turbidite-fan system (Figure 9b).

They speculate that in Eocene times the

left-lateral Cimandiri fault represented the

extreme limit of the Sunda shield and, that

the Bayah formation deltaic system supplied

sediment to the deeper-marine setting on

the downthrown side of the fault. The

Bayah formation and the Ciletuh formation

arenites (with some leached feldspar)

demonstrate excellent reservoir quality but,

the upper section of the Ciletuh sands

displays a change in current direction and a

new volcanic provenance with a reduction

in reservoir quality.

Keetley et al. (1997) suggest that early

Miocene post-rift sag resulted in subsidence

of the offshore area and vitrinite reflectance

results of Eocene sediments adjacent to the

Honje high indicates heating to 180C and

then uplift in the early Miocene from about


Figure 9: Potential reservoir facies in the Southwest Java basin. Eocene Bayah formation cross-bedded, fluvio-deltaic channelsands exposed on the Bayah high (a). Eocene Ciletuh formation deep marine fan sands exposed on the Ciletuh high (b).

(a) (b)

Figure 8: Simplifiedmap of structuralelements in theSouthwest Javabasin (after Keetleyet al., 1997).

4 km depth. The younger middle Miocene

sediments on the Honje high consequently

indicate negligible heating.

A middle to late Miocene second rifting

phase is also proposed by Keetley et al.

(1997). Apatite fission track analyses of

Eocene and Miocene sands in the eastern

part of the Southwest Java basin

(Soenandar, 1997), indicate a maximum

burial temperature of only 70 to 95C.

Significant cooling occurred in the late

Miocene to early Pliocene, with an

indication of over 3 km of inversion in the

Ciletuh area east of the Cimandiri fault,

caused by deformation of an accretionary

complex when subduction was blocked by

an old magmatic arc. Soenandar (1997)

recognizes a rapid increase in geothermal

gradient in the PliocenePleistocene, which

he also recognizes in the Sunda, Asri and

Northwest Java basins.

Fore-arc basins of Western Indonesia are

poorly understood but their hydrocarbon

potential is considered to be moderate to

high. It would appear that the Bengkulu and

Southwest Java basins experienced a

history similar to that of the back-arc basins

of Western Indonesia. Rifting was initiated

in the Paleogene, structural modification

occurred in the Miocene, and inversion and

raised heat flow (the main maturation and

structuring event in the back-arc basins) in

PliocenePleistocene times. The Bengkulu

basin demonstrates mature source potential

for oil in Arwana 1, sufficient heat flow for

oil generation, and convincing oil shows in

two wells. There is also potential for the

development of early rift-fill Eocene

lacustrine source rocks and associated

reservoirs if the similarities between the

Bengkulu basin and the South Sumatra

basin are considered.

Although not of lacustrine affinity, the

Bayah formations deltaic deposits in the

Southwest Java basin provide evidence for

the development of reservoir and source

facies in the syn-rift stage of fore-arc

development. Turbidite fan sands in the

Southwest Java basin also demonstrate

excellent reservoir potential.

There is less known about the Sibolga

basin, but the presence of biogenic gas and

a low geothermal gradient still support the

tested biogenic gas play. Thick Miocene

carbonates are, however, considered too

problematical with regard to sealing.

Interbedded sand and shale units provide a

more prospective biogenic gas play

alternative, although small footprint and

focusing may limit their potential.

The back-arc basinsThere are 17 Tertiary back-arc basins (and

inter-basins) in Western Indonesia and the

majority are considered submature or

mature with respect to hydrocarbon

exploration. Basins considered to be

underexplored (but probably of low

prospectivity) include the Billitong basin in

the Java Sea and the Pembuang, Asem-

Asem-Pater Noster, Muriah, Melawai and

Ketunggau basins of Kalimantan. Of all the

back-arc basins only the Pembuang basin in

southernmost Kalimantan (see Figure 1)

remains undrilled.

These back-arc basins are spread across

the southeast promontory of ancient

Sundaland and contain more than 85% of

Indonesias hydrocarbon reserves. They

demonstrate similar tectonic controls on

their evolution and their fills reveal similar,

cyclic patterns of sedimentation due to

transgression and regression throughout the

Cenozoic a feature common to the entire

Sunda shelf of Southeast Asia.

Lacustrine shales and coals are abundant

in the Eocene and Oligocene syn-rift

sequences of Southeast Asia and are

demonstrably important source rocks (e.g.

Sladen 1997). Syn-rift lacustrine shales are

often assumed to be the major source of oil

in Western Indonesia back-arc basins. In

terms of billions of barrels of oil generated,

this is true because of the extremely prolific

nature of these source rocks. The Central

Sumatra basin contains the vast majority of

Indonesias oil reserves sourced almost

exclusively from this facies, the Minas and

Duri oil fields alone accounting for

15 BBOIP. Robinson (1987) developed the

first comprehensive source rock and oil-

type classification and distribution for

Indonesias petroleum basins and this has

since been refined by Ten Haven and

Schiefelbein (1995). These works indicate a

range of important organic source facies for

the Western Indonesia basins (Figure 10)

including marine, terrigenous (fluvio-deltaic

of Robinson, 1987) and lacustrine.

The major reservoirs in the Indonesian

back-arc basins are Miocene transgressive

and regressive fluvio-deltaic and shallow-

marine sands with trapping by structural

closure and in pinch-outs, and carbonate

buildups. Deeper marine sand-dominated

depositional systems are, however,

becoming a focus for the industry. The main

phase of inversion and structural

development took place in the Pliocene.

Back-arc basins are also known to be areas

of high heat flow and the Central Sumatra

basin demonstrates the highest heat flow of

any basin in Southeast Asia (Thamrin,

1987). The main phase of hydrocarbon

expulsion and migration occurred during

the PliocenePleistocene inversion event.


LegendMarine (Cenozoic)

Marine (Mesozoic)

Lacustrine (Cenozoic)

Terrigenous (Cenozoic)

Figure 10: Oil sourcecharacteristics forIndonesiaspetroleum systems(Ten Haven andSchiefelbein, 1995).

North Sumatra basinThe North Sumatra basin is extremely large

and extends from just north of Medan in

North Sumatra, northward for several

hundred kilometers into the Andaman Sea

and across the ThailandIndonesia border.

The Indonesian sector of the basin is

bordered to the west by the Barisan Mountain

thrust system and to the east by the stable

Malacca platform (Figure 11). Only about

20% of the total basin area is onshore, and in

the north, towards Thailand, water depths are

over 1000 m in the basinal deeps. The basin is

notable for the first commercial oil field in

Indonesia the Telaga Said field discovered

in 1885 and the giant Arun gas field. This

was, with about 14 TcfG and 700 MBC

(million barrels condensate), the largest gas

field in Southeast Asia until it was superseded

by the supergiant Natuna Alpha gas field.

Stage I. Early Syn-rift(Eocenelate Oligocene)Direct structural evidence to support

Eocene rifting is not recognized in North

Sumatra, but the presence of late Eocene

clastics (Meucampli formation) and marine

carbonates (Tampur formation) suggest that

an Eocene basin did exist. This is further

supported by quartzites drilled offshore from

North Aceh which are assigned a middle to

late Eocene age by Tsukada et al. (1996).

Stage II. Late Syn-rift(late Oligoceneearly Miocene)In the late Oligocene a second stage of

rifting was characterized by a northsouth

trending series of grabens and half-grabens,

accompanied by structurally controlled

deposition of coarse-grained clastic, alluvial

and fluvial sandstones of the Parapat

formation. Kirby et al. (1994) have

suggested the existence of a lacustrine

source facies in these rift basins. This is not

supported by geochemical work (Robinson,

1987; Kjellgren and Sugiharto, 1989;

Subroto et al., 1992; Fuse et al., 1996; Ten

Haven and Schiefelbein, 1995), which

supports a mainly marine hydrocarbon

source. Parapat formation sands were

transgressed by latest Oligocene bathyal

lower Bampo formation shale, often

considered to be the main source for Peutu

formation reservoired Arun and nearby gas

fields, although Bampo shales at outcrop

and in the few subsurface penetrations are

poor in quality (Caughey, pers. comm.).

Caughey and Wahyudi (1993) consider the

thicker and richer subjacent Baong

formation shales to be a more likely source,


Sumatran fault systemSumatra

BarisanM

ountainthrust front

Batumandi

Wampu

NSO

Kambuna

Glag

ah lo

w

Pusu

ng h

ighP

akol

low

Yang

Bes

ar h

igh

Glagah-1

Gebang

Rantau

KualaSimpang

Darat

Pako

l hor

st

Asahan

arch

NSBJ-1

NSBA-1

NSBC-1

Duyung 1

Julu RayeuSouth

LhoSukon

Arun

Salamangadeep

Centralridge

E1 ridge

Topazdeep

NWsub-basin

Thailand

Rano

ng ri

dge

Jau r

idge

Indonesia

Malaysia

Indonesia

Thailand

Malaysia

Pase

AlursiwahPeulalu

KualaLangsa

Lho Sukon deep

Jawa east deep

Arun high

Malaccaplatform

Peusangan high

EAO

Ridg

e

Mer

gui r

idge

Rano

ngtr

ough

TAMIANG

DEEP

TAMPUR

PLATFORM

Figure 12: 3D seismic profile across a South Lho Sukon Peutu limestonepatch-reef, onshore North Sumatra basin. The middle horizon on the reefcrest is the base of a collapsed cave zone (Sunaryo et al., 1998).

SW

1.7

2.0

Two-

way

tim

e, s

ec

2.4

0 1 2km

NESLS A-3 SLS A-11 ST2

Figure 11: Generalized physiography and productive hydrocarbon discoveriesof the North Sumatra basin (modified from Andreason et al., 1977, Fuse etal., 1996 and Kjellgren and Sugiharto, 1989).

particularly as a pressure gradient from the

highly overpressured Baong into the

normally pressured Peutu is an ideal

source-reservoir arrangement commonly

associated with giant fields.

Stage III. Uplift and post-rift sag(early Miocenemiddle Miocene)Uplift occurred at the Oligocene-Miocene

boundary with erosion of the Bampo

shales, followed by thin basal transgressive

sands. This was succeeded by the deep

marine Belumai shales, which may be a

secondary source for gas in the Arun field.

In the western part of the basin the

Belumai shales are age equivalent to large

early Miocene Peutu formation carbonate

buildups that grew on the northsouth

trending-basement horsts (e.g., Arun,

Pase, South Lho Sukon, Alursiwah, and

Kuala Langsa gas fields Caughey and

Wahyudi, 1993; Sunaryo et al., 1998;

Barliana et al., 1999) and, to the east on

the edge of the Malacca platform, are

equivalent to Belumai formation

carbonates (e.g., NSB gas field). Peutu and

Belumai formation carbonates represent

the main play type in the North Sumatra

basin and the Peutu is volumetrically the

most important reservoir facies in the

basin. Porosity was enhanced during latest


Figure 13: Log offractured Peutulimestone reservoir inthe Pase A Field, wellPase A6, onshore NorthSumatra basin.Fractures are definedusing the DSI* DipoleShear Sonic Imagerand FMI* FullboreFormation MicroImagertools (Musgrove andSunaryo, 1998).

Gamma ray

Quartz

ELAN

Deg

Deviation

Volume

DNS T

SWF1 .FIL . Int

DSIwaveform

(us) 204400Deg

Conductive fractureTrue dip

Fractureorientation

FMIimage

Conductive fracture(sinusoid)

Orientation north

900Ener

8450

8500

8550

8600

8650

8700

(dB/m)-15 0

(V/V)

0

0

50

1Hole shape

Peutu limestone

Belumai formation

Bruksah formation

Meta formation

Clay 1

Bound water Fractureenergy

early Miocene uplift and extensive karst

systems have been identified by 3D seismic

surveys (Figure 12). Belumai buildups are

abundant and clearly visible on seismic

shot over the Malacca platform. The

buildups are, however, generally small

(significantly less than the 300500 m of

relief developed on subsiding blocks at

Arun, Alur Siwah and Kuala Langsa) and

the overlying Baong is much sandier on the

shelf and thief zones limit fill-up of the

buildups (Caughey, pers. comm.).

Younger Baong shales most probably

source gas on the Malacca platform to the

east, and oil in the string of fields that

parallel the Barisan thrust front on the

Tampur platform (see Figure 11).

Stage IV. Episodic uplift(latemiddle and latest Miocene)

The remainder of the Miocene was

characterized by yo-yo tectonics.

Latestmiddle to late Miocene encroachment

of the Australian craton and the Asian plate

resulted in activation of the Great Sumatra

fault and compressional uplift of the Barisan

Mountains with a change in clastic

provenance. Sediment supply switched from

an eastern Sunda shield source to a more

southern Barisan source. Compression

resulted in pressure solution and cementation

of Peutu carbonates near the Barisan thrust

front, but also created fracture porosity at

these locations (e.g., the Pase gas field see

Figure 13). Lower Baong formation sands

were rapidly transgressed by lower Baong

marine shales that represent another gas-

prone source facies and an extensive seal

over Peutu carbonate and lower Baong sand

reservoirs. The Baong shales possibly

matured in the late MiocenePliocene and

sourced both oil and gas on the Tampur

platform. In the middle Miocene, regressive

middle Baong sands were transgressed by

fine-marine clastics, the upper Baong shales.

Stage V. Uplift(latest MiocenePleistocene)Increased compression and major uplift in

the latest Miocene and through the

Pliocene produced the coarse clastic

Keutapang, Seurula and Julu Rayeu

formations that, along with older Baong

formation sandstones, represent the oil

reservoirs on the Tampur platform. This

compressional episode was also the main

structural event producing thrusts, flower

structures, shale diapirs and a series of

northnorthwest southsoutheast folds

above the now reactivated northsouth-

oriented, strike-slip basement faults. Late

stage faulting also created vertical

migration pathways to supply the younger

sand reservoirs.

Although the onshore sector of the

North Sumatra basin has been extensively

explored, it is possible that moderate-sized

and maybe even large, early Miocene, gas-

filled Peutu carbonate buildups sealed by

Baong shales remain. These large

buildups, however, appear to have an

associated high carbon dioxide risk

(Reaves and Sulaeman, 1994) as

illustrated by the potential giant Kuala

Langsa gas field (Caughey and Wahyudi,

1993). Smaller-scale, Peutu age-

equivalent, Belumai buildups represent a

potentially less rewarding play on the

Malacca shelf. Stratigraphic plays for the

Baong and Keutapang reservoirs have not

been made but the risk is high.

New or underdeveloped play concepts

could include lowstand turbidite-fan systems

associated with middle Miocene lowstand

(Tsukada et al., 1996; Nuraini et al., 1999),

and latest Oligocene Bampo fan systems

recognized elsewhere in the basin. Syn-rift

Parapat formation alluvial and fluvial sands

could represent an attractive reservoir target

in graben deeps where they are proximal to a

generating Bampo source. Lack of seal,

however, may be an issue. The Eocene

Tampur formation carbonates have also been

recognized as having reservoir potential and

have already tested gas beneath early Miocene

Peutu reservoirs in Alur Siwah, Peulala and on

the Malacca platform (Ryacudu and

Sjahbuddin, 1994).

The relatively underexplored northern

deepwater (>1000 m) sector of the basin

merits further investigation as deepwater

drilling technology improves.

Central Sumatra basinThe Central Sumatra basin is the most

prolific oil basin in Southeast Asia, producing

approximately 750,000 BOPD, roughly half of

Indonesias production. Sujanto (1997)

provides reserves estimates for the basin of

13 BBOE ultimately recoverable, of which

95% is oil, and 2.5 BBO remain to be

recovered. In terms of both petroleum

systems and logistics, this basin has been

relatively simple to explore. It extends over

500 km in a northwestsoutheast direction

and, at its widest point, measures about

400 km between the Barisan Mountain front

and the Malacca shelf.

In contrast to the North Sumatra basin,

only 20% of the Central Sumatra basin is

offshore and water depth is generally less

than 200 m. The basin is considered to be

mature with respect to hydrocarbon

exploration and, with a simple and

essentially single petroleum system

operating, new ideas are required if further

large fields are to be discovered and the

trend of declining production is to be halted.

The basin demonstrates dominant

conjugate northwest-trending thrust faults

and northsouth-trending, right-lateral

strike-slip faults (Figure 14) which follow


0 400 800km

Malacca Strait

Malaysia

Kotabatak

Minas

Duri

Zamrud

Coastalplainsblock

Berukhigh

Lirik trend

Bengkalis trough

Kulin

Petani

Bangko

Libo

Balam trough

Central deep

Paleogenedepocenters

Oil field

Gas field

Sumatra

Jakarta

Java

Central Sumatra Basin

Figure 14: Paleogene depocenters, generalized structure and oilfielddistribution for the Central Sumatra basin (Praptono et al., 1991).

older basement fractures. The strike-slip

faults often sole-out into the thrusts and,

with right and left doglegs, have produced

pull-apart and pop-up basins (Figure 15),

respectively. These can be the sites of large

oil accumulations.

Large northwestsoutheast trending

anticlines (e.g., the Kempas-Beruk uplift and

the Sembilan uplift Figure 15) reflect

ancient basement arches. At the surface,

locally occurring northeastsouthwest-

oriented fracture swarms represent Riedel

shears that are associated with the

northwestsoutheast-oriented, right-lateral

Great Sumatra fault system.

Oil is concentrated in two principal areas. In

the west the MinasDuriBangko trend

parallels the central deep and Balam trough in

the center of the basin. In the east the

Bengkalis trough hosts the coastal plains and

shallow offshore oil fields. These are grouped

on the Beruk high, and along the southernmost

Lirik trend. In the far north of the basin there is

reduced seal capacity and there are no oil

fields. This is due to coarsening of clastics near

the paleo-sediment source.

Stage I. Syn-rift(middle Eocenelate Oligocene)Rifting was initiated during middle to late

Eocene collision between the Indian and

Asian plates, and deep, northsouth- and

northwestsoutheast-oriented graben

developed, following pre-existing Mesozoic

shear lineaments (e.g., the Tapung half-

graben Soeryowibowo et al., 1999). These

grabens filled with Tertiary sediments

through the late Oligocene.

Initially the Pematang group clastics were

deposited in isolated grabens (e.g., Central

deep, Balam trough, Bengkalis trough).

Graben margin coarse fluvial and alluvial

clastics are secondary reservoir targets.

These pass laterally into a shallow, lake-

margin and coaly facies, a secondary source

rock. The prolific, deep, lacustrine Brown

Shale formation algal-rich laminites of the

graben center are thought to have been the

source of almost all the oil in the Central

Sumatra basin (Williams et al., 1985). The

kerogen assemblage of this source facies is

dominated by the highly oil-prone,

freshwater algae (Figure 16) Botryococcus,

which is responsible for the high-wax


BengkalisIsland

PadangIsland

Melibur

Lalang

GatamSabak

Pedada

Benua

Butun

Nilam

Zamrud

Idris

Bungsu

Beruk

UpliftOil field

0 25km

Pop-upPull-apart

BerukNE

D

D

U

U

Pusaka

Dusun

Hudbay

Caltex

Coastalplainsblock

Otak fold faultKempasBeruk uplift

Sembilan upliftSiak Kecil syncline

Bengkalisdepression

MetasKutupfault

Mengkapen

Figure 15: Fielddistribution alongregional,northsouthtrending dextraltranscurrent faultsin the coastal plainsblock of CentralSumatra (Heidrickand Aulia, 1993).

AA

FWA

A

A

Figure 16: Kerogen assemblage dominated by fluorescent amorphinite (A) anddegraded, freshwater Botryococcus algae (FWA) in the Brown Shale formation,Central Sumatra basin (photo courtesy of S. Noon).

crudes of the Central Sumatra basin and

Cenozoic-sourced, waxy, lacustrine crudes

that are so common elsewhere in South

Asia. The Brown Shale formation also acts

as an internal seal for the limited Pematang

group reservoirs. Although it is accepted

that the Brown Shale unit is essentially the

only source rock in the Central Sumatra

basin, Schiefelbein and Cameron (1997)

note a minor contribution from type III,

fluvio-deltaic organic matter.

Stage II. Uplift and Sag(late Oligocenemiddle Miocene)Middle to late Oligocene arc collisions

(Longley, 1997) caused mild inversion and a

major erosional hiatus at 25.5 mybp (e.g.,

Soeryowibowo, 1999). This is recognized as

a basin-wide event separating the Pematang

group syn-rift fill from the overlying Sihapas

group. Early to middle Miocene sag and

eustatic gain resulted in deposition of the

strongly transgressive Sihapas group,

representing a large tide-dominated delta

system that prograded from the north,

supplying the main reservoir sands from the

granitic Malacca platform.

The Sihapas group opens with the

superior reservoir quality Menggala

formation (Figure 17), consisting of fluvial

channel sands deposited in structural lows

and incised valleys on the truncated surface

of the Pematang group. Sediments become

progressively more marine and reservoir

quality tends to decrease as fluvial sands

are replaced by estuarine, shore-face and,

finally shaly shallow-marine sands of the

Telisa formation during the maximum

middle Miocene trangression. Reservoir

packages are demonstrably associated with

third- and fourth-order (including possibly

tectonically controlled) lowstand events on

a field to basin-wide scale, but also include

transgressive shallow-marine sheet sands.

The Sihapas contains highstand intra-

formational sealing shales, and the shale

dominated Telisa formation also acts as a

regional seal. Interestingly, the fine-grained

Sihapas group clastics were considered to

be the main source rock in the Central

Sumatra basin until 1985 when Williams et

al. identified the Pematang Brown Shale

source. Even though Sihapas deposition is

considered to have occurred during a period

of relative quiescence, northsouth right-

lateral faulting was active throughout and

produced early Miocene pull-apart basins.


M

M

M

M

M

K

KI

I

I

I

O

O

O

O

I

F

F

M

Figure 17: Photomicrograph of the lower Sihapas (Menggala) reservoir sandstone, Kurau field, CentralSumatra basin showing partly leached feldspars (F), quartz overgrowth cement (O), authigenic kaolinite (K) andexcellent primary intergranular (I) and secondary moldic (M) porosity. (Photomicrographs from Murphy, 1993.

Stage III. Uplift(middlelate Miocene)

Westerly sourced, volcanic sediments

deposited after 16 mybp are associated with

the development of the Barisan arc and

movement along the Great Sumatra fault.

This reflects increased plate convergence

and vectoral change (counter-clockwise

rotation in Western Indonesia) at the Sunda

trench. Compression led to deposition of the

regressive, fine-grained Petani formation

that locally contains reservoir facies.

Stage IV. Uplift(late MiocenePleistocene)During the late Miocene, compressional

forces intensified as subduction rates and

orientation changed again due to

encroachment of the Australian craton and

the Asian plate. Intense structural

development continued through the

Pliocene. Heat flow increased rapidly in the

PliocenePleistocene, possibly reflecting

the emplacement of shallow intrusives

(Eubank and Makki, 1981). Maturation of

the syn-rift Brown Shale oil source took

place and migration followed Eocene syn-

rift sand tracts, graben-bounding faults and

Sihapas sands.

In terms of exploration, the Central

Sumatra basin is considered to be mature.

Recent efforts by Caltex, the main

production sharing contract operator in the

basin, have concentrated on tertiary

recovery projects. These include large-scale

waterflood of the Minas and other oil fields

and steamflood of the Duri oil field, the

largest operation of its kind in the world

(e.g. Sulistyo et al., 1998). Recent

technological advancements in sequence

stratigraphy and 3D-seismic studies are

being applied in the hope of identifying

bypassed oil. Exploration has not ceased,

however, and smaller-scale Pematang and

fault-controlled traps are still being targeted

to help offset the declining production from

the basin.

Pematang group gas accumulations are

being sought to fuel the Duri steamflood,

since nearly one-third of produced Duri oil

is used for steam generation. Presently the

nearest gas is in the South Sumatra basin,

supplied by Gulf Oil in a gas-for-oil

exchange deal.

It would appear that there are few new

play types in the Central Sumatra basin.

Exploration of the Pematang groups coarse

clastics is considered to hold promise

although oil potential is limited by poor

reservoir quality. There is minor production

from fractured basement in the Beruk

Northeast field but this is not considered to

hold sufficient reserves to be of interest as a

primary target.

South Sumatra basinThe South Sumatra basin lies almost entirely

onshore and extends about 450 km from

northwest to southeast. It is separated from

the Central Sumatra basin by the Tiga Puluh

Mountains in the north, and from the basins

of the Sunda Strait by the Lampung high in

the south. At its widest point it extends

approximately 250 km from the Barisan

thrust front to the Malacca Strait in the

East, where Tertiary cover passively onlaps

basement. It comprises three main sub-

basins (Figure 18) the Jambi graben, the

central Palembang graben, and the South

Palembang or Lematang graben. The Jambi

and Lematang grabens are highly productive

with the former producing mainly oil and

the latter, being deeper and hotter, being

richer in gas.


Lampunggraben

Lampunghigh

Lematang/South Palembang graben

(sub-basin)

Palembang/North Palembang graben

(sub-basin)

Jambi graben(sub-basin)

Dun BelasMountains

Ipuhgraben

Pagar Jatigraben

Keduranggraben

50 100km0

Muaraduagraben

Kikimhigh

Central Palembang

sub-basin

Bangk

o high

Ketalin

g high

Lematang fault

Sumatra fault zone

Approximate extent of SouthSum

atrabasin

Figure 18:Generalizedstructural pattern ofthe SouthernSumatra region (afterYulihanto andSosrowidjoyo, 1996).

The South Sumatra basin contains diverse

petroleum systems, with both oil and gas

being sourced from lacustrine and fluvio-

deltaic terrestrial facies (Figure 19). Marine

facies of the Gumai formation have been

suspected of contributing to reserves,

especially gas, and there is even speculation

of a local carbonate or calcareous shale

source (Davis, pers. comm.).

Reservoirs include fractured basement

granites (Figure 20) and metamorphics,

granite-wash, OligoceneMiocene fluvio-

deltaics (Lemat, Talang Akar, Muara Enim

and Air Benakat formations) and lower

Miocene leached and fractured carbonate

buildups (Batu Raja formation). In the

Tempino oil field one of the reservoirs is a

fractured sill (Caughey, pers. comm.),

although this is not of economic significance.

Although not strictly part of the South

Sumatra basin small intra-montane basins in

the Barisan range (e.g., the Pasemah Block

operated by Stanvac Kamal, 1999),

demonstrate a similar history and origin to

the nearby South Sumatra basin with good

Talang Akar and Batu Raja formation

reservoirs at outcrop and oil and gas seeps

with a lacustrine source indicated.

Stage I. Syn-rift(late Cretaceouslate Oligocene)Rifting is considered to have commenced as

early as the late Cretaceous and continued

through to the late Oligocene. Northsouth

normal faults and a northwestsoutheast-

oriented horst and graben developed in

response to tensional shear as subduction

slowed at the Sunda trench. The graben

developed along pre-existing Mesozoic

transform fractures as in the Central

Sumatra basin.

Syn-rift fill includes the Eocene Lahat

formation granite-wash, volcaniclastics, and

conglomerates and sandstones that appear

to have developed as alluvial fans and river

systems within the deep graben. These

coarse clastics fine-up into the Lemat

formation, subordinate and commonly over-

mature source facies, which include

lacustrine Botryococcus- and Pediastrum-

rich shales, and lake-margin, coaly, organic

facies. Lemat fluvial sands are also locally a

reservoir. In the Puyuh field, Lemat channel

sands host oil and are interbedded with

intra-formational, lacustrine source rocks

(Maulana et al., 1999).


C

A

A

A

A

C

Figure 19: Kerogensextracted from sourcefacies in the SouthSumatra basin. Topphotograph showsterrestrial oil-pronesource faciesdominated by cutinite(C) and other land plantmaterial. Bottomphotograph showslacustrine oil-pronesource faciesdominated byBotryococcus algae (A).(Photos courtesy of S. Noon.)

X0.5

X1.0

X1.5

X2.0X7.5

X7.0

X6.5

X6.0

S

E

N

Major fractures -strike

Minor fractures -strike

W

S

E

N

W

Figure 20: FormationMicroScanner* images from afractured granitebasement reservoir,South Sumatra basin.

Stage II. Sag(late Oligoceneearly Miocene)The late Oligocene to early Miocene was

marked by transgression as a result of

thermal sag and eustatic gain. Late

Oligocene Talang Akar alluvial and braided

fluvial deposits, the main reservoir sands in

the basin, were deposited in basinal lows,

and are either sealed internally or by the

overlying marine Gumai shale in

stratigraphic and anticlinal traps.

Extensive Talang Akar shallow-marine and

deltaic coals and shales are considered to

be the major source rocks in the basin.

They are dominated by mixed oil- and gas-

prone type III terrestrial kerogen

(Schiefelbein and Cameron, 1995) and,

where buried deeply enough adjacent to

basement highs, have charged fractured

basement reservoirs. This can be seen in

the Rayun, Sumpal, Dayung, Bungkal,

Bungin, Hari and Suban deep gas fields.

With continued transgression into the

early Miocene, large Batu Raja formation

carbonate buildups developed on structural

highs and are important reservoirs,

particularly where they have been solution-

enhanced (Figure 21). Bulk reservoir

properties are highly variable but often good

(e.g., Ramba, Rawa and Suban with average

permeabilities in the 500750 mD range).

These buildups are thought to have

developed as low-relief, low-energy,

carbonate-mud-dominated banks

(Situmeang et al., 1993; Longman et al.,

1993) in a restricted seaway.

The Gumai shales were developed off-

bank in deeper water and, as transgression

progressed, formed a top seal to the Batu

Raja formation buildups. The Gumai shales

may also locally contribute to gas

generation where mature in basin deeps.

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