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Page 1: Geology

A Geological Overview of Indonesia

Chapter 4

Page 2: Geology

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 ndonesia’s development as a nation has

been strongly influenced by its geography

and 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 (<0.1%) sulfur content.

Indonesia is also the sixth-largest gas

producer in the world, and the largest

liquefied natural gas exporter, mainly

Overview of Indonesia’s oil and gas industry – Geology174

PT SCHLUMBERGER INDONESIARichard Netherwood

Overview of Indonesia

Page 3: Geology

Overview of Indonesia’s 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

TBASula

wesi

Sum

atra

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 - Banggai–SulaS/M - Salabangka–ManuiBU - ButonBD - BandaB - BoneF - FloresSS - Spermonde/SelayarL - LariangSBL - South Bali–LombokSA - SavuTI - TimorNWSZOC - Northwest Shelf zone

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

Wal

lace

line

Moluccas

TImorNusa Tenggara

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

Page 4: Geology

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 Indonesia’s 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).

Page 5: Geology

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 Sumatra–Java–Timor–Aru

Overview of Indonesia’s oil and gas industry – Geology 177

30MaMid Oligocene

EURASIAN PLATE

INDIAN PLATE

Proto-South

China Sea

Australia

Bird'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-South

China Sea

Malaysia

Sumatra

Java

SouthBorneo

Zamboanga

West Sulawesi

Oki Daitoridges

East Philippines

NORTH NEW GUINEA PLATE

Indochina

South China

INDIAN–AUSTRALIAN PLATE

South and East Sulawesi

PHILIPPINE SEA PLATE

PACIFIC PLATE

40MaMiddle Eocene

EURASIAN PLATE

INDIAN–AUSTRALIAN PLATE

Leading edge ofBird's Head microcontinent

PACIFIC PLATE

Izupeninsula

Celebes

SeaWest

Philippine

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

Sulu

Sea

Sulu arc activityends

Borneorotationcomplete

Malaya blocksrotation complete

Andaman spreading

Molucca Seadouble subductionestablished

Ayu trough spreading

N Banda

Sula

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).

Page 6: Geology

(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.

Overview of Indonesia’s oil and gas industry – Geology178

0 80 160 320 480m

0 160 320 640km

PHILIPPINE SEA PLATE

PACIFIC PLATE

CAROLINE PLATE

Strike–slip fault

Oceanic spreading axis

Subduction zone

Australian crust

Transitional, attenuated or sutured

Oceanic or island arc

Pre-Mesozoic continental crust

Quaternary–recent volcano

SUNDALAND

EURASIAN PLATE

AUSTRALIAN – INDIAN PLATE

AUSTRALIA CRATON

5cm/yr

7cm/yr

Sunda trench system

Mentawai fault

Java trench

Sum

atra trench

Great Sumatra fault system

South China Sea

Philippines

Pacific Ocean

Palau tr

ench

Mari

ana t

rench

Sorong faultWest Melanesian trench

Seram trough

Aru

tro

ugh

Timor trough

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).

Page 7: Geology

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 Philippine–Halmahera–New 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. >50–43 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

northwest–southeast 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 Bird’s 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. 43–25 mybp (middle Eocene–latest 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 north–south

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. 25–8 mybp (latest late Oligocene–lateMiocene)

In the late Oligocene, at about 25 mybp, the

leading edge of the New Guinea passive

margin (Australian craton) collided with the

Philippine–Halmahera–New 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 ‘Bird’s 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.

Overview of Indonesia’s oil and gas industry – Geology 179

Page 8: Geology

Stage IV. 8–0 mybp (late Miocene–Present)

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

(30–13 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

Overview of Indonesia’s oil and gas industry – Geology180

Page 9: Geology

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

Bird’s 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.

Overview of Indonesia’s oil and gas industry – Geology 181

Page 10: Geology

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 <200 m). They demonstrate gross

similarities in terms of both structure and

stratigraphy (Figure 5) reflecting common

regional controls throughout their Cenozoic

histories. Of particular note is their position

on the southeastern promontory of the

Sunda shield (Sundaland), their similar

tectonic histories (related primarily to the

motion of the Indo-Australian plate relative

to the Asian plate) and the influence of

global eustatic events on their sedimentary

fills. These factors have controlled:

• A common middle to late Eocene timing

for initial basin rifting and associated

fluvio-lacustrine fill, including the main

source rock for the majority of Western

Indonesian basins.

• Transgression from the middle Oligocene

through to the middle Miocene with fluvial

reservoirs being succeeded by the main

deltaic and carbonate reservoirs in the late

Oligocene to early Miocene, and regional

seals being deposited in the middle

Miocene at maximum transgression.

• Late Miocene through Pliocene

compressional structuring events and

increased heat flow associated with the

collision of the Australian craton with the

Asian plate, 8–3 mybp, and collision of

the Luzon arc with the Asian plate at

about 5 mybp.

Although there are gross geological

similarities between the Western Indonesia

basins, there are also significant geological

differences. These are primarily controlled

by basin position on the Sundaland

promontory in relation to present-day and

Cenozoic subduction of the Indo-Pacific

plate northwards beneath Sundaland. Fore-

arc basins occur between the modern

volcanic arc (the northern limit of the fore-

arc basins) and the subduction-generated

accretionary prism (outer island-arc of

Sumatra and the southern limit of the fore-

arc basins). Traditionally, these have been

considered of low prospectivity because

they lack source rocks, and have low-quality

volcaniclastic reservoirs and low heat flow.

The back-arc basins are situated behind the

volcanic arc and include all the remaining

basins of Western Indonesia. Only the basins

of Sumatra, Java, the Java Sea (which

extends east to the north of Lombok) and

possibly the Pembuang basin (although

there is no information for this basin) of

South Kalimantan are considered to be

back-arc basins in the strictest sense. They

are situated within tens to hundreds of

kilometers of the present-day volcanic arc

and their histories are dominated by their

proximity to the nearby subduction zone.

More distal back-arc basins (>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.

Overview of Indonesia’s oil and gas industry – Geology182

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

Page 11: Geology

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 Timor–Aru

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.

Overview of Indonesia’s oil and gas industry – Geology 183

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.

+ + + + + ++v

v 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

Page 12: Geology

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

Oligocene–Miocene shales are within the oil

window and the geothermal gradient is

between 4.5 and 5˚C/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 (Eocene–late 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 northeast–southwest,

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 westnorthwest–eastsoutheast,

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 Oligocene–early Miocene) A second stage of rifting took place in the

late Oligocene to early Miocene and marks a

change from orthogonal extension to

oblique northwest–southeast slip.

North–south 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

Overview of Indonesia’s oil and gas industry – Geology184

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 fore–arc 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

Page 13: Geology

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

Oligocene–Miocene section contains oil

shows. Mulhadiono and Asikin (1989)

describe the upper Oligocene–lower

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 Miocene–Pliocene)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 Oil’s 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

Overview of Indonesia’s oil and gas industry – Geology 185

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).

Page 14: Geology

SumatraSunda basin

Seribu platfo

rm

Tangeranghigh

West Java

WestMalimping

low

Honjehigh

UjungKulonhigh

UjungKulonlow

Pull-aparthalf-graben

UjungKulon 1a

Bayahhigh

Bayah

Ciletuhhigh

DDH-2

DDH-1Fig.9a

Fig.9b

Sunda st

rait

Malimping block

Krakatau

0 50km

Cimandiri fault

(>4.5˚C/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(Pliocene–Pleistocene)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

north–south-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 180˚C and

then uplift in the early Miocene from about

Overview of Indonesia’s oil and gas industry – Geology186

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).

Page 15: Geology

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 95˚C.

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 Pliocene–Pleistocene, 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

Pliocene–Pleistocene 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 formation’s 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

Indonesia’s 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

Indonesia’s 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

Indonesia’s 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 Pliocene–Pleistocene inversion event.

Overview of Indonesia’s oil and gas industry – Geology 187

LegendMarine (Cenozoic)

Marine (Mesozoic)

Lacustrine (Cenozoic)

Terrigenous (Cenozoic)

Figure 10: Oil sourcecharacteristics forIndonesia’spetroleum systems(Ten Haven andSchiefelbein, 1995).

Page 16: Geology

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 Thailand–Indonesia 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(Eocene–late 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 Oligocene–early Miocene)In the late Oligocene a second stage of

rifting was characterized by a north–south

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,

Overview of Indonesia’s oil and gas industry – Geology188

Sumatran fault systemSum

atra

BarisanM

ountainthrust front

Batumandi

Wampu

NSO

Kambuna

Glag

ah lo

w

Pusu

ng h

ighPa

kol l

ow

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).

Page 17: Geology

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 Miocene–middle 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 north–south

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

Overview of Indonesia’s oil and gas industry – Geology 189

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 300–500 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).

Page 18: Geology

Stage IV. Episodic uplift(late–middle and latest Miocene)

The remainder of the Miocene was

characterized by ‘yo-yo’ tectonics.

Latest–middle 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 Miocene–Pliocene 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 Miocene–Pleistocene)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 north–south-

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; Nur’aini 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

Indonesia’s 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 northwest–southeast 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 north–south-trending, right-lateral

strike-slip faults (Figure 14) which follow

Overview of Indonesia’s oil and gas industry – Geology190

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).

Page 19: Geology

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 northwest–southeast trending

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

the Sembilan uplift – Figure 15) reflect

ancient basement arches. At the surface,

locally occurring northeast–southwest-

oriented fracture swarms represent Riedel

shears that are associated with the

northwest–southeast-oriented, right-lateral

Great Sumatra fault system.

Oil is concentrated in two principal areas. In

the west the Minas–Duri–Bangko 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 Eocene–late Oligocene)Rifting was initiated during middle to late

Eocene collision between the Indian and

Asian plates, and deep, north–south- and

northwest–southeast-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

Overview of Indonesia’s oil and gas industry – Geology 191

Bengkalis

Island

Padang

Island

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 faultKempas–Beruk uplift

Sembilan upliftSiak Kecil syncline

Bengkalisdepression

Metas–Kutupfault

Mengkapen

Figure 15: Fielddistribution alongregional,north–southtrending 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).

Page 20: Geology

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 Oligocene–middle 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, north–south right-

lateral faulting was active throughout and

produced early Miocene pull-apart basins.

Overview of Indonesia’s oil and gas industry – Geology192

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(middle–late 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 Miocene–Pleistocene)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

Pliocene–Pleistocene, 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 group’s 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.

Page 21: Geology

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.

Overview of Indonesia’s oil and gas industry – Geology 193

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

Bangko high

Ketaling high

Lematang fault

Sumatra fault zone

Approximate extent of SouthSum

atrabasin

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

Page 22: Geology

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, Oligocene–Miocene 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 Cretaceous–late Oligocene)Rifting is considered to have commenced as

early as the late Cretaceous and continued

through to the late Oligocene. North–south

normal faults and a northwest–southeast-

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).

Overview of Indonesia’s oil and gas industry – Geology194

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.

Page 23: Geology

Stage II. Sag(late Oligocene–early 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 500–750 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.

Overview of Indonesia’s oil and gas industry – Geology 195

Mo

Mo

Mo

Vu

Ch

Ch

Vu

Figure 21: Leachedskeletal packstonefrom the early MioceneBatu Raja formation,Air Sedang field, SouthSumatra. Porosityincludes molds (Mo),vugs (Vu) andchannelized pores (Ch).(Longman et al., 1993.)

Stage III. Uplift(middle–late Miocene)During the middle Miocene there was an

increase in subduction rates that led to

major compression. This was manifested by

the Barisan Mountain uplift, activation of

the Great Sumatra fault and the formation

of traps, which are mainly anticlines and

faulted anticlines. A regressive phase of

deposition commenced with the shallow-

marine to deltaic Air Benakat and Muara

Enim formations that are the main

reservoirs in the Jambi area (e.g., the

original Jambi discoveries such as Kenali-

Asam, Tempino, Bajubang, Pannerokan, and

the more recent North Geregai oil field).

Petroleum generation and expulsion may

have started in the early middle Miocene

and was well underway by the late Miocene.

This would suggest that a significant

amount of hydrocarbons leaked-off just

prior to the main middle to late Miocene

period of structural development.

Stage IV. Uplift(Pliocene–Pleistocene)Compression continued, and thick volcanics

and volcaniclastics were deposited as the

main period of volcanic arc development got

underway. This appears to have been

accompanied by a significant increase in

heat flow, recorded in the Sunda Strait area

by apatite fission track analysis (Soenandar,

1997), which promoted the main phase of

hydrocarbon generation and migration.

The South Sumatra basin is at a relatively

mature stage of exploration, and it is likely

that most of the large oil fields have been

found. Significant gas, however, probably still

remains to be discovered. The generation of

new and adventurous plays in the 1990s

continued to produce new discoveries. Oil

was discovered by Gulf in 1993 in syn-rift

Lemat fluvial sands of the Puyuh field

(Maulana et al., 1999) and is also produced

from the young, low-resistivity Air Benakat

and Muara Enim sands that are reservoirs for

oil and gas in the Jambi area. Fractured

basement reservoirs hold proven reserves of

over 4 TcfG, and are still being drilled.

More recently, deep basinal areas have

been drilled successfully targeting gas in

deeply buried, fractured Batu Raja

formation limestones (e.g., Singa 1 and 2

drilled in 1999). In addition, limited

potential still remains for the traditional

Talang Akar and Batu Raja formation plays.

Tertiary recovery projects hold further

potential, and some of the older fields are

undergoing successful waterfloods (e.g.,

Kenali-Asem and Bajubang fields).

Sunda and Asri basinsThe Sunda basin and its northern extension,

the Asri sub-basin, are relatively small,

Cenozoic, back-arc depocenters. They occur

entirely offshore in the northern part of the

Sunda Strait, between the islands of

Sumatra and Java (see Figure 22). One of

the oldest production sharing contracts in

Indonesia, the offshore South Sumatra

contract was signed by IIAPCO in 1968. The

area was considered mature with little or no

prospect of further significant hydrocarbon

discoveries by the middle 1980s; particularly

with regard to the Asri sub-basin where a

large number of wells had been drilled with

no hydrocarbon shows and no proven source

rock (Wight et al., 1997). In late 1987,

however, the Intan oil field was discovered

closely followed by the large (260 MMBO)

Widuri oil field, and several smaller satellite

accumulations. The Asri sub-basin remains

prospective to this day.

Stage I. Syn-rift (middle Eocene–late Oligocene)A series of north–south trending extensional

half-grabens caused by northwest–southeast

shear associated with the collision of the

Indian subcontinent with the Asian plate,

contain a thick Paleogene syn-rift sequence

that has been drilled to the lower Oligocene,

but probably extends into the Eocene

(Wight et al., 1997). These sediments

include the principal source rocks for the

area, the Banuwati formation lacustrine

shales, dominated by type I, oil-prone

kerogen. Rift margin coarse clastics are

laterally equivalent to the Banuwati shales

and form a subordinate reservoir facies.

Page 24: Geology

Stage II. Sag(late Oligocene–late Miocene)

The alluvial, fluvial (Figure 23), deltaic and

marginal-marine sandstones of the upper

part of the Talang Akar formation are the

main reservoirs in both basins, and

represent basin margin fill with marine

shales that were deposited in the basin

centers. In the Widuri oil field, the fluvial

Gita member sandstones attain

permeabilities in the range of tens of

Darcies and porosities of over 25% (Wight

et al., 1997).

Unfortunately, other oil fields are

marginalized by a high diagenetic kaolinite

content that has destroyed permeabilities

even though oil saturations may be high.

Talang Akar reservoirs are sealed intra-

formationally, and by semiregional formation

top shales.

In the more southerly Sunda basin, early

Miocene Batu Raja formation carbonates

(Figure 24) developed on basement highs

around the edge of the basin, with thick pay

zones associated with lowstand dissolution

events (Wicaksono et al., 1995). Batu Raja

reservoir quality may be poor where low-

permeability, micritic, wackestone facies

dominate. Deeper-marine Gumai shales

provide an effective seal for the Batu Raja

carbonate reservoirs.

The Banuwati shale may have entered the

oil window in the early Miocene. Lateral

migration occurred many kilometers along

the weathered sediment/basement interface,

channel sands and, in carbonates, via karst

pipes, with vertical migration via faults (Wight

et al., 1997). The latter part of the Miocene

was a period of continued quiescence with

deposition of Parigi formation carbonates and

Cisubuh formation fine marine clastics.

Overview of Indonesia’s oil and gas industry – Geology196

YPF Maxus

Arco

Jakarta

PERTAMINA

Jatinegara

Tambun

RDLMB

CilamayaUtara

PasirjadiSDSPagaden

PMK

GantarJatibarang

TugubaratRandegan

Cemara

KPT

GGXK

XM

XWOBOM

OOOO

OUOWFS

FFN

FW

FIHZEE

ES

UR

BBTS

BZZ

SC

KL

L

LLMM

MRMX

MQ

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APN

AA

Bima 'ZU'

DumaNora

SelatanUtari

KittyCint A Rama

Wanda GitaFaridaKrisna

NurbaniYvonne

SundariJanti Yani

Widuri

Intan

KarmilaKartini

AVAVS

L-Parigi

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Java

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matr

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Cirebon

Sunda platform

Seribuplatform

Vera

Cirebon

Basementtime

structure

Jakarta

Java

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matr

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South ArdjunaSouth Ardjuna

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Asri

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Cipunegara - E 15 Graben Jatibarang

< 0.5 TWT scale, sec

0.5–1.01.0–1.51.5–2.02.0–2.52.5–3.0> 3.0

Figure 22: Basement time structure map of Northwest Java sub-basins(above) and location of hydrocarbon fields (below) (after Noble et al., 1997).

Page 25: Geology

Overview of Indonesia’s oil and gas industry – Geology 197

5 10km0

2360ft

2314ft

2380ft

2379ft2359ft

Figure 23: Amplitudemap of 33 series sandof the lower MioceneUpper Gita member ofthe Talang Akarformation. Meanderingchannel systems areclearly visible (modifiedfrom Armon et al.,1995).

Figure 24: Evidencefor exposureincluding thin coals(left top), shale-filledkarst pipes (middle)and karst breccia(right) in the earlyMiocene Batu Rajaformation. Core fromwell Jelita 1, Sundabasin (Wicaksono etal., 1995).

Stage III. Uplift(Pliocene–Pleistocene)

During the Pliocene–Pleistocene, shallow-

and marginal-marine sediments and

volcaniclastics were deposited, accompanied

by a rapid increase in heat flow (Soenandar,

1997) related to development of the existing

volcanic arc. This thermal event pushed

much of the Banuwati shale into the oil

window, greatly increasing the prospectivity

of the region.

From an exploration perspective, the

Sunda–Asri area is relatively mature,

particularly the Sunda basin. Discovery of the

Intan, Widuri and related fields in the more

northerly Asri sub-basin in the late 1980s to

early 1990s could suggest that further Talang

Akar reservoirs remain to be discovered. The

eastern part of Asri sub-basin is sparsely

drilled. Marginal Talang Akar oil fields, such

as the Risma field, may become commercially

viable as exploitation technologies improve

and costs are reduced. Early syn-rift plays

have not been extensively tried and their

potential requires further evaluation.

Page 26: Geology

Northwest Java basinThe Northwest Java basin lies roughly equally

in an onshore and shallow-offshore setting (see

Figure 22). The Northwest Java production

sharing contract (PSC) is the oldest offshore in

Indonesia, being signed by IIAPCO in 1966,

and farmed out to Arco in 1969, after IIAPCO

obtained the offshore South Sumatra PSC.

This back-arc basin is extensive and

complicated, comprising a number of

north–south-oriented half-graben and sub-

basins situated on the southernmost edge of

the Sunda platform (Reksalegora et al., 1996).

The three main depocenters, from west to

east, are the Ciputat, Ardjuna and Jatibarang

sub-basins, with minor onshore sub-basins

including the Kepuh, Pasir Bungur and

Cipunegara E-15. The Vera sub-basin lies

offshore in the northeast part of the basin. The

Northwest Java basin deepens towards the

Bogor trough in the south, abutting the

volcanic arc (Figure 25). In the north, younger

Tertiary cover onlaps the Sunda shield.

Hydrocarbon accumulations are

abundant, and both oil and and gas

(thermogenic and biogenic) (Noble et al.,

1997) are reservoired in stacked

volcaniclastic, carbonate and coarse

siliciclastic beds. The onshore Jatibarang oil

field contains multiple-stacked reservoirs

that include fractured Jatibarang formation

volcanics and volcaniclastics, Talang Akar

formation sands, Batu Raja formation

limestones, upper Cibulakan formation

sands and carbonates, and Parigi formation

limestones (Amril Adnan et al., 1991).

Stage I. Syn-rift(middle Eocene–late Oligocene)

Eocene to early Oligocene tilting led to the

development of the Seribu platform and the

Northwest Java basin, which deepens towards

the Bogor trough in the south. North–south

block faulting, associated with dextral shear

due to the collision of the Indian subcontinent

with the Asian plate, produced the various

sub-basins and half-grabens that make up the

Northwest Java basin (Gresko et al., 1995).

The middle Eocene–middle Oligocene

Jatibarang formation consists of interbedded

volcanics, volcaniclastic sands and lacustrine

shales, which represent the initial basin fill.

Reservoirs are commonly fractured and

lacustrine shales are the main oil source to

the east in the Jatibarang sub-basin (Noble et

al., 1997). Equivalent alluvial-fan and fluvial-

sand facies are also potentially good reservoir

targets in the western part of the basin

(Butterworth and Atkinson, 1993). Late syn-

rift fill comprises the early to late Oligocene,

fluvial lower Talang Akar formation, which

again demonstrates good reservoir potential

and represents the phase II syn-rift deposits

of Butterworth and Atkinson (1993). In the

eastern part of the basin, later syn-rift fill

fluvial-dominated deltaic-channel and delta-

front bars, and fan-deltas are starting to be

important reservoir targets (Ascaria et al.,

1999). Jatibarang and Talang Akar reservoirs

are sealed by intra-formational shales.

Stage II. Sag(late Oligocene–late Miocene)

Late Oligocene transgression led to

deposition of the upper Talang Akar (lower

Cibulakan) formation, with greatly reduced

volcanic influence (Butterworth and

Atkinson, 1993). Thick, paralic, oil-prone

coals are of particular importance as source

rocks in the more northerly Ardjuna sub-

basin (Noble et al., 1997), whereas more gas-

prone deltaics and shallow-marine shales of

the upper Talang Akar formation represent

the major source facies for both oil and gas

elsewhere in the basin (Noble et al., 1997).

Fluvial systems supplied coarse clastics from

the north, and fluvial and shallow-marine

sands are significant reservoirs at this level.

North–south oriented Talang Akar and

younger, middle-Miocene, upper-Cibulakan

channels are thought to represent the main

lateral migration pathways.

Continued quiescence through the early

Miocene saw the development of fully open-

marine conditions and deposition of the

coral-rich Batu Raja formation (middle

Cibulakan). This was followed by the

Massive unit carbonate buildups developed

on basement highs and representing

another major reservoir facies, particularly

where there is significant dissolution

porosity (e.g., the Bima oil field). Laterally

equivalent marine shales provide a seal for

the Batu Raja carbonate reservoirs.

Overview of Indonesia’s oil and gas industry – Geology198

JavaJakarta

Oil reservoir

Bogor trough

Parigi Cisubuh

LowerCibulakan

Batu Raja

Jatibarangvolcanics

Continental crust(Sunda shield/Asia plate)

Melange

Subduction of oceaniccrust (Indian plate) beneath

Sunda shield

Volcaniclastics

NEOffshore

SW

Sea level

Fore-arc basin Magmatic arc Back-arc basin

Offshore

Turbidites

Figure 25: Simplified geological cross-section of West Java.

Page 27: Geology

The middle Miocene upper Cibulakan

includes both carbonate and clastic

reservoir facies. The mid-Main member

carbonate buildups are, according to Isworo

et al. (1999), the main reservoir in the

Seribu shelf area. Gentle, middle Miocene

uplift of the Sunda shield to the north

resulted in a supply of upper Cibulakan

clastics, another reservoir facies, to the

marine area in the south. From 3D seismic

across the Northwest Java shelf,

Posamentier (1999) identified transgressive

tidal sand ridges in the upper section of the

Main member. These features are

potentially excellent stratigraphic traps,

being enclosed entirely in overlying, deeper-

marine shales.

Stabilization again led to deposition of

carbonates in the late Miocene, when pre-

Parigi and Parigi formations developed as

relatively low-energy, fine-grained, shaly-

lime muds, and packstones and

wackestones. Pore types are dominated by

matrix microporosity, demonstrating

solution enhancement as a result of

lowstand exposure (Bukhari et al., 1993).

These carbonates are a major reservoir for

both thermogenic and biogenic gas, the

latter being sourced from deeper-water-

equivalent marine shales. Locally, these

carbonates also form oil reservoirs in the

onshore area.

Stage III. Uplift(late Miocene–Pleistocene)

Late Miocene collision of the Australian

craton with the Sunda trench, far to the east

resulted in uplift and influx of coarse-grained

sand, the Cisubuh formation, which also acts

as a reservoir for biogenic gas. Cisubuh shales

form the main seal for Parigi carbonate

reservoirs. At this time, a significant increase

in heat flow (Soenandar, 1997) resulted in

the main phase of maturation and migration,

concurrent with trap formation in broad

anticlines and tilted fault blocks.

The Northwest Java basin is now

considered to be mature, with the

distribution of upper Talang Akar sands and

Miocene carbonate buildups being fully

understood. Considerable potential for

small- to medium-sized fields may remain in

the syn-rift Jatibarang formation and the

lower Talang Akar formation.

East Java basinThe East Java basin is, without dispute, the

most structurally and stratigraphically

complex of the Indonesian back-arc basins.

In terms of reservoir facies, which range

from Eocene, fractured, calcareous shales

and shaly limestones to diagenetically

enhanced, Pleistocene volcaniclastics, and

also in terms of petroleum systems, it is one

of the most diverse. The basin extends

east–west from onshore east Central Java,

for over 1000 km to the Flores back-arc

basin, and includes a number of distinct

east–west oriented structural zones.

Branching off from this main basin trend to

the north, is a series of northeast–southwest-

trending half-grabens downthrown to the

east. These include, from west to east, the

Muriah trough, the Tuban-Camar trough,

the central-deep depression (Masalembo

basin), and the Sakala sub-basin, which are

separated by areally extensive structural

highs (Figure 26). The basin is

predominantly offshore with water depths

reaching over 1500 m in the Lombok sub-

basin, and covers a total area in the region

of 200,000 km2.

Onshore, the structural picture is

extremely complicated, with multiple

phases resulting in all modes of faulting.

Tertiary development includes a major

inversion event, and at least two major

episodes of volcanism. The picture is

further complicated by a plethora of

lithostratigraphic schemes (see Ardhana et

al., 1993) compiled by the large number of

companies that have explored different

parts of the basin. These schemes show

significant differences and have yet to be

satisfactorily reconciled across the basin.

Historically, the East Java basin has been

significant in the quest for oil. Numerous

Overview of Indonesia’s oil and gas industry – Geology 199

Sibaru platform

Sakala sub-basin

Kangean high

Lombok sub-basinSouth Madura sub-basin

RMK wrench zone

Kendeng zone

Java Ge anticlineEast Java

Bali Lombok

RMK Inversion zone

North Madura platform

Masalembo basin

JS-1 rid

ge

Muriah trough

North Rembang zone

South Rembang zone

Bawean arch

Tuban–Camar trough

Central-d

eep depression

Madura

Sakala fault

Lombok ridgeKujung thrust belt

Kendeng zone

Quaternary volcanic arc

Normal fault, NE-trending separates basinal lows from highs

Thrust structure located at inversion zone

Strike-slip movement/wrenching, located at flank area/basinal margin

Platformal area, arch and ridge

Basinal area

Southern basin

RMK wrench zone (high) 0 100km

Figure 26: Generalizedbasin configuration forEast and NortheastJava basins (afterManur andBarraclough, 1994).

Page 28: Geology

onshore oil fields were discovered by the

Dutch before World War II, with production

from the middle Miocene Ngrayong

formation sandstones (e.g., the Kawengan

oil field being the largest and still producing

today) or Pliocene deepwater carbonates

(e.g., the Lidah and Metatu oil fields). All

these fields were discovered on the basis of

the very obvious surface expression of

northwest–southeast-trending (Cepu area in

the west) and east–west-trending (near

Surabaya in the east) anticlines. Production

peaked with the war effort in the 1940s.

Stage I. Syn-rift(middle Eocene–latest early Oligocene)Transtensional tectonics in the early to

middle Eocene led to the onset of rifting

that continued into the early Oligocene. The

earliest syn-rift fill includes fluvial sands,

and lacustrine shales and coals. These

sediments appear to be oldest in the far

southeastern part of the basin. Offshore in

the east reservoirs occur in the pre-Ngimbang

and Ngimbang clastics (Ebanks and Cook,

1993) as the West Kangean and Pagerungan

gas fields, respectively. Similar deltaic and

shallow-marine, Eocene clastics, including

good reservoir sands (Figure 27), crop out

to the west of the basin limits in Central

Java near Nanggulan.

Late Eocene transgression deposited the

Ngimbang carbonates which are shallow-

marine, low-energy, shaly, micritic

limestones and calcareous shales occurring

in the east of the basin. These highly

indurated and fractured sediments form the

main reservoir in the West Kangean gas field

(Siemers et al., 1993b). Elsewhere offshore,

upper Eocene to lower Oligocene,

Lepidocyclina-rich, larger benthic,

foraminiferal limestones, the CD carbonates,

are reservoirs for subcommercial oil and

gas. The CD carbonates are overlain by

deep-marine shales, representing maximum

transgression, which form a seal for the

Pagerungan and West Kangean reservoirs.

Historically, it has been assumed that all

the oil and thermogenic gas of the East Java

basin has been sourced from syn-rift

lacustrine shales. This would appear to be

the case for the gas in the Pagerungan and

West Kangean fields in the eastern part of

the basin (Schiefelbein and Cameron, 1997)

but elsewhere, hydrocarbons demonstrate a

deltaic or paralic marine source with

carbonate affinities (Davis, pers. comm.). It

is possible that the pre-Ngimbang clastics in

the east of the basin have been buried deep

enough to generate oil since the late

Eocene. It has since been displaced by gas,

which is being generated to this day.

Stage II. Sag(late Oligocene–latest early Miocene)

Following the mid-Oligocene global lowstand,

clastics were rapidly transgressed by the

shallow-marine Kujung carbonates. These

limestones are red-algae dominated, but are

also commonly coral- or larger benthic

foraminifera-rich (Figure 28). They are a

proven reservoir both onshore (e.g., Mudi oil

field) and offshore (e.g., the Ujung Pangkah

oil and gas field near Surabaya, the KE2 oil

field and the minor Camar oil field). A

number of Kujung buildups remain undrilled.

Structural activity intensified in the early

Miocene with compression in the southeast.

This led to inversion of the Madura–Kangean

high forming the structures for the

Pagerungan and West Kangean gas fields

(Bransden and Matthews, 1992). In the

west, rapid deposition of the deepwater

Tuban formation shales occurred in

subsiding depressions while the Rancak

formation buildups developed on the highs.

These carbonates are reservoirs for oil and

gas in the offshore, more central part of the

basin (e.g., KE2 field). Tuban shales are a

strong candidate as a source rock for much

of the oil and gas in the western part of the

basin, although this is not proven.

Stage III. Multiple uplift(middle Miocene–Pleistocene)The remainder of the Neogene is

complicated by repeated multiple

compressional phases and is grouped under

one episode for the sake of simplicity.

Early–middle Miocene Ngrayong

formation sandstones were deposited in the

south during compressional fault-block

rotation, uplift and erosion. Historically, the

onshore Ngrayong sands were the main

reservoir in the East Java basin, and host

most of the oil in the westerly Cepu region.

They represent the main reservoir in the

Kawengan oil field and are interpreted as

relatively deep marine, turbidite fan

deposits (Ardhana, 1993 and Ardhana et al.,

1993), and are high-quality reservoirs (see

Figure 28). Shallow marine Ngrayong

equivalent shore-face sands crop-out to the

north of these deeper marine facies in the

uplifted North Rembang zone (see Figure

26). Ngrayong formation sands are also

recognized offshore in the Muriah trough to

the north, hosting biogenic gas sourced

from contemporaneous Ngrayong coals

(Manur and Barraclough, 1994).

Phillips et al. (1991) believe that the

Eocene Ngimbang clastics entered the oil

Overview of Indonesia’s oil and gas industry – Geology200

55.0

554

.75

87.30

89.80

1 2 3 4 5 6 7 8

Figure 27: Shallow cores from locations near Nanggulan, Central Java. These Eocene fluvio-deltaicshallow marine (trays 1 and 2), shoreface (trays 3 and 4) and distributary channel (trays 5 to 8)sands are potential reservoir sands (photos courtesy of Coparex BV).

Page 29: Geology

Overview of Indonesia’s oil and gas industry – Geology 201

Figure 28a: Pleistocene volcaniclastic sands. This volcaniclastic sandstonereservoir in the Wunut gas field, onshore Java, is characterized by excellentintergranular and dissolution porosity after feldspar (photo courtesy of Lapindo).

(a)

(b)

(c)

(d)

(e)

Figure 28b: Early Pliocene Paciran limestone. This globigerine foraminiferallimestone reservoirs biogenic gas in the East Java basin. Porosity in uncementedexamples can be as high as 70% (photo courtesy of Mobil Oil).

Figure 28c: Middle Miocene Ngrayong sandstone. These fine to medium graineddeepwater sands are interpreted as deep sea fan and/or contourite. Primaryintergranular porosity is good and reservoir potential is considered excellent.Shallower water Ngrayong facies reservoir oil onshore East Java basin (photofrom Ardhana et al., 1993).

Figure 28d: Early Miocene Kujung limestone. The examples shown are: an algal(possibly rhodolith) framestone (left) and larger benthic ( Lepidocyclina andMiogypsina) grainstone (right) with poor vugular and microvugular dissolutionporosity (V).

Figure 28e: Middle-late Eocene Ngimbang clastics. These medium to coarse-grained reservoir sands are from the Pagerungan gas field. Intergranular porosityis excellent and is enhanced by oversized dissolution pores (photo from Ebanksand Cook, 1993).

Page 30: Geology

window during the middle Miocene. During

the middle to late Miocene, subsidence led

to deposition of the deep-marine,

Wonocolo, fine-grained clastics, interrupted

by end late Miocene compression and

inversion, with deposition of shallow marine

Karren carbonates.

Continued compression into the Pliocene

resulted in further structural changes, with

shale diapirism and the development of two

major anticlinal trends; the east–west-

oriented Java trend and the

northeast–southwest Kalimantan trend.

These anticlines host the vast majority of

shallow, onshore oil fields and are strongly

expressed by surface geology in East Java.

In the early Pliocene, globigerine-limestones

were deposited. They are interpreted as

possible contourites by Schiller et al. (1995)

and are reservoirs for biogenic gas in the

east Madura Straits (Figure 28, Basden et

al., 1999) and for oil in some of the older,

onshore fields (e.g., Sekarkorong, Lidah and

Metatu). These globigerine limestones were

reworked into the late Pliocene Selorejo

formation, which is also a potential minor

reservoir. Pleistocene volcaniclastics are

minor reservoirs for gas in the onshore

region of East Java (e.g., Wunut gas field –

Figure 28; Kusumastuti et al., 1999).

Although the East Java basin is widely

explored, potential still remains for

significant oil and gas discoveries in the

Eocene syn-rift clastic, the deepwater-facies

Ngrayong sand and the Kujung and Rancak

limestone plays. Smaller, more esoteric

plays, such as the Pleistocene Wunut gas

field and biogenic gas plays, may

demonstrate potential purely because of the

well-developed infrastructure and nearby

industrial market in East Java.

Barito basinThe Barito basin is named after the Barito

River that flows from north to south in

Southeast Kalimantan, west of the Meratus

Mountains. It is bordered to the west by the

stable Barito shelf (Sunda shield) against

which the Neogene basin-fill onlaps

(Figures 29 and 30). The uplifted Adang

fault zone separates the Barito basin from

the upper Kutei basin to the North, and the

basin extends and shallows to the coast in

the south.

The Barito basin is subdivided into a

structurally complex northern section,

dominated by reverse-faulted anticlines, and

a southern area characterized by

undisturbed sediments dipping gently into

the axis of an asymmetric trough, with

thrusting and wrench-faulting at the eastern

margin against the Meratus Mountains

(Bonn et al., 1996; Figures 30 and 31).

The northern part of the basin contains all

the fields discovered to date, including the

large Tanjung Raya oil field (725 MBOIP)

with oil hosted mainly in syn-rift alluvial

facies that highlights the potential of this

play in the Western Indonesian basins.

Subordinate Tanjung Raya reservoirs

include post-rift, fluvio-deltaic sands and

minor, fractured basement. Other reservoirs

in the basin include Oligocene–Miocene

Berai formation limestones that tested gas

in the offshore Makassar 1 well, and the

early to middle Miocene sandstones of the

Warukin formation.

Basement comprises amalgamated

terranes, with continental basement to the

west and accreted zones of Mesozoic and

early Paleogene rocks in the east.

Overview of Indonesia’s oil and gas industry – Geology202

160–200kmW E

Stable Barito shelf Barito basinBarito

foredeep

Zone ofwrenchfaulting

MeratusMountains

Tertiary sedimentarycover up to 15,000ft thick

DahorDahor

Basement high

Warukin

Berai carbonates

Tanjung sandstonesFigure 30: Schematic geological cross-sectionacross the Northeast area of the Barito basin(Campbell et al., 1988).

100 200km0

Sunda shield

Kuch

ing

high

(Mes

ozoi

c or

ogen

ic b

elt)

Mal

aysia

Baritobasin

Paternostershelf

Tarakanbasin

Sulu Sea

Sempornafault

Maratuafault

Java Sea Su

law

esi

Mak

assa

r tro

ugh

Makassarstraits

rift

Kuteibasin

Mer

atus m

ounta

ins

(ophio

litic c

omple

x)

Asem

-Ase

mba

sin

Melawi basin

Arang fault (high)

Kerenden 1

Ketungau basin

Sangkukirang fault

Mangkalihat fault

Figure 29:Physiographic andlocation map ofKalimantan withdistribution ofhydrocarbon fields(modified fromMamuaya et al., 1995).

Page 31: Geology

Overview of Indonesia’s oil and gas industry – Geology 203

Figure 32: Texturally and compositionally immature Eocene alluvial pebbly sandstone reservoir fromthe lower Tanjung formation, Tanjung Raya field, Barito basin. Grains shown on the left includequartz (Q), feldspar (F) and volcanic fragments (V). Grains shown on the right are rimmed bycorrensite (mixed-layer smectite-chlorite). (Photos courtesy of JOB Pertamina Talisman.)

Didi 1

KambitinBagok 1

Semuda-1

Bangkau-1

Miyawa 1

Kasa

lerid

gePa

nnaa

nrid

geM

isirid

ge

Hala

trid

ge

TapianTimur

Tanjung

Warukin

Meratus

Mou

ntai

ns

Sihungnos e

250 50km

SE Kalimantan

Meratus

KeyPaleogene grabensBasement massifOil fieldOil showsThrust fault, late Miocene–RecentWrench fault, late Miocene–Recent

Figure 31: Structuralmap of the NortheastBarito basin showingPaleogene grabens anddistribution ofhydrocarbons. (AfterMason et al., 1993;Rotinsulu et al 1993and Satyana 1995).

V

Q

V

Q

VV

F

Q

F

L

Corrensite

Stage I. Syn-rift (Paleocene–middle Eocene)

Rifting in the Barito basin started relatively

early, in the Paleocene, with the

development of a series of

northwest–southeast-trending grabens

(Figure 31) as a result of collision between

the Indian subcontinent and the Asian plate.

Syn-rift sediments include deep lacustrine

source rocks, and alluvial and fluvial sands

of the upper Paleocene to middle Eocene

lower Tanjung formation, which comprise

the reservoir in the major Tanjung Raya oil

field (Figure 32).

Stage II. Sag(middle Eocene–middle–early Miocene)

Upper and lower Tanjung formation clastics,

overlain by Berai formation carbonates,

were deposited as a transgressive series

passing from fluvio-deltaic and shallow-

marine clastics, into platform limestones.

These clastics and carbonates are minor

proven reservoirs in the basin.

Stage III. Inversion (middle Miocene–Pleistocene)During the middle Miocene, South China Sea

continental fragments collided with north

Kalimantan and the Kuching high was uplifted

(see Figure 29). This event was

contemporaneous with collision to the east of

Sulawesi, which ended rifting in the Makassar

Strait and uplifted the proto-Meratus

mountains. Together, these events were

responsible for the onset of inversion that

intensified in the late Miocene when, far to the

east, the northwest Australia passive margin

collided with the Sunda trench and the Banda

fore-arc. Inversion was accommodated by

strike-slip faulting and later, in the

Pliocene–Pleistocene, by thrusting, folding

and trap formation. Erosion resulted in the

deposition of the regressive, paralic and

deltaic Warukin formation, which includes

coals, shales and minor reservoir sands.

Pliocene–Pleistocene reactivation of the

Meratus range against the rigid Barito

platform, shed Dahor formation tectonic

molasse westward off the mountain front

into the Barito basin. Together, these

sediments attain a thickness of several

thousand meters in the middle of the basin.

This extensive period of inversion also

buried source rocks deep enough for

maturation and expulsion of hydrocarbons

into the inversion anticlines.

Page 32: Geology

The Barito basin remains prospective.

The southern part of the basin is relatively

unexplored but does not hold much

structural promise. The syn-rift sediments are

a proven large-scale reservoir in the Tanjung

Raya field, which is presently undergoing

waterflood tertiary recovery. Berai formation

limestones are a potential economic reservoir

in the far north of the basin.

Kutei and Makassar basinsThe Kutei basin (Figure 33) covers an area of

about 60,000 km2. It is arguably the deepest

basin in Indonesia, the Tertiary column alone

attaining a maximum sediment thickness of

about 14 km (Allen and Chambers, 1998), and

it is 9 km deep in the productive area near

Samarinda and the Mahakam River delta.

The Schwaner Mountains to the northwest

of the basin comprise Cretaceous and

Tertiary turbidites and older igneous rocks.

To the west, the basin limit is confined by the

Kalimantan central ranges (including the

Muller Mountains), the Kapuas ranges and

the Kuching uplift. To the east the Kutei

basin passes into the deep-marine Makassar

(Strait) basin. It is bounded to the south by

the Adang fault zone, a flexured sinistral

transform downthrown to the north, and also

by the Meratus Mountains. To the north the

basin is bounded by the Bangalon lineament

and the Sangkulirang fault zone, a transform

with a strong element of downthrow to the

south. Basement is interpreted by Guritno

and Chambers (1999) to comprise Jurassic to

Cretaceous oceanic crust and is covered by a

thick turbidite sequence. The basement was

deformed, metamorphosed and intruded by

granites prior to the mid–late Eocene when

deposition of petroleum prospective

sediments commenced.

Although classified as a back-arc basin,

the position of the Kutei basin on the edge

of what was the passive Sunda shield margin

belies an origin closely associated with

rifting in the Makassar Straits. Basin

development throughout the Neogene was

dominated by isostatic sag as a result of

sediment loading, a mechanism observed in

other Neogene rift systems (e.g., Gulf of

Suez – Sellwood and Netherwood, 1985).

As for the East Java basin, stratigraphic

nomenclature is confusing with a large

number of operators having developed their

own lithostratigraphic schemes. The scheme

used here (see Figure 5) was originally

published by the Indonesian Petroleum

Association (Courtney et al., 1991) but has

been modified. The major Neogene deltaic

petroleum system has generated over

11 BBOE in proven reserves. The thick pile

of Neogene deltaics provide source rocks

(delta-top and delta-front coals and shallow-

marine coaly shales – Figure 34); carrier

beds (channel sands); and Miocene–Pliocene

Balikpapan, Kampung Baru and Mahakam

formation reservoir facies that include

channel and mouth-bar sands and, more

recently discovered, delta-front turbidite

systems (Figure 35).

Overview of Indonesia’s oil and gas industry – Geology204

0 20km

Sangatta

Kerindingan

Melahin

Serang

AttakaSemberah

Lampake

Pamaguan

SangaSanga

Mutiara

Handil

BekapaiNW

Peciko

Nubi

Sisi

Tunu

Badak

Nilam

Tambora

Beras

Samboja

Yakin

Sepinggan

Wailawi

Santan

Upper Miocene

Middle Miocene

OligoceneSource kitchen> 2000 isopach

Lower Miocene

Figure 33: Summarygeological map of thelower Kutei basin, withfield locations andthickest (>2000 ft)kitchen areas (fromBates, 1996 andPaterson et al., 1997).

Figure 34: Kerogendominated by vitriniteand cutinite extractedfrom Miocene oil- andgas-prone shales in theKutei basin. (Photocourtesy of S. Noon.)

Page 33: Geology

Overview of Indonesia’s oil and gas industry – Geology 205

Bedding

Way-up

Coalyshale

Coalyshale

Crevasse Splay

PSB PSBPSB

PSB

Upper channel

Shale plug

Coal

Epsilon x-beds

Lower channel

8443

8446.5

cm0

1

2

3

0

1

in

cm0

1

2

3

0

1

in

Figure 35a: Thick (10s m) coralline limestones are developedin the Miocene Mahakam section and demonstrate reservoirpotential. These core segments are from the Serang field anddemonstrate good, visible moldic porosity (Photo fromSiemers et al., 1993a.)

Figure 35b: A thick (approximately 3 m) massive and extensiveturbidite sheet sand enclosed in shale. Turbidite fans have recentlybecome the focus of exploration in deep water offshore from theMahakam Delta following Unocal’s Merah Besar and West Senooil discoveries. (Photo courtesy of J. Decker.)

Figure 35c: Fourstacked, delta-front,coarsening upwardsparasequences. Shalespass up into thinlylaminated and/orbioturbated sandstonerepresenting mouthbars. (Photo courtesy ofP. Montaggioni.)

Figure 35d: A thin but laterally extensive crevasse splaysand enveloped in coaly shales. Larger crevasse splay sandsmay be areally extensive, but are only minor reservoir faciesin the Mahakam Delta. (Photo courtesy P. Montaggioni.)

Figure 35e: Stacked distributary channels withoverbank shales and a 1-m thick coal seam. Large-scale epsilon cross-beds represent lateral accretion,and both channels display erosional bases. (Photocourtesy of P. Montaggioni.)

(b)

(e)

(a)

(d)

(c)

Page 34: Geology

These reservoir facies have analogs on

the modern Mahakam Delta (Figure 36).

All the major oil and gas fields in the

productive Samarinda area are located on

northnortheast–southsouthwest-trending,

faulted anticlines of the Samarinda

anticlinorium (Figure 37).

The deltaic source facies are both oil-

and gas-prone; more liptinitic or drifted

coals and carbonaceous shales in estuarine

or shallow-marine settings are more oil-

prone; and upper coastal plain and pro-

delta marine shales are more likely to be

gas-prone, according to Thompson et al.

(1985). Other authors consider Miocene

Mahakam (and Tarakan) coals to be strictly

oil-prone (e.g., Schoell et al., l985; Oudin

and Picard, 1982). Ferguson and McClay

(1997) consider the gas in the Badak field

to be the product of oil cracking during

late-stage, deep burial of the reservoir into

the gas kitchen.

Work by Peters et al. (1999) classified

Mahakam source facies in sequence

stratigraphic terms and resolved the problem

of source for the deepwater West Seno,

Merah Besar and Panca 1 oil discoveries with

the identification of a deep-marine ‘lowstand’

oil group. According to Peters et al. (1999)

these lowstand fan-reservoired oils originated

from similarly deposited, deep-marine,

lowstand, coaly shales which range in age

from early to late Miocene.

Stage I. Syn-rift(middle–late Eocene)

It is now generally agreed that the Kutei

basin was initiated in the middle Eocene

(e.g., Feriansyah et al., 1999; Moss and

Chambers, 1999), with an extensional rift

phase associated with incipient sea-floor

spreading in the Makassar Straits. The half-

grabens that developed at this time filled

with middle to late Eocene syn-rift

sediments, including conglomeratic alluvial

fans of the Kiham Haloq formation,

equivalent to the lower Tanjung formation

of the Barito basin.

Further to the east, thick, deep-marine,

Mangkupa formation shales and turbidites

are dated, on the basis of foraminifera, as

mid–late Eocene. In between the alluvial

and open-marine facies, deltaic sediments of

the Berium formation were deposited and

include coals, channel sands and

carbonaceous shales.

The syn-rift sediments have long been

considered as being potentially hydrocarbon

bearing. Guritno and Chambers (1999)

proved this potential in the northern part of

the onshore Runtu PSC. Between 1997 and

1998 Tengkawang 1 was abandoned as a

gas-condensate discovery with oil shows,

and Maau 1 and Wahau 1 were plugged and

abandoned with oil shows. Hydrocarbons

are reservoired in poor-quality deltaic sands

of the upper Eocene Berium formation, and

are sourced from intra-formational ‘coaly’

sediments. The location of better quality

reservoir sands may well lead to significant

syn-rift discoveries.

Overview of Indonesia’s oil and gas industry – Geology206

Pembulananticline

Tenggaronganticline

Belayantrough

Katuduanticline

Murunganticline

Pembulananticline

Tenggaronganticline

Sebuluanticline

Separianticline

Semberahanticline

Badaktrend

Sebuluanticline

Semberahanticline

Prangatthrust

Separianticline

outcrops

Badak/Nilamanticline

Present-dayMahakam delta

PlioceneUpper MioceneMiddle Miocene

Lower Miocene

EW

0 10km

Figure 37: Geologicalcross-sections throughEast Kalimantan. Top:regional cross-sectionacross the Kutei basin.Bottom: geologicalcross-section of theSamarindaanticlinorium. (Allenand Chambers, 1998.)

Area of lower

photograph

Distributarychannels

Tidalchannels

Mouthbars

Tide-dominatedinterdistributary

zone

Distributarychannel

Tidal channel

Sea

Distributary

channels

Mouth bar

Tidal

channels

Figure 36: Modem Mahakam Delta distributarychannel and mouth-bar reservoir analogs. (SLRimage from Allen and Chambers, 1998, photoscourtesy of P. Montaggioni.)

Page 35: Geology

Stage II. Sag(late Eocene–early Miocene)

During the late Eocene, basin deepening

produced marine conditions throughout.

The marine Antan and Kedango formations

(also known as the Ujoh Bilang formation)

were deposited through the Oligocene and

include both turbidites and carbonates.

Renewed extension and uplift of the basin

margins occurred in the late Oligocene (e.g.

Feriansyah et al., 1999), but deep-marine

conditions persisted in the center of the

basin with turbidite and deep-marine shales

being deposited. At this time carbonates

were more widely developed on the basin

flanks and basement highs.

In the southwest corner of the basin,

these Batu Hidup formation (Berai

formation equivalent) carbonate buildups

are the gas reservoir for the subeconomic

Kerenden gas field (Van de Weerd et al.,

1987). This represents the only hydrocarbon

discovery in the upper (western) Kutei

basin. The major hinge zones to the south

(Arang fault zone) and to the north

(Bangalon lineament and the Sangkulirang

fault zone) also developed at this time.

Stage III. Deltaic(early Miocene–Recent)Early Miocene deepwater conditions

persisted in the basin center and carbonates

continued to develop on the basin flanks

prior to the onset of late–early Miocene

inversion, when uplifted Eocene and

Oligocene sediments were eroded and a

major delta system formed in the west and

prograded to the east. Prior to this event

the older Mahakam sands were dominated

by volcanic and meta-sedimentary material,

but recycling of the earlier Tertiary

sediments saw an increase in the

compositional maturity of the deltaics.

The lower Miocene deltaics are over

3500 m thick and were buried rapidly, which

led to overpressuring. The deltaic interval is

folded and faulted by northnortheast–

southsouthwest-trending anticlines that

contain bathyal shales in their cores and

shallow deltaics on their flanks, and which

may have started to form in the late–early

Miocene (Allen and Chambers, 1998).

Chambers and Daly (1995) proposed an

inversion tectonic model for the Samarinda

anticlinorium, with anticlines representing

detachment folds (see Figure 37) over

variably uplifted and overpressured bathyal

sediments. Deltaic sedimentation continued

into the middle and late Miocene, punctuated

by compressional deformation, uplift and

erosion in response to basin inversion.

Each inversion episode led to deltaic

progradation. By the beginning of the

middle Miocene, there was initial rapid

progradation of the delta, sediment being

supplied by incision of the Mahakam River.

There was also progressive development

from west to east of syn-depositional folds,

the initial structural expression of the

present-day anticlines (Allen and Chambers,

1998). Section balancing by Ferguson and

McClay (1997) indicates a change from

extension to contraction that started at

about 14 mybp, within the middle Miocene.

At the start of the late Miocene, major

outward building of the delta took place as a

result of an inversion pulse causing

increased sediment supply.

The middle–late Miocene also represents

the period when delta-plain to delta-front

coals and carbonaceous shale source rocks

(with total organic carbon of 20%–70%) for

the Mahakam hydrocarbons were deposited

(Paterson et al., 1997). Paterson et al.

(1997) defined the top of the effective

kitchen as the start of significant

hydrocarbon expulsion rather than

generation, and the base as the top of the

main overpressure zone. The source kitchen

is up to 1000 m thick and covers a

significant portion of the middle–late

Miocene paleo-depocenter. It is located

immediately below the stacked-channel and

shallow-marine reservoirs in the eastern

part of the Samarinda anticlinorium.

Further to the west in the Samarinda

anticlinorium there are no oil or gas

discoveries, reflecting a greater distance

from the miocene source; more significantly,

the northnortheast–southsouthwest striking

anticlines have prevented westerly

migration of hydrocarbons.

Compressional folding continued

throughout the Pliocene and Pleistocene

and formed the long, sinuous, subparallel

anticlines that have trapped hydrocarbons

in the predominantly deltaic Miocene to

Pleistocene Balikpapan, Kampung Baru and

Mahakam formations.

Overview of Indonesia’s oil and gas industry – Geology 207

Tarakansub-basin

Vanda 1

EastVandahigh

May

neFa

ult S

y ste

m

0 50 100km

Quaternary

Neogene

Paleogene

Oil field

Cretaceous

Pre-Tertiary sediments with some igneous rocks

Gas field

Igneous rock

Zone of shalediaprism and

thrusting

Semporna fault

MangkalihatPeninsula

Neogene carbonatecomplex

Muarasub-basin

200

m

1000

m

South China Sea

Kalimantan

Latihanticline

Berausub-basin

Tarakanarch

Bunyuarch

SempornaPeninsula

200 m1000 m

Ahusarch

Tidungsub-basin

Sebatikarch

Sembakungfield

Bunyu Tapa field

Bunyu fieldJuata field

Pamusian field

Bangkudulis field

South China Sea

Maratua fault

Intrusive

Neogeneextrusive

Figure 38: Generalizedgeological map of theTarakan basin (fromLentini and Darman,1996, withmodifications fromNetherwood andWight, 1993).

Page 36: Geology

The Samarinda–Mahakam area of the

Kutei basin is considered to be mature, and

all large anticlinal structures have been

drilled. There is still the possibility of

smaller stratigraphic and fault traps, but

these are notoriously difficult to find in the

Mahakam area where individual reservoir

sands may be of limited extent, and are

multiple-stacked and commonly not

interconnected.

The latest successes have been in the

pro-delta Makassar Strait area where

Miocene, lowstand, turbidite fans host

significant oil discoveries (e.g., West Seno,

Merah Besar fields). These fan systems are

easily identified on seismic (Baillie et al.,

1999) and are even more prospective with

the recognition of associated deep-marine

source facies and adjacent mature kitchen

areas (Peters et al., 1999). Large, pro-delta

carbonate buildups are known to exist and

smaller, shelfal, delta-front carbonates have

been considered as potential reservoirs in

the past (e.g., Siemers et al., 1993a). There

are also further possibilities in the syn-rift

clastics (as illustrated by Guritno and

Chambers, 1999) and in Oligocene

carbonates (e.g., Kerenden gas field)

particularly toward the basin margins.

Tarakan basinThe Tarakan basin (see Figure 38) is located

in the far northeast of the island of Borneo

and represents a passive deltaic margin

where the Sesayap and other rivers transport

fine-grained sediments into the northern

Makassar Strait. There are 14 oil and gas

fields in the basin and most of the largest

were discovered prior to World War II.

The basin is dominated by a series of

northwest–southeast trending, sinistral

transform faults and similarly trending

anticlines that help divide the onshore and

shallow-water parts of the basin into four

sub-basins. To the northeast, magnetic

lineations indicate the opening of the Sulu

Sea (Lee and McCabe, 1986) and to the

southeast, subduction of the Celebes Sea

occurs beneath the north arm of Sulawesi.

To the northwest folding becomes more

intense, with right-lateral, strike-slip

faulting. Further to the northwest near

Sabah, there is complex overthrusting from

the north associated with obduction of

basic igneous rocks at the western end of

the Sulu island arc (Netherwood and

Wight, 1993).

The four sub-basins, from north to

south, are:

• The Tidung sub-basin, bounded to the

north by the major sinistral transcurrent

Semporna fault zone and to the south by a

carbonate platform. It contains a number

of northwest–southeast-trending anticlines

that become more severely folded to the

northwest. There are no drilled

hydrocarbon occurrences in the sub-basin.

• The Tarakan sub-basin, occupying the

central area of the Tarakan basin, and

representing a series of stacked and

amalgamated Pliocene–Pleistocene

depocenters with a thick clastic fill. The

Pliocene wedges-out against Miocene

sediments to the south and west. This

sub-basin contains the producing fields of

the Tarakan basin, which are all located on

the crests of northwest–southeast-

trending anticlines.

• The Berau sub-basin is dominated by a

series of compressional anticlines,

trending northnorthwest–southsoutheast,

and related to the sinistral wrench faults

that have accommodated spreading in the

Makassar Strait.

• The most southerly Muara sub-basin trends

northwest–southeast and is bounded by the

Maratua (wrench) fault system at its

northern margin, and the Mangkalihat fault

to the south. The northern Maratua fault

has produced a basement high on which

the Maratua reef islands are developed.

Seismic studies and drilling indicate more

than 5000 m of Oligocene to Recent

carbonates, syn-rift and passive margin

sediments resting on older volcanic rocks.

In the offshore region major north–south

growth faults, including the main Mayne

fault system, are the dominant structural

control on sedimentation (Netherwood and

Wight, 1993). The distal, offshore

stratigraphy is dominated by abundant

deltaic clastics, and laterally equivalent,

shallow- to deep-marine basinal shales and

local carbonates that have been targets for a

number of unsuccessful wells (e.g., Vanda 1,

Figure 39). In the eastern deep there are

over 2100 m of Pleistocene sediments and

1200 m of Pliocene. The Pliocene is over

2500 m thick in the inverted arches of

Tarakan, Bunyu and Ahus. Landward paralic

intervals contain coals and carbonaceous

shales with abundant type I and type II

kerogens. These may represent a similar

hydrocarbon source to those of the Miocene

Mahakam Delta.

The Miocene has rarely been penetrated.

However, outcrops and the few wells drilled

in the Tidung and Berau sub-basins indicate

thousands of meters of Miocene, as well as

Oligocene and Eocene sediments. The older

sediments are encountered far to the south

in the Muara sub-basin.

Stage I. Syn-rift(middle Eocene–early Miocene)The basin was initiated by rifting of the

Sulawesi Sea, with middle to late Eocene

extension and subsidence and was complete

by the early Miocene. This resulted in a

series of en-echelon block faults dipping to

the east. It is speculated by Lentini and

Darman (1996) that the Eocene rift fill may

contain source rocks.

Overview of Indonesia’s oil and gas industry – Geology208

Figure 39: Vuggyporosity (left andmiddle) developed nearthe top of a carbonatebuildup. Shaly platycoral facies (right) ofthe reef front. Pliocene,Vanda 1 well, Tarakanbasin (Netherwood andWight, 1993).

Page 37: Geology

Overview of Indonesia’s oil and gas industry – Geology 209

Selubur high Natuna Sea

Natuna Island

Laut Island

Sokang trough

Outer basinal area

Komodo graben

Paus-Ranai

ridge

Nat

una

arch

Terumbucarbonateplatform

West Luconiadelta

Penyubasin

Sunda shelf

Boundary highCumi-cumi

plateau

Kakapgraben

KF

KRA 1KH

AI-IX

Malay basin Anoa high

Khoratplatform

Anambas Islands

Mala

ysi

aIn

donesi

a

Tenggol arch

Sotong

Anding

Duyong Centralhigh

Anambas

graben

Bawal graben

Kepiting 1Kelu 1

Sembilang 1 Kodok 1

Kerisi 1

Sepat 1

ForelBawal

BuntaiTembongBelida

TerubukCCE 1

Belut 1Ikan Pari 1

Udang

TabuGuntongTapis

Palas

Pulai

Segili

Anoa

TinggiTiongBekok

Harim

autro

ugh

25 50km0

Bursa 1X

AP 1X

AV 1X

Banteng1&2

Sokang 1

'L' Structure

GPN

S-199

GPN S-125

2000

3000

4000

1000

3000

40004000

5000

4000

200010

00

1000

3000

4000

3000

2000

2000

2000

2000

3000

50004000

4000

4000

5000

5000

4000

3000

2000

1000

2000

3000

4000

5000

6000

6000

5000

4000

5000

6000

6000

7000

5000

4000

6000

3000

5000

4000

1000

2000

2000

3000

4000

2000

2000

20003000

1000

1000

1000

1000

1000

1000

1000

1000

Areas where depth to basement > 4000m

Areas where sediment is < 3000m thick

Oil field/discovery

Gas field/discovery

Terumbu carbonates – Miocene

Figure 40: Morphological division, tectonic lineaments andhydrocarbon occurrences in the Natuna Sea area (after Fainsteinand Meyer, 1998 and Phillips et al., 1997).

Figure 41: Playconcepts for WestNatuna basin (afterFainstein and Meyer,1998).

0

Dept

h, m

NW SE

1000

2000

3000

4000

0

1000

2000

3000

4000

Muda formation Muda formation

Arang formationArang formation

Gabus formation Gabusformation

Barat formation

Baratformation

Pre-Gabus

West Natuna basin – Line GPNS-125

Syn-riftsediments

Syn-riftsediments

Inverted half-grabens containinglacustrine and marginal

marine source rocks

Inner Arang unconformity

Dept

h, m

Page 38: Geology

Stage II. Sag(middle Miocene–Pliocene)

Subsidence and the development of

north–south listric growth faults and deltaic

fill characterize this stage.

Stage III. Inversion(Pliocene–Recent)As with most basins in Indonesia, late

Neogene compression produced inversion

and structuring. There was reactivation of

transform movement along wrench faults

crossing the Makassar Straits, and

transpression resulted in the large

southeast-plunging anticlines that host all

the known fields. Lentini and Darman

(1996) suggest between 1000 and 1500 m of

inversion during this period.

Oil was first discovered in the Tarakan

basin in 1899 (Tarakan field) and since that

time the only sizeable discoveries have been

the Pamusian oil field in 1901 (200 MBO

recoverable) and the Bunyu oil field in 1923

(80 MBO recoverable). The fact that no

other major fields have been discovered

must be considered surprising in such a

large basin with producing hydrocarbons,

well-defined structures, and an extremely

thick section of deltaics for both source

rocks and reservoirs. The basin has a known

Eocene rift sequence and thick Neogene

carbonates. Although information is limited,

it is thought that the hydrocarbon potential

of this basin has not been fully realized.

There is still potential for structural and

stratigraphic traps along the large Bunyu

and Tarakan arches in the Tarakan sub-

basin. One of the major problems with the

proximal deltaic sands to date, however, is

poor reservoir quality, with thin, fine-

grained sands and a poor net-to-gross ratio.

Some of the best opportunities are

considered to be basinward of large growth

faults, on rollover anticlines where

multiple-stacked carbonate buildups occur

with hydrocarbon shows (Netherwood and

Wight, 1993). Opportunities may also be

possible in the lowstand fans that spill off

the fronts of growth faults, such as those

proven to contain oil in the Makassar

Straits. Other opportunities include

possible sourcing from deeper syn-rift

sediments and possible large carbonate

reservoirs in the south of the basin.

West Natuna basinThe West Natuna basin forms the eastern

part of the largest basin system within the

Sunda shelf. This system includes the Malay

basin and the basins in the Gulf of Thailand.

The principle tectonic elements of the West

Natuna area include three subbasinal

provinces, the northwest–southeast-

oriented extension of the Malay basin, the

northeast–southwest-oriented Anambas

graben, and the east–west-oriented Penyu

graben (Figure 40). These sub-basins were

initiated as early Tertiary rifts and are

separated by major structural highs,

including longstanding plateau areas such as

the Renggol arch and Cumi-Cumi high, that

were inverted in the mid–late Miocene.

The majority of discoveries have been

made in the post-rift to syn-inversion

sequences (Gabus/Udang to Arang

formations). Significant discoveries have

also, however, been made in the syn-rift

pre-Gabus sequence (Figure 41). The KRA

field, brought on stream in 1995, represents

the first production in the area from

Paleogene syn-rift sediments. To date

approximately 500 MMBO and 2.5 TcfG have

been discovered in the basin.

Stage I. Syn-rift (late Cretaceous–early Oligocene)The exact timing of rift initiation is

uncertain. It may have been as early as the

late Cretaceous, although the more probable

timing is late Eocene to early Oligocene

when complex graben and half-graben

systems developed as a result of the

collision between the Indian subcontinent

and the Asian plate. The northeast–

southwest-oriented Anambas graben is the

largest, but equally productive is the

smaller, northwest–southeast-oriented KF

half-graben, located near the Indonesia–

Malaysia international divide.

The rift fill sediments are continental and

include red beds, lacustrine shales and

coals, fluvial sands and stacked fan deltas

(the KRA field reservoirs) of the Belut

formation (Fainstein and Meyer, 1998). The

rift sequence in the West Natuna area is also

referred to as the Benua/Lama formation.

During rift initiation, sedimentation

probably kept pace with subsidence and the

areally restricted, incipient half-grabens

were filled with mainly fluvial deposits

(Phillips et al., 1997). As rifting progressed,

subsidence increased and deep lacustrine

shales were deposited. These are the main

source facies with an algal-dominated

kerogen assemblage including Botryococcus

and Pediastrum (Figure 42) and with total

organic carbon values in excess of 5%.

During relative lowstands, fan-deltas

episodically built-out into the lakes from

uplifted rift margins. Turbidite sands may

well be developed in front of these

fluvial/alluvial sedimentary piles. Locally, as

in the KF half-graben, the late syn-rift phase

was characterized by widespread, open-

lacustrine and lacustrine-plain

environments, resulting in the deposition of

massive, sealing shales (Benua formation).

Elsewhere, sedimentation outpaced

subsidence progressively filling the rifted

depocenters with large-scale lacustrine

deltas (Phillips et al., 1997).

Overview of Indonesia’s oil and gas industry – Geology210

Figure 42:Chlorococcalean typealgae, Pediastrum,typical of lacustrinesource rocks inWestern Indonesia,Oligocene, WestNatuna basin (photocourtesy of S. Noon).

Page 39: Geology

Stage II. Post-rift (late Oligocene–early Miocene)

The late Oligocene–early Miocene is

characterized by deposition of fluvio-

lacustrine sands, shales and coals of the

Gabus formation. Gabus sands are the main

reservoirs in the West Natuna basin. They

were deposited as incised-valley fill and

lowstand shoreline sands (Phillips et al.,

1997) and can attain a thickness of over

200 ft. These include rift-margin deltaic

and fluvial sands (e.g., Forel and KF oil

fields) and thicker, braid plain and braid

delta deposits (e.g., KH, KG, Belida,

Udang, Belanak and Sembilang fields).

Gabus formation shales and coals can

demonstrate good source potential,

although they only locally reach maturity

in deeper parts of the basin. In the south of

the basin the upper Gabus is known as the

Udang formation.

Towards the end of the Oligocene a major

‘wet’ or lacustrine cycle, the Barat

formation, was deposited across the basin.

It is shale-dominated and shows some

marine influence. The shales are typically

organically lean, but this unit forms an

important semi-regional seal to the

underlying Gabus formation.

Stage III. Syn-inversion (early Miocene–late Miocene)

In the early Miocene, compression and

wrench faulting marked the initiation of

inversion. Many of the proven and

prospective structures in the area were

formed during this tectonic phase. The

change in tectonic stresses in the area,

from relative extension to compression, is

due, at least in part, to the onset of seafloor

spreading in the South China Sea. Global

eustatic rise at this time is recorded locally

by the establishment of marine and

marginally marine (paralic) environments

in the Arang formation. Sedimentation was

dominated by shales, with abundant coals

and subordinate sands. Significant

reservoirs are, however, developed, such as

the tidally influenced sands of the lower

Arang (or Pasir) formation, which are

productive in the Belida, KH and KG oil and

gas fields. The coals and shales developed

in the Arang formation are commonly oil-

and gas-prone but, like the Gabus, are

generally considered not to have been

buried deep enough to generate

hydrocarbons. The exception to this is in

the central Malay basin which has

continued to subside differentially through

the Miocene to Recent.

The last main pulse of inversion occurred

in the middle to late Miocene. Orthogonal

compression together with

northwest–southeast-oriented, strike-slip

tectonics were accommodated by

deformation along both the major graben

bounding faults as well as a series of

northwest–southeast striking wrench faults

that transect the area. This resulted in the

formation of structural highs where

depositional lows had previously existed,

and significant erosion of the syn-inversion

and post-rift sequences. The erosion of the

former grabenal areas created a suite of

often large, anticlinal structures across the

West Natuna basin. These structures are

referred to as Sunda folds and have been an

important exploration objective.

In the Anambas graben area, the major

anticlinorium termed the boundary high is a

product of pulsed Miocene inversions. Oil

and gas accumulations are proven in the

Sunda fold family of inversion structures

(e.g., the KF and Anoa fields). Significant

hydrocarbon accumulations are also located

in structures associated with the right

lateral wrenching (e.g., KG and KRA in the

KF half-graben, and the Udang, Forel and

Belanak fields).

Overview of Indonesia’s oil and gas industry – Geology 211

Figure 43: Playconcepts for EastNatuna basin(Fainstein andMeyer, 1998).

SE

0

1000

2000

3000

4000

5000

0

NW

1000

2000

3000

4000

5000

Bursaoil discovery

'L' structureNatuna gas field

Muda formation

Arang formation

Arang formation

Arangformation

Gabus formation

Gabus formation

Gabusformation

Gabusformation Pre-Gabus

Pre-Gabus

Pre-Gabus

Kitchenfor 'L' structure

gas

Source of hydrocarbonsprobably lower Arang

and Gabus shales

Supergiant'L' structure

45TcfTop-oil window

Top-gas window

East Natuna basin – Line GPNS-199

Dept

h, m

Page 40: Geology

Stage IV. Post-inversion (late Miocene–Pleistocene)

The Muda formation, a regional seal, is

dominated by marine shales that were

deposited during subsidence and

transgression from the late Miocene

onwards. Associated gas-charged sands in

the Muda formation have long been avoided

by drillers, but were upgraded from a

drilling-hazard to a potentially economic

shallow gas play by Bennett (1999).

In many areas, post-inversion subsidence

has been insufficient to reactivate the syn-

rift kitchen areas that were ‘switched-off’

due to uplift and inversion. In the Malay

basin province, however, Pliocene–

Pleistocene subsidence has been substantial

and coincident with increased heat flow

(possibly due to crustal thinning), resulting

in hydrocarbon expulsion from the younger,

post-rift Gabus and Arang source rocks. At

present, heat flow remains high and the top

of the oil- and gas-windows are on average

about 2500 and 4800 m, respectively

(Fainstein and Meyer, 1998).

The West Natuna basin is still considered

to be prospective with many areas relatively

underexplored. There is good potential

within the deeper syn-rift sediment package

where thick reservoirs are adjacent to

generating source rocks and may be sealed

by lacustrine and peri-lacustrine shales.

The potential of this play type is proven

in the KRA oil field. The post-rift and syn-

inversion succession contains abundant high

quality reservoir sands with associated

source rocks throughout and, with a

relatively high geothermal gradient of

3.72°C/100 m, the potential for expulsion

and short-range migration into inversion

related structures is high. Shallow gas in the

Muda formation is also a new play concept

that holds promise.

East Natuna basinThe offshore East Natuna basin is separated

from the West Natuna basin by the Natuna

arch (see Figure 40) and extends to the

east into the Sarawak basin off western

Borneo. Unlike the West Natuna basin, it

was not subjected to a major phase of

Miocene inversion and is, therefore,

structurally quite different (see Figure 43).

The East Natuna basin can be divided

into a number of discrete structural

elements defined by depressions and highs

in the basement of Cretaceous granites and

metasediments (Figure 44). The Sokang

trough in the southwest of the basin and

immediately to the east of Natuna Island

contains over 6000 m of Tertiary sediments

and is separated from the main basin by a

structural high, the Paus ridge. To the north

of the Paus ridge the narrow north–south

oriented Komodo graben contains over

5000 m of Miocene clastics. The Terumbu

Overview of Indonesia’s oil and gas industry – Geology212

UpperCamba/

Baturarevolcanics

LowerCamba

Tonasa

Malawa

Langivolcanics

Buavolcanics

Walanae

Tacipi

Enrekangvolcanics

Buakayu

Makale(Tonasa)

Toradja

Latimojong

Age uncertain

+

+

++

+

+

Celebesmolasse

Upper platformand reefal limestones

Clastic coal unit

Lowerplatform

limestone

Basal clastics

Not presentin Tomori wells

Unnamedbasement

FufaWahat

Salas complex

Upper Nief

Lower Nief

Kola shale

Manusela

Saman-Saman

Kanikeh

Kobipoto Tehoru

+

++

+

++

Sele

Klasaman

Klasafet

Kais Kais

Sirga

Faumi

Imskin/Waripi

Granite?

Kembelangan

Tipuma

AinimAifat

Aimau

Salawatigranite

Kemummeta-sedimentary

Klamogun

?

Sele

Steen kool

KlasafetSeka

Sago

Kais

Sirga

Onin

(Baham)

Imskin

Kembelangan

AinimAifat

Aimau

Kemum meta-sedimentary

Tipuma

Viqueque

Batu Putih

Ofu formation

Monu

Naktunu

Oe Baat

Wai Luti

BabuluAifulu

Niof

CibasMaubisso

Atehoe

Barracouta(Woodbine group)

Oliver

Cartier

Prion & Hibernia

Grebe/PuffinJohnsonWaingalu

AshmoreDarwin

Flamingo

Plover

Malita

Cape Londonderry

Mount Goodwin

Hyland Bay

Fossilhead groupKulshill group

Weaber groupArafura group

Goulburn groupWessel group

Woodbine group

Waingalu

Flamingo group

Kulshill group

Weaber groupArafura group

Goulburn groupWessel group

After Wilson et al., 1997,Coffield et al., 1997.

Davies, 1989. Kemp, 1993, 1995.Livingstone et al., 1993,

Fainstein, 1998a,Lunt & Djaafar, 1991.

Lunt & Djaafar, 1991,

Fainstein, 1998a.

After Sawyer et al., 1993, Fainstein, 1998a, 1998b,Young et al., 1995, Sani et al., 1995.

5

15

20

30

40

50

60

657080

100

150

200

250

300

400

500

Sulawesi Seram West Irian Jaya

Salawati Bintuni

Timor regionWest Timor

(limited information)Bonapartebasin (ZOC)

Arafura Sea(limited information)

Southwest

Quat.Holo.Pleist.

Late

Early

Late

Mid

dle

Early

Uppe

rEa

rlyLa

teM

iddl

eEa

rly

Paleocene

Late

Early

Late

Middle

Early

Late

Tria

ssic

Jura

ssic

Perm

ian

Pale

ozoi

cM

esoz

oic

Cret

aceo

usPa

leog

ene

Neo

gene

Eoce

neOl

igoc

ene

Mio

cene

Plio

cene

Ceno

zoic

MiddleEarlyLate

Early

Carboniferous

Devonian

Silurian

Ordovician

Cambrian

Precambrian

West-central Tomori(limited information)

Figure 44: Summary of basin stratigraphy in Eastern Indonesia.

Page 41: Geology

shelf in the north has developed between

2500 and 4000 m of Neogene cover that

includes up to 1500 m of Miocene to

Pliocene Terumbu formation carbonates.

The outer basin (Bunguran trough) dips

east towards Sarawak and contains over

10,000 m of sediments.

The East Natuna basin is well known as

being the host for the largest gas field in

Southeast Asia, the Natuna Alpha gas field,

with 210 TcfG in an isolated buildup in the

upper part of the thick, middle Miocene to

late Pliocene Terumbu carbonates.

Progressive, relative sea-level rise over a

period of nearly 2,000,000 years allowed the

build up of over 1500 m of carbonates.

Episodic exposure has created and

preserved an average porosity of 15% for

the five wells drilled to date. Unfortunately

71% of the gas is carbon dioxide (Dunn et

al., 1996) and, as such, estimated

recoverable reserves are 45 TcfG.

Stage I. Syn-rift(late Cretaceous/Paleocene–early Miocene)

Northwest–southeast-oriented rifting may

have started as early as the late Cretaceous

(Dunn et al., 1996) and continued through

the Oligocene and into Miocene times.

Seafloor spreading occurred to the north in

the South China Sea during the later

Tertiary. The specific divide between actual

rifting due to plate collision to the west, and

rapid subsidence due to seafloor spreading

to the north, was at the base of the middle

Miocene. Syn-rift lithostratigraphic

nomenclature is similar to that of the West

Natuna basin, the Gabus and Barat

formations comprising basal fluvial and then

transgressive paralic and marine deposits,

including sands, silts, shales and coals.

These sediments have been identified as a

mature source for the Natuna Alpha gas and

contain potential reservoirs of excellent

quality (Dunn et al., 1996).

Stage II. Post-rift (middle Miocene–middle Pliocene)

At the base of the middle Miocene, the

extensional, rift-generated fault-block

terrane started to subside due to rifting and

spreading of the Borneo margin. Terumbu

formation carbonate buildups developed on

the normal-faulted basement highs at the

eastern edge of the Natuna arch. Three

recognized cycles of carbonate growth relate

to changes in relative sea level. In deeper

water, shales were deposited coincident with

the shallow platform carbonates.

In the Natuna Alpha gas field, carbonate

growth ended at the base of the Pliocene due

to subsidence associated with loading by an

orogenic front and an accretionary prism in

northwest Borneo (Dunn et al., 1996).

Elsewhere, Terumbu carbonate growth

continued into the basal Pliocene and the top

of the carbonate sequence was exposed by

eustatic sea-level fall in the early to middle

Pliocene with resultant solution

enhancement of porosity.

Stage III. Subsidence (middle Pliocene–Pleistocene)Foundering of the East Natuna basin

resulted in the sealing of the carbonate by

deep-marine shales. Elevated geothermal

gradients, as seen throughout Western

Indonesia at this time, matured the Arang

formation source rocks.

The East Natuna basin is relatively

underexplored but the potential for further

large gas discoveries in the Terumbu

carbonates is low because most buildups

have been drilled. These include the Pliocene

Bursa-1 and AP-1X subeconomic oil and gas

discoveries. The earlier syn-rift clastic plays,

however, require more serious consideration,

with proven hydrocarbon generating

capabilities and thick, high-quality sands.

Basins of Eastern IndonesiaThe petroliferous basins of Eastern

Indonesia are geologically different from

those in the west of the archipelago. In fact,

in many cases they cannot strictly be

classified as basins, and include complex

fold belts and even thrust belts that are

elevated to such an extent that commercial

hydrocarbon pools at subsurface depths of

2500 m may be underpressured (e.g., the

Oseil oil field in Seram).

Geological differences to the basins of

Western Indonesia include a Paleozoic and

Mesozoic sedimentary history older than the

Jurassic breakup of the Gondwana

supercontinent. Mesozoic sedimentation

resumed after continental breakup, and

there was a noticeable change in

sedimentary style starting in the Neogene

(Figure 44). These pre-Tertiary and early

Tertiary stratigraphies are near-copies of the

Northwest shelf of Australia. They prove

that the multitude of highly rotated and

deformed fragments making up many of the

islands of Eastern Indonesia, from eastern

Sulawesi to Irian Jaya, were part of the

Australian craton. Recently, pre-Tertiary

sequences have started to reveal their true

value with the discovery of commercial

hydrocarbon accumulations and also

prolific, entirely Mesozoic petroleum

systems. The only explored area of Eastern

Indonesia that does not demonstrate this

affinity is the western side of Sulawesi,

representing a fragment of the Sunda shield

(Asian plate) that has rifted away from the

edge of Sundaland. Western Sulawesi is

separated from Borneo by attenuated

continental crust in the Makassar Strait to

Overview of Indonesia’s oil and gas industry – Geology 213

Page 42: Geology

the south and by oceanic crust in the Celebes

Sea to the north (figures 45, 46 and 47).

In addition to an Australian plate origin,

the eastern part of Indonesia was ‘close to

the action’ during the complicated collision

events that took place throughout the

Miocene. These include the collision of the

New Guinea passive margin with the

Philippine–Halmahera–New Guinea arc

starting at the very end of the Oligocene

(approximately 25 mybp) and collision of

the Australian plate with the Sunda trough

(Timor trough) and Sunda shield starting in

the late Miocene (about 8 mybp). In

consequence, Eastern Indonesia is

tectonically and structurally extremely

complex, comprising slivers of continental

blocks, arc fragments and trapped ocean

basins (figures 45 and 46). Although many

potential petroleum basins are recognized,

they tend to be small, geologically poorly

understood and, usually, in deep water.

Some 86% of Eastern Indonesia’s basinal

areas are in water depths greater than

200 m (Pattinama and Samuel, 1992) and

the onshore areas are in remote jungle.

Of the 38 Paleozoic to Tertiary-age

sedimentary basins identified in Eastern

Indonesia, 20 remain undrilled and many

that have been drilled are underexplored.

Although the basins of Eastern Indonesia

may never prove to be as prolific as the

back-arc basins of Western Indonesia, the

fact that only 5 MMBOE have been

discovered to date compared with Western

Indonesia’s 50 MMBOE is viewed as a

reflection of the explorationist’s reticence,

rather than the region’s true potential.

Interest has only recently been rekindled

by more favorable frontier exploration terms

and a number of commercial and, in one case

giant, hydrocarbon discoveries in the

Mesozoic section of Eastern Indonesia. These

recent discoveries include the Oseil oil field

undergoing development by Kufpec in the

Jurassic of Seram; the giant (over 20 TcfG)

Tangguh gas project of Arco and British Gas

in the Paleogene and Jurassic section of the

Bintuni basin, western Irian Jaya; and a

string of oil and gas-condensate discoveries

including Elang, Kakatua, and Undan-Bayu in

Overview of Indonesia’s oil and gas industry – Geology214

Sorong fault

AUSTRALIAN PLATETimor trough

Timor

Sumba

Flores

Buru

Irian Jaya

Seram

Salawatibasin

EURASIAN PLATE

Mo

lucca S

ea

Sulawesi

PACIFICPLATE

PHILIPPINESEA PLATE

Band

aar

ch

South Arutro

ugh

Sor ong fault zone

North Banda arch

7cm/year

Banda Sea

Bintunibasin

Legend

Fault

Trend of volcanic inner arc

Continental crust

Subduction zone

Figure 45: Tectonic setting of East Indonesia (modified from Guritno et al., 1996 and Sani et al., 1995).

Celebes Sea(oceanic crust)

Molluca Sea(oceanic crust)

(Mag

mat

ic a

rc)

North arm(Magmatic arc)

East arm

Sula platform(Gondwana continental crust)

Sundaland

South arm

South Eastarm

Tukang Besi platform(Gondwana continental crust)

Banda Sea(oceanic crust with Gondwana-derived continental fragments)

Sulawesi

Buru

Makasa

r st

rait

(att

enuate

d A

sian c

onti

nenta

l cru

st)

Kalim

an

tan

Samarinda

Palu

Ujung Pandang

Kendari

Manado

Mamasa

A A'

Masupu

?

Tiakafield

100 200km0

Halm

ah

era

Oil seepGas seep

LegendOphiolite

Metamorphic rock

Oceanic crust

Continental crust

Paleogene/Neogenesediments

Figure 46: Tectonicsetting of Sulawesiwith origins ofSulawesi fragmentsindicated (fromGuritno et al., 1996).

Australian-derivedProterozoic–Paleozoic

lithosphere

SundalandMesozoic–Cenozoic

lithosphere

Scale vertical = horizontal

Makassar Strait South Sulawesi Bone Bay Southeast Sulawesi Banda Sea

EW

020406080100

km

020406080

100

A A'

x x xFigure 47: Regional cross-section across southernSulawesi continent–continent collision(Guritno et al., 1996).

Page 43: Geology

the Timor Gap zone of cooperation (ZOC)

and, Corallina and Laminaria just outside the

Timor Gap ZOC in the northern part of the

Northwest shelf of Australia.

Four of the main areas in Eastern

Indonesia that have already been targets of

hydrocarbon exploration are Sulawesi,

Seram, Western Irian Jaya and the Timor

Gap ZOC. These areas are discussed below

and although they do not provide a

complete view of the petroleum geology of

Eastern Indonesia, they go a long way

towards defining the stratigraphic and

structural complexities and habitats of

hydrocarbons discovered to date and what

may be expected in the future.

SulawesiSulawesi is a tectonically complex island

with a varied history, and comprises

fragments of four separate tectonic

provinces (see Figure 46). The northern

arm of Sulawesi is a Recent, active

magmatic arc with poor petroleum

potential. The east and southeast arms

are microcontinental fragments derived

from the northern margin of the

Australian craton, which collided with

western and South Sulawesi – the alienated

southeast edge of Sundaland – starting in

the early Miocene (e.g., Calvert, 1999;

Sudarmono, 1999).

The petroleum potential of Sulawesi has

been suspected for a long time, with oil and

gas seeps recognized onshore in West

Sulawesi. The first successful gas well was

drilled in the Sengkang basin in southwest

Sulawesi by BPM in 1939. Further biogenic

gas was discovered in the Sengkang basin

by Gulf and BP in the 1970s with relatively

small (total 750 BcfG; Wilson et al., 1997)

accumulations trapped in Miocene

carbonate buildups and now being

developed for local power generation. In

addition, significant asphalt deposits are

known from Buton Island, a

microcontinental fragment of Australoid

affinity. This area was also drilled by Gulf

and Conoco from the 1970s to 1990s.

Miocene deltaics and turbidites of the

Tondo formation were targeted,

hydrocarbon shows being sourced from

Triassic, oil-prone sediments containing

type II kerogen (Sumantri and Syahbuddin,

1994). On the eastern arm of Sulawesi in

the Banggai-Sula basin, Union Texas

discovered oil and gas in subeconomic

quantities in fractured Miocene carbonates

(Davies, 1990) during the 1980s and 1990s.

South SulawesiIn parts of South Sulawesi (Kalosi, Lariang

and Karama basins) low-grade, Cretaceous,

metamorphic basement is exposed. This

underwent the same widespread middle

Eocene extension experienced by the rest

of Sundaland.

Rift-fill includes marine marls in the

Lariang and Karama basins (Bone Hau

formation of Calvert, 1999), volcanics and a

series of basal continental siliciclastics

including lacustrine sediments, transgressed

by deltaics including coal, and marine

siliciclastics, known as the Malawa

formation and the Kalumpan formation

(Calvert, 1999) respectively in Southwest

and west Central Sulawesi. The syn-rift fill

provides potential Eocene reservoirs, and

type II and type III kerogen-rich, oil- and

gas-prone source rocks. The Paleocene

volcanics are associated with subduction,

and with mafic to ultramafic ophiolites

obducted in the east. The syn-rift thickness

varies greatly, from less than 100 m to over

1000 m (Guritno et al., 1996) as a result of

basement fault block control (Garrard et al.,

1989). The rift-fill was transgressed by

shallow marine carbonate potential

reservoirs in the latest Eocene, known as

the Rantepau formation (Calvert, 1999) in

west Central Sulawesi and the Tonasa

formation in Southwest Sulawesi. These

algal and larger benthic-foraminiferal

limestones continue up into the middle

Miocene when they were drowned by deep-

marine marls (Berlian formation of Calvert,

1999) in some areas.

The middle Miocene through to the

Pleistocene saw uplift with granite

intrusion and deposition of mainly

volcaniclastics associated with the late

Miocene, continent-to-continent collision

between western (Sundaland) and eastern

(Australia craton) Sulawesi. This has

resulted in extensive overthrusting to the

west, and sinistral transform faulting in the

South Sulawesi area.

The Bone basin, located between the two

southern arms of Sulawesi, is geologically

quite different to the basins of west Central

and west South Sulawesi with their

Sundaland affinities (termed ‘Sundawesi’ by

Fraser and Ichram, 1999). The Bone basin

originated as a fore-arc basin from the

Paleogene to the early Miocene during

convergence of Sundaland with Australia. At

this time coarse clastics spilled into the

basin and rotational forces led to rifting in

the southern part of the basin. The colliding

plates finally locked in the Pliocene and the

Bone basin took on its submerged intra-

montane configuration (Sudarmono, 1999).

All gas discoveries to date in South

Sulawesi have been small (<1 Tcf in the

Sengkang basin) and of biogenic origin, but

the potential for larger thermogenic

discoveries cannot be ignored. Eocene coals

and carbonaceous shales provide a good

potential source for both gas and oil. Eocene

clastics and later Tertiary carbonates show

good reservoir possibilities, with known gas

in Tacipi formation reef knolls. Migration

may have taken place through Eocene

channel sands and vertically along fault

planes, with anticlinal trap development

throughout Neogene times. It is generally

thought that burial was not deep enough to

mature the Eocene source, but Miocene

magmatism and orogenesis may have raised

heat flow resulting in the expulsion of

hydrocarbons, and there are known oil seeps

in the South Sulawesi area.

East SulawesiDavies (1990) published findings of Union

Texas Oil from almost a decade of

exploration in the Tomori PSC of East

Sulawesi, an area referred to geologically as

the Banggai-Sula basin (Sumantri and

Sjahbuddin, 1994). The eastern arm of

Sulawesi comprises two

tectonostratigraphic units – the Banggai-

Sula microcontinental block, a rotated and

extruded part of the Australian plate, and

the east Sulawesi ophiolite belt, thrust over

the former in the early Pliocene.

The pre-collision, Sulawesi, Eocene to

Miocene succession in the area comprises a

thin, basal clastic unit, only 12 m thick

where penetrated, and two thick carbonate

units. The post-collision succession

comprises clastics including claystones,

conglomerates, sandstones and also some

limestones. All hydrocarbon accumulations

discovered to date are in tightly cemented

and stylolitized but fractured carbonates.

They include the small Tiaka oil field in the

Eocene–Oligocene Lower Carbonate unit,

and the small Minahaki and Matindok gas

fields in the Miocene, Upper Carbonate unit.

Although burial is relatively shallow, oils are

light, gas is of thermogenic origin and the

presence of an oleanane fraction from gas

chromatogram mass spectrometry analysis

indicates a Tertiary age source, considered to

be Miocene coals that generated

hydrocarbons in the Pliocene–Pleistocene

during collision with the Sulawesi ophiolite

belt and associated thrusting. Davies (1990)

Overview of Indonesia’s oil and gas industry – Geology 215

Page 44: Geology

also considers that, to the north beneath the

thrust belt, Miocene sediments could be

buried as deep as 5000 m.

Oil and gas are known to exist in this

compressional tectonic regime. Although

information is scarce, there are proven

fractured carbonate reservoirs. It is

possible that in the thrust belt to the north,

more extensive fractured reservoirs in a

similar setting to those found on Seram

(see below) may exist.

SeramSeram is located on the northern rim of the

Banda arc and is a microcontinental

fragment of the Australian plate. It is

situated in a strongly compressional and

overthrusted tectonic setting, with the

Banda Sea oceanic crust and a volcanic

island arc to the south, and the Seram

subduction trough to the north where the

western Irian Jaya segment of the

Australian plate is being consumed beneath

Seram Island (Figures 48 and 49). Oil has

been produced in Seram since 1896, when

the Dutch developed the Bula oil field on

the basis of oil and gas seeps in the

northeastern part of the island. Production

is from Pleistocene clastics and carbonates

of the Fufa formation. More recently

commercial quantities of oil have been

discovered by Kufpec in the Jurassic

carbonate reservoirs of the Oseil oil field

(Kemp and Mogg, 1992; Kemp, 1993;

Kemp, 1995).

Seram is composed of two stratigraphic

series. The Mesozoic to late Miocene

succession is closely related to that of the

Australian plate. The younger succession,

for which deposition was of much shorter

duration, is late Miocene to Recent and

records the sedimentary history of plate

collision and thrust belt generation that

took place over this period.

Overview of Indonesia’s oil and gas industry – Geology216

Seram trough

Australianplate

Figure 48

Australian plate

Banda Sea

(oceanic crust)

Ambonvolcanic arc

Ocea

nic

crus

t

Seram thrust beltThrust belt

foreland basinsAccretionary

wedge and melange

Pre-Triassic

Triassic to upper Miocene

S N

+

+

VV

V

+

+

+

+

+

Figure 48: Schematic geological cross-section throughthe Seram thrust and Seram trough (Kemp, 1993).

Kais

Jurassic

NS

22860

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000

6500

6996

959

959 2286

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000

6500

6996

Line IJ97 - 0193

Figure 49: Detail ofseismic line across theSeram trough(Fainstein, 1998a).

Page 45: Geology

Basement is the Kobipoto or Tehoru

metamorphic complex of Permian to lower

Triassic age. Middle to late Triassic

intracratonic rifting of Gondwana was

marked by deposition of the pre-rift clastic

Kanikeh formation, which contains potential

reservoir sands and coals that could be a

source of hydrocarbons. From the end of the

Triassic through the early and middle

Jurassic, reduced sediment supply and

transgression was marked by deposition of

the Saman-Saman formation, deep-marine

limestones that grade into the Manusela,

shallow-water, oolitic, limestone shoals. The

Saman-Saman calcareous shales and

argillaceous limestones are considered to be

the main source for oil and gas in the

fractured, Manusela limestone reservoirs

(Figure 50) of the Oseil oil field, and are rich

in sulfurous-type II marine algal kerogens.

Continental breakup of Gondwana

eventually occurred in the late Jurassic,

followed by deposition of the upper Jurassic

marine Kola shale. The newly formed,

passive margin sagged with deposition of

the marine limestones and claystones of the

Nief beds in a passive margin setting. This

continued from the early Cretaceous

through to the late Miocene when collision

between the Pacific–Philippine plate and

the Australian plate placed Seram in a

highly compressional, plate-boundary

position. Large-scale thrusting of the pre-

Tertiary over the Nief formation formed

large anticlinal traps in mobile sheets (see

figures 48 and 49). Erosion produced coarse

clastics of the Salas olistostrome and the

Pliocene–Pleistocene Wahat and Fufa

formations. The latter is a reservoir in the

Bula oil field, situated in the thrust front

foreland basin.

In western Irian Jaya at this time,

buckling resulted in subsidence and

deposition of marine shales. Multiphase

expulsion is considered to be quite recent

because Pliocene-Pleistocene reservoir

rocks are filled, unless earlier traps have

been breached.

The production of hydrocarbons since the

late nineteenth century, and the recent

success of innovative plays in the

overthrust, fractured Jurassic Manusela

formation limestones (Figure 51) attest to

the fact that Seram remains prospective.

Proven reservoirs also include the

Pleistocene Fufa formation of the Bula oil

field. Other formations, including the Nief

and even basement, may provide potential

reservoir where fractured.

Western Irian JayaWestern Irian Jaya contains a number of

basins (Figure 51), two of which, the

Salawati and the Bintuni basins, are proven

hydrocarbon provinces. There is very little

released information available for other

basins in western Irian Jaya. The Salawati

and Bintuni basins have, in the past, been

described as mature because the only play

until the end of the 1980s had been Miocene

Kais formation carbonate buildups and, it

was thought that all of these prospects had

been drilled. However, starting with the

Roabiba 1 well drilled by Occidental in 1991

and culminating in the Wiriagar deep and

Vorwata wells, giant gas reserves have been

discovered in the Jurassic and Paleogene of

the Bintuni basin opening up these areas for

renewed exploration efforts. In addition,

new speculative seismic surveys (e.g.,

Fainstein, 1998a) demonstrate the

existence of further, commonly large

Miocene carbonate buildups offshore in the

Salawati basin.

Salawati and Bintuni basinsThe Salawati and Bintuni basins are two

large basinal areas located predominantly

offshore in the southern and western parts

of the “Bird’s Head” peninsula area of

western Irian Jaya. Oil was first discovered

in Miocene carbonate buildups of the Kais

formation in the Salawati basin Klamono

field in 1936, and carbonates of equivalent

age in the Bintuni basin Wasian oil field in

1939. Up until the 1980s these carbonate

buildups had been the only tested play in

Overview of Indonesia’s oil and gas industry – Geology 217

Figure 50: Manuselaformation carbonatesin the East Nief 1 well,Seram. Ooid grainstone(left) with intergranularporosity. Dolostone(right) with modifiedvugular pores andblack residual oil(Kemp, 1993).

0 100km

Seram Island

Wahai basin

Bula

Walio

Mogoi

Wiriagar

Wasian

Wiriagardeep

Vorwata

Roabiba 1Ubadari 1

KasimKlalin

Oseil-1

Bula basin

Misool

Salawati basin

Berau basin

Bintunibasin

Onin

Kumawa

Sorong fault zone

WaigeoWeda basin

Ayamaruplateau

Aiduna fault

Ransiki fault

Yapen fault

Wandam

enfault zone

Lenggurufold

belt

Argunithrust

Sekakridge

Tosem block

Seramtrench

Kepala Burung foredeep basin

Misool Onin anticline

Basins

Continental crust

Middle Miocene igneous rocks

Figure 51: Main structural elements and petroleum basins of Irian Jaya and Seram(after Livingstone et al., 1993, Sutriyono et al., 1997, and Fainstein, 1998a).

Page 46: Geology

the basin. Since the initial oil discoveries a

large number of similar fields in the Salawati

basin (e.g., Walio oil field – Livingstone et

al., 1993) and the Bintuni basin (e.g.,

Wiriagar oil field – Hendardjo and

Netherwood, 1986) have been discovered.

In 1991 Occidental drilled the Roabiba 1

well in the Bintuni basin and discovered gas

in Jurassic sandstones. This opened up a new

play that led to the discovery of the giant

Wiriagar deep-Ubadari-Vorwata gas

accumulations (collectively known as the

Tangguh gas project) in Paleocene turbidites

and Jurassic to Cretaceous Kembelangan

formation fluvio-deltaic sands. British Gas

also drilled through the existing Mogoi oil

field and discovered further gas reserves in

Permian sandstones in the Mogoi deep 1 well.

The Pre-Mesozoic section in both the

Salawati and Bintuni basins comprises a

series of highly folded and metamorphosed

Silurian and Devonian Kemum formation

turbidites separated by a major

unconformity from the Carboniferous to

Permian aged Aifam group. The Aifam

group consists of a thick transgressive

sequence of conglomerates, sands and

shales of the Aimau formation which pass

up into calcareous shales with some

limestones and sands of the Aifat formation.

These were then regressed by shales, sands

and coals of the Ainim formation. Chevallier

and Bordenave (1986) believe that the

Mogoi and Wasian oil fields are sourced

from the Permian Aifat formation shales,

although they note that the overlying Ainim

formation coals demonstrate better source

potential. Davis (pers. comm.) believes that

a Paleocene–lower Eocene Waripi/Imskin

source cannot be ruled out. The Bintuni

basin Jurassic gas reserves are also probably

sourced from the Permian Ainim formation.

There may be, however, input from the

Triassic to lower Jurassic Tipuma formation

which, in the Bintuni basin comprises red

beds but in the Salawati basin is more

marine, and/or contribution from the

Jurassic to Cretaceous lower Kembelangan

group (Davis pers. comm.). The fluvio-

deltaic Kembelangan group represents the

main reservoir for gas in the Bintuni basin

but major erosion also occurred in the

Jurassic to Cretaceous as a result of rifting

during Gondwanaland breakup, and in the

Salawati basin the Kembelangan group is

only locally preserved.

During the Tertiary the Paleocene

Waripi/Imskin formation was deposited. It is

a mixture of carbonates and marine shales

but includes thick turbidite sands in the

Bintuni basin and also a major reservoir

facies for the Wiriagar deep gas field. In the

Salawati area, these sediments are not

present throughout the basin because of a

hiatus that extended from the Triassic to

the early Tertiary.

Carbonates of the New Guinea limestone

group dominate the section from the late

Paleocene to late Miocene. These

predominantly Miocene carbonates are

areally extensive, occurring throughout the

Bird’s Head peninsula and making up the

Overview of Indonesia’s oil and gas industry – Geology218

Figure 53: EarlyMiocene carbonates,Bintuni basin.Dolomitized Kaisformation (left) withexcellentintercrystallineporosity. Mogoiformation planktonicforaminiferalpackstone (right) withfracture porosity.

West Kasimfield

ShaleReefKasim stage

Walio–Jaya stage

Cendrawasia–Kasim Utara stage

U marker

Platform stage

Kais platform

W E

Kasimfield

Jayafield

Cendrawashfield Textularia II

Kasim Utarafield

ShaleArgillaceous Shelf/shoal

limestone

1350

ft 650ft

125ft200ft Reef

Possible earlierreef stage

U marker

Kais platform

Reef stagesN S

Kasimfield

Waliofield Textularia II

Figure 52: Stages inthe development ofthe early MioceneKais formationcarbonate buildups,Salawati basin, IrianJaya (Livingstone etal., 1993).

Page 47: Geology

high peaks of Central Irian Jaya. They

include a thick pile of shallow limestones

and transgressive shales that pass-up into

the main Salawati basin stratigraphic

reservoir, the late Miocene Kais formation

reefal buildups, that demonstrate a number

of stages of buildup growth as a result of

fluctuating relative sea level (Figure 52).

The Kais reservoir in the Salawati basin and

in the Wiriagar oil field in the Bintuni basin

shows good secondary vugular and mouldic

porosity as a result of leaching during sea-

level fall and exposure of the buildup tops.

The Kais locally demonstrates excellent

intercrystalline porosity associated with

dolomitization (Hendardjo and Netherwood,

1986; Figure 53). In the Mogoi and Wasian

oil fields in the Bintuni basin, matrix

porosity is low due to the shaly nature of

the limestones. In these carbonates, a

fracture porosity system (Figure 53)

developed when the anticlinal traps were

formed during the Oligocene. Dolomitization

has also enhanced porosity beneath the oil

leg in these fields.

In the late Oligocene to early Miocene

compression produced northwest–

southeast-oriented folding, high-angle

faulting and reactivation of an earlier

Mesozoic fracture system. This compression

was caused by the collision of the New

Guinea passive margin with the arc system

to the north. Uplift in the north at that time

(O’Sullivan et al., 1995) led to an influx of

clastics represented by the Sirga formation.

Anticlinal traps developed in the Mogoi,

Wasian and Wiriagar oil fields, although the

Wiriagar field is also a stratigraphic buildup

(not to be confused with the underlying

Wiriagar deep Paleogene and Jurassic

reservoirs that demonstrate four-way dip

closure). The Oligocene folds intensify to

the east in the Lengguru fold belt where

they become thrusts and decollement

features. High oleanane biomarkers in the

Salawati oils indicate a Tertiary and

probable Klamogun, deepwater Kais-

equivalent source for these oils (Davis, pers.

comm.), unlike the probable

Paleozoic–Mesozoic or Paleogene Bintuni

basin hydrocarbons.

Late Miocene Klasafet and late Miocene

to Pliocene Klasaman (Salawati basin) and

Steenkool (Bintuni basin) shales act as a

seal to the Kais reservoirs. They reflect the

onset of collision with the Banda arc, which

continued into the Pliocene (Henage, 1993),

and the deepening in the basins that

occurred at this time. During the Pliocene

continued compression resulted in uplift in

the north along the Sorong fault and the

Ayamaru high in Salawati and led to further

erosion and deposition of the Sele formation

coarse clastics. Compression at this time

continued the development of anticlines

oriented northwest–southeast and formed

the left-lateral bounding faults defining

present-day depocenters.

Overview of Indonesia’s oil and gas industry – Geology 219

Timor Is

land

Dili

Kupang

Darwin

Central basin

Southern range

Benabasin

Besi-Kamabasin

Viqueque basin

Northern

range

Ashmoreplateau

Londonderryhigh

1

2

4

3

5

6

7 8 9

10

Vulcan gra

ben

Vulcan

Sub basin

West Sahul sync

Sahul

platform

Malitagraben

Petrelgas field

Tern gas field

Petrelsub-basin

Bonapartebasin

Australia

Bathurst

Island

Tanimbar

Island

Darwinshelf

Troubadour 1

Sunrise 1

Flamingohigh

Kelphigh

West Arafura

Sea

Indonesia

Australia

Indonesia

Australia

Timor trough

East Sahul sync

Mature sediments

Cretaceous (Bathurst Island group)

Late Jurassic early Cretaceous (Flamingo group)Triassic-mid-Jurassic Mount Goodwin and Plover formations

Oil seep

Oil field

Gas seep

Gas field Zoc-C

Zoc-A

Zoc-B

Indonesia–Australiazone of cooperation

0 100 200km

Oil fields1. Puffin2. Skua3. Oliver 14. Jabiru5. Challis

6. Corallina7. Laminaria8. Kakatua9. Elang10. Undan/Bayu

Figure 54: Structural map and hydrocarbon occurrences in the Northwest shelf area, including the Timor Gap zoneof cooperation, Timor Island and West Arafura Sea (after Fainstein et al., 1996b and Sawyer et al., 1993).

Page 48: Geology

Other basins in Western Irian JayaOther areas in western Irian Jaya have been

the subjects of cursory exploration efforts

but only a minor amount has been published

concerning these basins (e.g., Sumantri and

Sjahbuddin, 1994; and more recently

McAdou and Haebig, 1999).

There has been very little exploration in

the Irian Jaya thrust fold belt to date, but a

similar geology to the Papua New Guinea

central fold belt is expected, where oil and

gas are reservoired primarily in upper

Jurassic to lower Cretaceous clastics of the

early post-rift (Gondwanaland breakup)

succession, and trapped in complex thrust

associated anticlines. Conoco reported oil and

gas shows in Kau 2 drilled in the Wasim block

of eastern Irian Jaya. Potential reservoirs also

include Kais formation-equivalent limestones

(the Darai formation in Papua New Guinea).

Potential sources include the Miocene

Kimeuhah formation shales and the Jurassic

marine shales of the Kopai formation.

The Waipogan-Waropen basin, in northern

Irian Jaya, is a hybrid fore-arc with at least

one, and possibly two accretionary prisms,

and contains a thick (in places >7000 m)

Tertiary section covering the collision zone

between the Australian and the Pacific plates

(McAdou and Haebig, 1999). There are

active oil and gas seeps within this area and

out of seven wells successfully completed to

proposed target (out of a total of twelve

wells drilled), four were dry, two contained

subeconomic gas, and one showed both oil

and gas. Abundant reservoir facies include a

thick succession of Miocene–Pliocene

Markats formation and overlying Memberamo

formation turbidites and deltaics, the latter

also providing good potential source facies.

Large Memberamo formation carbonate

buildups provide further reservoir

opportunities, along with the Oligocene–

Miocene Darante formation carbonates

positioned on shallow basement highs.

Potential source rocks include Memberamo

and Markats shales, which may be a source

of gas and condensate and should be mature

in the deeper parts of the basin, although

McAdou and Haebig (1999) note that

geothermal gradient for the basin is low, as

may be expected in this fore-arc setting.

Irian Jaya shows excellent hydrocarbon

potential. Miocene carbonate plays

previously thought to be exhausted in the

Salawati and Bintuni basins may have a

new lease of life, as regional seismic lines

indicate the presence of large and undrilled

Kais formation buildups in the offshore area

south of the Bird’s Head peninsula. The

recent Mesozoic gas discoveries in the

Bintuni basin open up a whole new

Mesozoic play for this basin and other areas

in Irian Jaya. The successes in Seram also

hold hope for tectonically complicated

areas that have been subjected to intense

compression. These include the Irian Jaya

fold belt that continues east into the

Papuan fold belt of Papua New Guinea

where a string of structurally complex oil

and gas accumulations was discovered in

the 1990s (Buchanan, 1996) and, the

Lengguru fold belt where deep burial may

have resulted in the maturation of even

relatively young Tertiary sources. The

Wiapogan-Waropen basin in the north also

remains relatively unexplored but shows

potential with oil and gas seeps to surface

and petroleum shows in the few wells

drilled to date (McAdou and Haebig, 1999).

Timor Gap and Arafura SeaThe Timor Gap zone of cooperation (ZOC),

until recently jointly administered by

Australia and Indonesia, is situated to the

south of the Island of Timor and on the

northern part of the Northwest shelf of

Australia (see Figure 54). Recent political

changes in Timor have stalled the treaty

between Indonesia and Australia, pending

renegotiation.

The Timor Gap ZOC is an extension of the

Bonaparte basin in Australian waters to the

south and demonstrates many stratigraphic

similarities to the rest of the Northwest shelf

and to Timor Island to the north, with its

known oil and gas seeps and minor (less

than 200 BOPD) oil production since 1911.

Structurally, as for the Arafura Sea area to

the east, it is situated near the Timor trough

where the Australian plate is colliding with

the Asian plate and being subducted.

(Figures 55 and 56.) It is characterized by

an abundance of northeast–southwest-

oriented normal faults downthrown to the

northwest, with locally developed grabens

and half-graben (Figure 56.) There are a

number of distinct structural zones. These

include the Sahul platform which is a

structural high developed in the northeast of

the area, and the East Sahul syncline in the

west that trends northwest–southeast

connecting with the Petrel sub-basin to the

south and with the Malita graben (see

Figure 54) that runs northeast–southwest.

In the 1990s, only a few years after the

joint administration was put in place, Petroz

discovered the Elang oil field. This was

rapidly followed by a string of oil and gas

condensate discoveries including Kakatua,

Bayu-Undan, and Corallina and Laminaria

near the ZOC. The discovery of the Elang

oil field and the geology of the ZOC have

been described by Young et al. (1995) and

Arditto (1996).

The pre-Tertiary predominantly clastic

succession extends from the Cambrian, and

overlies crystalline basement. During the

late Devonian to early Carboniferous

northwest–southeast-oriented rifting

produced the larger scale features observed

today – the Sahul Syncline and the Petrel

sub-basin. This earlier phase of rifting was

followed by a second stage starting in the

Triassic and culminating in the late Jurassic,

when the breakup of Gondwana and the

development of an associated regional

unconformity took place.

Of particular interest as a reservoir is the

non-marine to marine early Jurassic section

that encompasses the main reservoir, as

well as seal and source rocks. It includes the

Plover formation and Elang formation

(Arditto, 1996 – previously known as the

Montara beds). The Plover formation was

deposited prior to breakup, through the

early to middle Jurassic. It comprises a

northerly prograding fluvio-deltaic complex

including sandstones, shales and coals. The

Elang formation, which overlies the Plover

formation, is a retrogradational deltaic,

nearshore to proximal shelfal sequence that

was deposited just before the breakup

unconformity that separates the middle from

the upper Jurassic. This formation represents

the main reservoir for the majority of the

discoveries in the Timor Gap ZOC, although

the Plover formation is also a minor reservoir

(Arditto, 1996). Intra-formational seals are

possible within these formations.

The late Jurassic to early Cretaceous

Flamingo group marine sands and shales

were deposited over the Elang formation

(see Figure 57). The lower Flamingo is

thick and conformable on the Elang

formation depocenters, but absent on highs,

and is synchronous with the final phase of

rifting and continental breakup. There are a

number of sand types including highstand

progrades, lowstand fans, incised-valley fills

and proximal fans. Along with the Elang

Overview of Indonesia’s oil and gas industry – Geology220

Page 49: Geology

Cretaceous Kambelangan (Flamingo) group,

and Permian clastics have also been

targeted in the past (e.g., ASM 1X). Gas-

prone source rocks may include Permian-

Carboniferous shales.

On the island of Timor, oil and gas seeps

are numerous, and early production

resulting from exploration between 1914

and 1928 was from the late Jurassic Babulu

formation sands. Potential reservoirs are

carbonates of the lower Jurassic Maubisse

formation and possibly the Tertiary

succession. Potential source rocks include

the Jurassic Wailuli shale and lower

Cretaceous sediments.

Overview of Indonesia’s oil and gas industry – Geology 221

0.000

-2.67 3817.33Line-tie

SPLine-tieSP

1.000

2.000

3.000

4.000

5.000

6.000

7.000

8.000

9.000

10.000

0.000

1.000

2.000

3.000

4.000

5.000

6.000

7.000

8.000

9.000

10.000

Platemotion

Sea floor

Paleogeneprism

Accretionaryprism

Paleocene

Jurassic

Triassic

Permian

Upper mantle

AptianCretaceous

Figure 56:Southwest–northwestseismic line across thenorthern part of theBonaparte basin, shelfand slope, the Timortrough and the Timoraccretionary wedge(Fainstein, 1996b).

Continentalupper mantle

Present-dayearthquakeepicenters

AustraliancrustOceanic

upper mantle

AlorIsland Timor Island

Timortrough

Pseudo-outernon-volcanic arc

Pleistocene to present day

Extinct (Pematian)inner volcanic arc

Timor SeaN S

Figure 55: Schematicnorth–south cross-section across theTimor Volcanic arcand the Timorsubduction zone(Sawyer et al., 1993).

formation, these sands represent the main

reservoir formation in the Petrel sub-basin

to the south (Killick and Robinson, 1994).

The Flamingo group marine shales form a

basin-wide seal. During the early to late

Cretaceous the mainly marine argillaceous

Bathurst group was deposited and, together

with shales of the Elang formation and

Flamingo group, are thought to represent

the algal-marine source recognized from the

oils in the area.

The Tertiary succession is thick and

unconformable and carbonates predominate.

The final structuring phase commenced in

the late Miocene as a result of the collision of

the Australian plate with the Timor trough,

and in Pliocene–Pleistocene times collision of

the Australian and Eurasian plates formed

the Kelp high and the observed northeast–

southwest-oriented faults. Compression

continues with pervasive fault reactivation

The Aru–Arafura Sea area is thought to

be similar to the Timor Gap ZOC, with

hydrocarbon potential in the Triassic

Tipuma formation (see the Bintuni basin

stratigraphy, see Figure 44) where good

porosity was recognized in the

Kambelangan 1 well (Sumantri and

Sjahbuddin, 1994). There are also good

reservoir sands in the late Jurassic through

Page 50: Geology

Geothermal energyIndonesia is the only Southeast Asia OPEC

member but over the past decade, oil

exploration has not been successful in

replacing depleting oil reserves. Even

though gas discoveries have made up for

this shortfall in terms of BBOE the

prediction is that without significant

additions to oil reserves Indonesia will

become a net importer of oil sometime early

in the twenty first century.

Alternative sustainable sources of energy

are, therefore, required to help

compensate for declining oil reserves and

to satisfy an ever-increasing demand for

energy. Although geothermal energy will

never be the main energy source in

Indonesia, it could contribute significantly

to the energy demand and is a sustainable

‘green’ energy resource.

A chain of volcanoes – the Ring of Fire –

encircles the Pacific Ocean as a result of the

subduction of oceanic crustal plates at the

ocean trench subduction zones (Figure 58).

As the oceanic plate is consumed

downwards into the mantle it melts and

large intrusive bodies of magma rise towards

the surface. In some cases, these intrusive

bodies are shallow enough for volcanoes to

develop where magma breaks through to the

surface via zones of weakness and spills out

at the surface as lava.

Indonesia is situated in an ideal setting

for the development of geothermal energy,

at the western limit of the Ring of Fire, and

is the most volcanic country in the world

with 121 active volcanoes. A major

subduction zone where the northwards-

moving Indo-Australian plate is being

subducted beneath the Sunda shelf, extends

almost the full length of the country from

west to east. Volcanoes are developed along

almost the entire length of this Sunda

trench system, from the northwest tip of

Sumatra to the far east of Indonesia just

south of Irian Jaya. The major

concentrations of volcanoes associated with

this subduction trench are on Sumatra

(approximately 1.5 volcanoes for every

100 km) and Java (approximately 3.5

volcanoes per 100 km). Volcanic islands also

occur to the east of Java, including Bali,

Lombok, Sumbawa, Flores, and others

extending northeastwards into the Banda

Sea. In addition, with Indonesia being a

complex system of interacting microplates,

there are other volcanoes associated with

minor subduction zones throughout the

Moluccas and northern Sulawesi. All these

volcanic areas demonstrate the potential for

development of hydrothermal systems and

over 100 geothermal prospects have been

identified (Figure 59) by PERTAMINA.

Overview of Indonesia’s oil and gas industry – Geology222

Montara beds

Malita fmPlover fm

0

1

2

3

4

5

6

7

Dept

h, k

m

0 50km

Permian

Triassic

(undifferentiated)

Montarabeds/Elangformation

Timortrough

NESW

Kelp-1Hydra-1Mandar-1Elang-1Flamingo-1Iris-1Garganey-1Avocet-1A

Londonerry high Sahul syncline Flamingo highFlamingosyncline Kelp high (Sahul platform)

Tertiarycarbonates

Miocene unconformity

BathurstIsland group

Darwin fm/Flamingo gp

Triassic(undifferentiated)

Breakupunconformity

Plover fmMalita fm

Breaku p unconformity

Base Tertiary disconformity

Base Aptian disconformity

Figure 57: Schematic geologic cross-section of the western zone of cooperation (ZOC) (Young et al., 1995).

Page 51: Geology

Overview of Indonesia’s oil and gas industry – Geology 223

Indonesia

Bougainville trench

Ryukyu trenchPhilippinetrench

Japan trench

Kurile trenchAleutian trench

Middle Americatrench

Peru-ChiletrenchTonga trench

Kermadec trench

Equator

Pacific Ocean

RING

OF

FIRE

Oceanic-continental convergence

Asthenosphere

Lithosphere Lithosphere

Continental crustOceanic crust

Tren

ch

Volc

anic

arc

Sundatrenchsystem

Figure 58: The ‘Ring ofFire’, a volcanic belt thatencircles the PacificOcean is the result ofconsumption of thePacific and Indian oceanplates at the oceanictrench systems(subduction zones).

Location of main geothermal prospectsDrilled prospects

0 400 800 1000km

Irian Java

Ambon

Banda Sea

Flores Sea

Sulawesi

Kalimantan

South China Sea

Java Sea

JavaBali

Sumbawa

Sumba

Flores

Timor

Sum

atra

Mala

ysia

1

2

3

4

67 8 9

5

10

11

Sumatra

1. Sibayak2. Tarutung3. Pusuk Bukit4. Ulubelu

Java

5. Salak6. Wayang–Windu7. Darajat8. Kamojang9. Karaha10. Dieng

Sulawesi

11. Lahendong

Figure 59: Location ofhydrothermal prospectsin Indonesia.

Page 52: Geology

The primary requirement for the

formation of a geothermal system is a heat

source, usually related to magmatic

activity. Economically viable geothermal

systems develop where a magmatic heat

source is emplaced high enough in the

Earth’s crust to induce convective

circulation of groundwater (Figure 60). It

must be at a depth shallow enough for this

heated water, or steam, to be exploited at

the surface for generation of electrical

energy using steam turbines.

The depth of emplacement of these

magmatic bodies is usually between about 2

and 5 km. The host rock depends on the

geological province, but for hydrothermal

systems in volcanic areas such as Indonesia,

the host rock is usually either volcanic

(basalts and andesites) or volcaniclastic

(tuffs or volcanic sands and

conglomerates/breccias that were spilled

from the sides of volcanoes). The presence

of carbonates in the host rocks changes the

composition of the hydrothermal fluids and

is detrimental to the commercial

development of the system due to problems

with scaling and corrosion etc. The best

hydrothermal systems usually have high

permeabilities due to fracturing in the host

rock. Fracture zones, and also porosity and

lithology, can be determined using wireline

logs, particularly with the Formation

MicroScanner* (Figure 61). These are run

in-hole with circulating cold water to cool

the borehole environment.

The fluid circulating in the hydrothermal

system is usually meteoric water and high

rainfall in Indonesia further enhances the

prospects for the development of geothermal

systems. The composition of the geothermal

waters is usually a mild brine with a near

neutral pH, although the chemistry of the

fluids may vary depending on the proximity

to the sea or depth within the system where

hydrochloric acid and sulfur dioxide levels

may be high due to magmatic influence.

Temperatures may be as high as 1000˚C

approaching the melting temperature of the

rock, but in Indonesia this is never the case

and reservoir temperatures tend to vary

from 60˚C to 400˚C at usual reservoir depths

of between 200 and 1000 m. A convective

cell is normally developed, with hot-water

up-flow in the center and cold-water

recharge from the edges of the system,

although laterally extensive out-flow zones

with hot springs may develop a number of

kilometers away from the active

hydrothermal system.

Of the hydrothermal prospects identified

by Pertamina (more than 100 as shown in

Figure 59) only 12 have been drilled to

date. There are only three geothermal

plants on-stream – Gunung Salak, Kamojang

and Darajat – all situated in West Java, with

a total combined rating of 305 MW.

Obviously, there is significant scope for the

future development of hydrothermal power

in Indonesia.

Overview of Indonesia’s oil and gas industry – Geology224

Early venting of magmaticvolatiles; porphyry typemineralization

Cooling intrusion

Convectingneutral chloridegeothermal fluid

Limited boiling and gas separation onlocalized vertical permeability

Recharge

Lateraloutflow

Local boiling

Sea level

Neutral chloridesprings,possibly sinters

Sulfate–bicarbonatesprings

Piezometric surface ofdeep, single-phase reservoir

Lateral outflow and water rock interaction

Acid sulfatesprings

Rainfall

Weak fumeroles and gas heated features

Erodedstratovolcano

Vadose zone

Limited boiling

Acid sulfate aquifer

Zone of fluid mixing andmineral deposition

Figure 60: Schematic hydrothermal systemassociated with an andesitic stratovolcano(Giggenback, 1992).

Page 53: Geology

The futureIndonesia will have to diversify its energy

resources over the next few years to keep

pace with a growing population and an

escalating demand for energy. Hydrocarbons

remain an attractive energy source and

exploration will continue, but a shift in

focus regarding play types and the arenas of

exploration, and also a change from oil

consumption to gas consumption are both

expected and required. This shift is

necessary for environmental reasons, to

slow the depletion of oil resources and the

time when Indonesia becomes a net

importer of oil.

Western IndonesiaWestern Indonesian basins are considered

for the most part to be relatively mature

with regard to hydrocarbon exploration.

There are, however, a few back-arc basins

that can be considered to be underexplored

including the Pembuang basin in South

Kalimantan that has not yet been drilled.

The back-arc basins of Sumatra and Java,

and the deltaic basins of East Kalimantan,

which have been the object of such

intensive exploration over the last century,

may also reveal missed opportunities.

Post-rift sequencesThe conventional or traditional Western

Indonesian play types – early Miocene

carbonate buildups and post-rift Miocene

(mainly) transgressive sands – are largely

exhausted. In the East Java basin, however,

there are a number of Miocene Kujung and

Rancak buildups that have not yet been

drilled. Production from the Kujung and

Rancak buildups is established (e.g., the

Mudi, KE, and Camar oil fields). There

have been some very recent discoveries in

the Kujung buildups (e.g., the Ujung

Pangkah oil and gas field offshore from

Surabaya). This play demonstrates the

remaining potential in East Java. Similar

buildups are also recognized in the delta-

front areas of the Mahakam and Tarakan

deltas of East Kalimantan.

Relatively small-scale buildups of

equivalent age also remain to be drilled on

the Malacca platform of the North Sumatra

basin and in the Batu Raja of South

Sumatra. Further large Peutu limestone

buildups (such as the Arun gas field) also

cannot be ruled out in the North Sumatra

basin, and there may remain further oil and

gas potential in the extensive Terumbu

carbonates of the East Natuna basin. Fluvio-

deltaic and shallow-marine Miocene sands

demonstrate very limited remaining

potential for structural traps in the onshore

area, with smaller and more subtle fault-

and stratigraphically controlled

accumulations remaining to be discovered.

In the Natuna Sea, however, both the

East and the West Natuna basins

demonstrate excellent potential with thick

post-rift sands being developed. Manur and

Barraclough (1994) also recognized a

middle Miocene Ngrayong deltaic biogenic

gas play in the Muriah trough extension of

the East Java basin.

A relatively untested play, which is only

just beginning to show its potential,

comprises deepwater Miocene lowstand

fans. Turbidite plays have been drilled in

the past, but they have only recently

become a major focus with the discovery of

the Merah Besar and West Seno oil fields

offshore from the Mahakam Delta. Large

turbidite systems have been revealed on

seismic in the North Sumatra basin

(Tsukada et al., 1996) and similar Ngrayong

formation turbidite and contourite sands

have been drilled with some success by

Santa Fe in the East Java basin (Ardhana,

1993; Ardhana et al., 1993).

Overview of Indonesia’s oil and gas industry – Geology 225

N

S

Fracture dipazimuth

W E

Figure 61: FormationMicroScanner imageof a fracturedhydrothermalreservoir showingfracture orientations.

Page 54: Geology

Syn-rift sequenceThe syn-rift sequence has largely been

neglected throughout the back-arc basins of

Western Indonesia. Thick alluvial fan

systems, fan deltas, fluvial sands and

lacustrine deltas of Eocene to Oligocene age

may be reservoirs for substantial volumes of

hydrocarbons throughout the Western

Indonesian basins. They are coupled directly

with the most prolific source facies including

deep-lacustrine and marginal shallow-

lacustrine earlier syn-rift, and later syn-rift

transgressive, coals and shales. This

source–reservoir combination has been

recognized for the Northwest Java basin

(Butterworth and Atkinson, 1993), and

realized elsewhere.

Arco produces gas from syn-rift Eocene

clastics and carbonates in the Pagerungan

and West Kangean gas fields in the offshore

East Java basin. Caltex has minor production

from Pematang formation syn-rift sands in

the Central Sumatra basin but they are

starting to explore the Pematang more

vigorously, in particular for gas to power the

giant Duri oil field steamflood project and

others. The Tanjung Raya oil field of the

Barito basin in Southeast Kalimantan has

produced nearly 125 MMBO since 1938,

mainly from Eocene syn-rift alluvial fan

deposits. More recently developed, the KRA

field in the West Natuna basin produces oil

from Oligocene Belut lacustrine-deltaic

sands. The potential of the back-arc basin

syn-rift sequence has, therefore, been

demonstrated but exhaustive exploration has

not yet started, as the post-rift prospects

remain easier to identify on seismic and are

better understood.

Other play typesDepending on infrastructure and the degree

of industrialization in specific areas, smaller

and more esoteric plays may be attractive.

Pliocene globigerinid limestones and

diagenetically enhanced volcaniclastics are

reservoirs for the small biogenic and

thermogenic gas deposits of the Terang-

Sirasun and Wunut gas fields in East Java,

respectively. They will supply gas to the

industrialized area around Surabaya. Gulf’s

gas in fractured basement in the South

Sumatra basin is being traded for oil with

Caltex. This latter play may prove to be

large, with reserves of over 4 TcfG already

realized. In a similar manner, the fractured

pre-rift–early syn-rift Eocene Tampur

limestone in the North Sumatra basin has

demonstrated some potential as a gas

reservoir (Ryacudu and Sjahbuddin, 1994).

Many of the oil fields in Western

Indonesia are approaching old age. As such,

numerous enhanced oil recovery projects

are underway and offer further potential for

retaining oil production from the more

depleted fields. Some of these include the

Duri steamflood (the largest of its kind in

the world), the Minas waterflood (and pilot

light-oil steamflood) and the Melibur

steamflood in Central Sumatra; the Kakap

gas injection in the Natuna Sea; the Kenali

Asem waterflood in South Sumatra; the

Krisna lower Batu Raja waterflood in the

Sunda basin; the Handil chemical waterflood

in the Mahakam Delta; and the Tanjung

Raya waterflood in the Barito basin. In

addition, there is an increasing interest in

exploring for missed or bypassed reserves in

largely depleted fields. An example is the

PERTAMINA-owned Rantau oil field in the

North Sumatra basin that has already been

subjected to waterflood. PERTAMINA and

Schlumberger have formed a results-based

business alliance for this field to find and

tap bypassed oil using mainly the RFT*

Repeat Formation Tester tool.

Frontier areas in WesternIndonesiaAttractive PSC terms have been offered

by PERTAMINA for exploration in frontier

areas in Western Indonesia. These include

pre-Tertiary plays (e.g., Gulf’s basement

gas in South Sumatra), intermontane basins,

and deepwater (over 200 m) areas and fore-

arc basins. Unocal has demonstrated the

value of deepwater exploration with the

discovery of the West Seno and Merah Besar

oil fields. Other deepwater acreage exists in

Western Indonesia, particularly in the

offshore Tarakan basin in front of the Mayne

fault system. Here there is potential for the

trapping of oil in deep water sands and in

carbonates developed on structural highs

(Netherwood and Wight, 1993). The Andaman

Sea in the northern sector of the North

Sumatra basin is also deep water acreage.

Fore-arc basins have been tested

including the Sibolga basin offshore

northwest Sumatra, the Bengkulu basin

offshore southwest Sumatra, the Southwest

Java basin and the South Java basin. The

validity of biogenic gas plays has been

demonstrated in the Sibolga basin, although

no commercial discoveries have been

realized in large lower and middle Miocene

buildups because of sealing problems

caused by early gas generation. However, it

is thought that interbedded sands and

shales may show better prospects for

biogenic gas. The Bengkulu basin has a

proven petroleum system for oil generation.

It demonstrates a similar geology to the

south Sumatra basin, with an undrilled

Paleogene rift system that could feasibly

contain lacustrine source rocks, and proven

post-rift reservoir facies. Post-rift Miocene

shales and even some coals are proven

source facies. The Southwest Java basin had

a complicated post-rift Neogene tectonic

history. It contains mature inverted Eocene

source facies and plentiful potential

reservoir sands including Eocene–Miocene

fluvio-deltaic, shallow-marine and even

turbidite fans.

Overview of Indonesia’s oil and gas industry – Geology226

Page 55: Geology

Eastern IndonesiaEastern Indonesia is considered to be

underexplored, with half of the basins (20)

not yet drilled. This is because of deep water,

poor infrastructure, remote onshore location,

and a poor understanding of the geology.

Eastern Indonesia, with the exception of

the Tertiary in Seram, Salawati and Bintuni

basins, has been designated a frontier area

with improved PSC terms. For this reason,

coupled with recent commercial

hydrocarbon discoveries, the basins of

Eastern Indonesia are much more attractive

to the explorationist than in the past. One of

the greatest barriers to exploration in

Eastern Indonesia, is the complex and

widely different structural regimes that may

make and destroy plays. Thrust and fold

belts abound (e.g., the eastern arm of

Sulawesi, Davies 1990; Seram, Kemp 1993,

1995; and the Lengguru and Central Irian

Jaya fold belts), as do subduction troughs. In

addition, many of the potential hydrocarbon

provinces and/or basins are small, and have

been rotated or extruded. Until recently, the

Pre-Tertiary was poorly understood and,

apart from in the Salawati and Bintuni

basins and southern Sulawesi, the Tertiary

has largely been considered unprospective.

Pre-Tertiary playsWith the initiation of the recent giant

Tangguh gas project in the Bintuni basin, the

discovery of commercial oil in fractured

Jurassic carbonates in Seram and the

discovery of oil and gas in the Timor Gap

ZOC, the Mesozoic has come to the

foreground as the preferred exploration play

in Eastern Indonesia. Prior to the breakup of

Gondwana, early Jurassic and older, and also

the post-breakup late Jurassic to Cretaceous

sedimentary sections, demonstrate excellent

oil and gas source potential. Deltaic coaly and

shallow-marine source facies are developed at

various stratigraphic levels. Thick fluvio-

deltaic and shallow-marine reservoir sands of

the post-breakup succession provide the main

reservoirs in the Timor Gap ZOC and the

Bintuni basin. The Arafura Sea to the east of

the Timor Gap and the Indonesian Northwest

shelf margin to the west are stratigraphically

and structurally similar to the ZOC. These

areas are essentially virgin territory, with very

few wells and great promise.

In Seram the Mesozoic potential has been

proven with the fractured Jurassic Manusela

formation reservoir in the Oseil oil field.

Elsewhere in Seram, Triassic potential

source and reservoir rocks are recognized

(Kemp, 1995). The Triassic and older plays

need to be considered. British Gas also

tested gas from Permian sands in the Mogoi

deep well in the Bintuni basin.

Tertiary playsWestern Sulawesi is unique in that it is a

part of the Sunda shield and not, as in most

potential Eastern Indonesia hydrocarbon

provinces, a fragment of the Australian

craton. Western Sulawesi, therefore,

demonstrates a syn-rift sequence similar to

Western Indonesia basins with known

potential lacustrine and deltaic source rocks

and reservoirs. It also has proven Miocene

carbonate reservoirs with small, but

commercial gas reserves to be used for local

power generation.

Elsewhere in Eastern Indonesia, the

Tertiary is largely considered to be either

played out (e.g., Kais formation carbonates

in the Salawati and Bintuni basins), or non-

prospective because of extreme tectonism

or poor seals over a predominantly

carbonate section with high potential for

breaching and poorly understood petroleum

systems. Untested Kais formation buildups

have, however, been recognized offshore in

the Salawati basin (Fainstein 1998a). The

Banggai-Sula basin contains a thick

Paleocene to late Miocene carbonate

succession highly tectonized and thrust over

both younger and older rocks. This intense

tectonism, however, has been responsible

for the maturation of middle Miocene

sources that may normally not be buried

deeply enough to generate hydrocarbons. It

has also been responsible for the formation

of fracture porosity for the subcommercial,

but geologically significant, Tiaka, Minahaka

and Matindok oil and gas discoveries

(Davies, 1990). Although of a different age,

this is geologically a very similar situation to

the commercial Mesozoic Oseil oil field

carbonate play in Seram.

Neogene carbonates may also

demonstrate potential in the Lengguru and

central Irian Jaya fold belts, which are

tectonically complex but similar in many

respects to the Banggai-Sula basin, the

Seram, and the Papua fold belt of Papua

New Guinea to the east. Interestingly, these

areas may also promote maturation of

Neogene source rocks through burial in the

cores of deep synclines or under thick

thrust piles. There is oil in the

Pliocene–Pleistocene clastics and

carbonates of the Fufa formation in the

small Bula oilfield in northeast Seram.

Similar shallow plays may exist in other

basins where there has been late Neogene

shedding of tectonic molasse.

Other energy sourcesThe potential for geothermal energy to

supplement hydrocarbons is strong, with

about 100 prospects recognized and three

hydrothermal projects already supplying

about 305 MW of power.

Thick gas hydrate layers, a combination

of frozen methane and water, have been

recognized on the sea floor in various parts

of Indonesia, including the Celebes Sea and

in the Seram trough (e.g., Fainstein 1998b).

The technology to exploit these gas deposits

does not yet exist but this situation is likely

to change in the future.

Acknowledgements

Thanks need to go in particular to those people who

took it on themselves to critically proof the various

sections of the text. These include Bob Davis,

consultant geochemist for proofing a large part of

the text and commenting on geochemistry, and

Chuck Caughey of Gulf for wading through the

entire document, Deidre Brooks of Woodside in Perth

for covering the Timor gap section, and Tony Dixon

for the West Natuna section. I would also like to

thank Herman Darman of Shell, Rob Barraclough of

Kufpec, Ian Longley of Woodside in Perth, and John

Decker of Unocal for their comments and suggestions

on various parts of the text.

Overview of Indonesia’s oil and gas industry – Geology 227