geology indonesia
TRANSCRIPT
A Geological Overview of Indonesia
Chapter 4
The Petroleum Geology of Indonesia
Indonesia is diverse in terms of culture, geography and geology. It is a sprawlingnation of 9.5 million km2 and, with 80% of its area being water and more than17,000 islands, it is the largest archipelago in the world. It traces the path of theequator for over 5400 km east to west across three time zones and extends for over1800 km from north to south.
I 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
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).
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).
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).
(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).
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
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
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
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.
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
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
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).
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).
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).
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).
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).
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).
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).
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.
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).
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.
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.
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
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
P
APN
AA
Bima 'ZU'
DumaNora
SelatanUtari
KittyCint A Rama
Wanda GitaFaridaKrisna
NurbaniYvonne
SundariJanti Yani
Widuri
Intan
KarmilaKartini
AVAVS
L-Parigi
Kandang Haur
Java
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matr
a
Cirebon
Sunda platform
Seribuplatform
Vera
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structure
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Java
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matr
a
0 50 mile
Yani-Nst
South ArdjunaSouth Ardjuna
Tanjung
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Central Ardjuna
Ciputat Kepuh
Pasir Bunger
Cipunegara - E 15 Graben Jatibarang
Tanjung
Asri
Sunda
Central Ardjuna
Ciputat Kepuh
Pasir Bunger
Cipunegara - E 15 Graben Jatibarang
< 0.5 secTWT scale
0.5 - 1.01.0 - 1.51.5 - 2.02.0 - 2.52.5 - 3.0> 3.0 sec
Figure 22: Basement time structure map of Northwest Java sub-basins(above) and location of hydrocarbon fields (below) (after Noble et al., 1997).
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.
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.
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).
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).
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).
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).
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.
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.)
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 (10 s 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)
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.)
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).
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).
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
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5000
4000
1000
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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
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).
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
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.
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
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
EastWest
020406080100
km
020406080
100
A A'
x x xFigure 47: Regional cross-section across southernSulawesi continent–continent collision(Guritno et al., 1996).
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
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
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Line IJ97 - 0193
Figure 49: Detail ofseismic line across theSeram trough(Fainstein, 1998a).
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).
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).
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
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ben
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Sub basin
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platform
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Tern gas field
Petrelsub-basin
Bonapartebasin
Australia
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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).
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
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
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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
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).
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
Jawa 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.
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).
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.
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
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