Geology Indonesia

Chapter 4 A Geological Overview of Indonesia

Overview of Indonesia

The Petroleum Geology of Indonesia Indonesia is diverse in terms of culture, geography and geology. It is a sprawling nation of 9.5 million km2 and, with 80% of its area being water and more than 17,000 islands, it is the largest archipelago in the world. It traces the path of the equator for over 5400 km east to west across three time zones and extends for over 1800 km from north to south.

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

I

PT SCHLUMBERGER INDONESIA Richard Netherwood

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

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

Indonesian sedimentary basins Philippines

Western Indonesia NSB

EN

Malaysia

WN

Eastern Indonesia

Malaysia and Brunei

CE TA

Singapore

ra at

m Su

NSF

MU

KE ME

CSB

UK

GO L

law

PE

EJ

Discovery (10)

Java

Undrilled (22)

SS

TBA SW

W A

F

JF

SA

SBL

TImor

TI

C A

B NWS ZOC

0

Western Indonesia

Eastern Indonesia

NSB CSB SSB NSF SSF S/A NWJ JF EJ BI PE BA PN AA/P UK K/MS MU TA CE KE ME WN EN

SM/NM GO B/S S/M BU BD B F SS L SBL SA TI NWSZOC W SE NEH EH SEH SW BT MO TBA KT A AK AR CIJ W/W

AR

KT

BD

Pre-Tertiary petroleum

North Sumatra Central Sumatra South Sumatra North Sumatra fore arc South Sumatra fore arc/Bengkulu Sunda/Asri Northwest Java Java fore arc East Java/Java Sea Billitong Pembuang Barito Pater Noster platform Asem-Asem/Pasir Upper Kutei Kutei/Makassar Straits Muara Tarakan Celebes Ketungau Melawai West Natuna East Natuna

CIJ

AK

Nusa Tenggara

Tertiary petroleum

-

MO

SE Moluccas

BU

B

W/W

BT

Irian Jaya

S/M

e

e li n

NWJ

PN

Wall ac

Producing (14)

BI

B/S

i es

S/A

SEH

Su AA/P

SSB

No discovery (14)

EH

K/MS

BA Kalimantan SSF

NEH

SM/NM

-

South/North Minahasa Gorontalo Banggai–Sula Salabangka–Manui Buton Banda Bone Flores Spermonde/Selayar Lariang South Bali–Lombok Savu Timor Northwest Shelf zone of cooperation Weber Seram Northeast Halmahera East Halmahera Southeast Halmahera Salawati Bintuni Misool-Onin Teluk Berau–Ajumaru Kai Tanimbar Aru Akmeugah Arafura Central Irian Jaya Waipoga/Waropen

400

800

1000km

38 (63.3%) Eastern Indonesia

22 (36.7%)

Western Indonesia Western Indonesia (22 basins)

Eastern Indonesia (38 basins) Producing (7.9%)

Undrilled (13.6%) Producing (50.0%)

Drilled (No discoveries) (22.7%)

Undrilled (50.0%)

Discoveries (Non-producing) (13.6%)

Discoveries (Non-producing) (15.8%)

Drilled (No discoveries) (26.3%)

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

Overview of Indonesia’s oil and gas industry – Geology 175

U L

5.2 5 (5.5)

10.6 10 (10.5)

Middle Lower

Miocene

Upper

Pliocene

Q

Ma 0

15

21.5 (21.0)

20

29.5 (30.0) 30

Major events Overall Rotation of N and E regression arms of Sulawesi. Northward movement of Bird's Head relative to Australia Increased convergence with CCW rotation of Sumatra and development of Sumatra wrench fault. Sulawesi forms – emplacement of continental crust along Sorong fault Transgression onto Sunda shelf. Eustatic and tectonic – increased convergence along Sunda arc led to inversion and then thermal sag

35

Lower Upper

5Ma Luzon arc collides with Asian plate 10Ma Australian craton collides with Asian Plate – inversion Middle Miocene – maximum transgression

c21Ma South China Sea spreading ends c25 Ma New Guinea passive margin collides with arc system to North. Sorong fault forms. Emplacement of Sulawesi ophiolites

38.6 (39.5)

Slowed convergence leads to second stage of rifting along Sundaland margin

40

45

Slowed convergence leads to rifting along Sundaland margin

51.0 50 (49.5)

Lower

3 Ma Timor and Banda arc collide

c32Ma South China Sea spreading

Lower Middle

Eocene

Upper

Tertiary

Upper

25

Paleocene

Understanding 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 wideranging 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

2nd order sequence boundaries +200m +100 m 0

Hol

Geological evolution of the Indonesian archipelago

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

Global eustatic curve Epoch

Period

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 sealevel 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

Oligocene

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.

55

c43 Ma Major plate reorganization. India and Australia plates combine. Subduction of India beneath Eurasia ends c50Ma India – Eurasia collision commences

Slow southern ocean spreading. Subduction along west Sundaland margin

59.5 (58.5) 60

65

Figure 2: Chronostratigraphic summary of major geological events in the Cenozoic (events taken 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

50 Ma End Early Eocene

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

40 Ma Middle Eocene

Taiwan

South China

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

Mindoro Indochina

PACIFIC PLATE

North Palawan

PACIFIC PLATE

EURASIAN PLATE

EURASIAN PLATE

Malaysia

Izu peninsula

Proto-South China Sea

West Philippine Sea spreading extends to Celebes Sea

Subduction of Proto-SCS begins

?

NORTH NEW GUINEA PLATE

Sumatra

South Borneo

Java

Zamboanga

Celebes Sea

Oki Daito ridges

West Sulawesi PHILIPPINE SEA PLATE East Philippines

West Philippine Sea

?

No rotation of Philippine Sea plate

Arc activity at south edge of Philippine Sea plate

INDIAN–AUSTRALIAN PLATE

INDIAN–AUSTRALIAN PLATE

? ? Leading edge of Bird's Head microcontinent

South and East Sulawesi

30 Ma Mid Oligocene

20 Ma Early Miocene

EURASIAN PLATE

Opening of South China Sea north of Macclesfield Bank

Red River fault Indochina extruded to SE Three Pagodas system

North Pawalan Extension driven by slab-pull and Indochina extrusion

Final spreading of South China Sea

PACIFIC PLATE

Opening of Parece Vela basin begins

Proto-South China Sea

EURASIAN PLATE

Spreading in Parece Vela basin Inversion in Natuna basins

Cagayan ridge separates from Sulu arc

Borneo rotation begins Ophiolite approaching Sulawesi west arm

INDIAN PLATE

Bird's Head microcontinent

10 Ma Late Miocene

INDIAN PLATE

Bird's Head microcontinent dismembered by Sorong fault splays

Australia

Spreading in Shikoku PACIFIC PLATE basin Clockwise rotation of Philippine Sea plate

Continental crust thrust CAROLINE PLATE beneath Sulawesi Molucca Sea forms part of Philippine Sea plate Sorong fault system initiated Australia

EURASIAN PLATE PACIFIC PLATE

Subduction at Manila trench

Malaya blocks rotation complete Andaman spreading Borneo rotation complete

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

Philippine Sea plate rotates

Sulu Sea

Sulu arc activity CAROLINE PLATE ends Molucca Sea double subduction established Ayu trough spreading Sula N Banda

INDIAN PLATE

Australia


Re

Hainze e–Sag aing fa u

lt

PHILIPPINE SEA PLATE

d

ren

lt au

rf

ch

ve Ri nd sa da lts go au Pa ao f ree Ch Th ang W

Ma ria na t

Philippines

EURASIAN PLATE

PACIFIC PLATE

Pacific Ocean South China Sea h

nc

u la

tre

Pa Gr a atr an Wal

fau

lt

fau

tem S

0 160 320

320

da

tr e

h

lt

h

nc

tre

Meratus suture, Late Cretaceous collision

ru

nc h

480 m

640 km 5 cm/yr

s y s t em Java trench

AUSTRALIAN – INDIAN PLATE

o

r tr

o Tim

ugh

7cm/yr

Australian crust

Oceanic spreading axis

Pre-Mesozoic continental crust

Subduction zone

Transitional, attenuated or sutured

Strike–slip fault

Oceanic or island arc

Quaternary–recent volcano

(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 leftlateral 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.


West Melanesian trench

Seram trough

u ea fa

ys

ra at

lt s

m

Su

un

0 80 160

CAROLINE PLATE Sorong fa ult

m Su

i wa

nta

Me

t ea

SUNDALAND

o tr

ug

A

AUSTRALIA CRATON

Australia

Figure 4: Simplified tectonic elements and crustal distribution for Indonesia (after Coffield et al., 1993 and Nugrahanto and Noble, 1997).

Tectonic evolution The 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 late Oligocene)

Stage III. 25–8 mybp (latest late Oligocene–late Miocene)

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. Fluviolacustrine 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.

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 IndoAustralian plate was close to collision with the margin of Sundaland near west Sulawesi. Ophiolites were emplaced along the eastern edge of this western Sulawesi arm. Oceanic crust trapped between Sulawesi and Halmahera was rotated clockwise and subducted beneath the eastern margin of Sulawesi. The tectonic development of the region was further influenced by the continued northward motion of the Indo-Australian plate following collision. Counter-clockwise rotation of the entire Sunda shield promontory including peninsular Malaysia, Sumatra, Java and Borneo occurred. The effective increase in rate of convergence between the Indo-Australian plate with respect to Sumatra stimulated magmatic activity that weakened the upper plate and led to right-lateral dislocation along the Great Sumatra fault system. During rotation, a bend and half-graben developed in the Sunda Straits separating South Sumatra from West Java. In northwest Borneo a delta was established and turbidites poured into the proto-South China Sea. Increased subsidence east of Borneo resulted in arc splitting and the opening of the Sulu Sea as a back-arc basin. Halmahera and the Philippine plate were carried towards the subduction zone below north Sulawesi, and fragments of the Australian continental crust were added to the developing Sulawesi along the Sorong fault system.


Stage IV. 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 effects Longley (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 and their petroleum systems The complex geological history of Indonesia has resulted in over 60 sedimentary basins that are the subject of petroleum exploration today. By the end of 1996, following nearly 130 years of drilling activity, 38 of these basins had been widely explored, 14 were producing oil and gas, 10 had shown promise with subeconomic discoveries and 22 (over one-third) remained poorly explored or unexplored (Sujanto, 1997, see Figure 1). Of the 22 basins in Western Indonesia, only two are undrilled. In Eastern Indonesia there are 38 basins of which 20 are undrilled. Although large areas of Indonesia, particularly in the west, are considered to be mature with respect to hydrocarbon exploration, the majority of basins in the east remain underexplored. This reflects both the relatively sparse knowledge of the geology of Eastern Indonesia and its remoteness with respect to world markets. There are logistical difficulties and high costs associated with the exploration of sparsely populated wilderness areas with

little or no infrastructure and exploration in deep (>200 m) water. The majority of explorationists, therefore, have concentrated their efforts on the highly productive but more mature basins of Western Indonesia. These include the North Sumatra, Central Sumatra (the most prolific basin by an order of magnitude), South Sumatra, Sunda-Asri, Northwest Java, East Java, Barito, Kutei, Tarakan and East and West Natuna basins. All of the most prolific petroleum systems discovered to date are located in Western Indonesia, with 85% of all Indonesian recoverable oil reserves being in the hot back-arc basins of Sumatra and Java. Gas is more evenly distributed in foreland 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 forearc, 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.


Western Indonesian basins

• 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. Forearc basins occur between the modern volcanic arc (the northern limit of the forearc basins) and the subduction-generated accretionary prism (outer island-arc of Sumatra and the southern limit of the forearc 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

The 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.

Sumatra

2nd order sequence boundaries

mybp

+200m +100m

North

0

Quaternary

SE SW Toba Tuffs Alluvium

Alluvium

South

Minas

Julurayeu

(Korinci)

Late

10.6 (10.5)

Middle

Miocene

v

v

v

v

Kasai

v

Bangko Menggala

Late

25

Batu Raja Pendopo Upper Talang Akar

Massive

Batu Raja Batu Raja (M. Cibulakan) TAF (Gita) Upper Talang Akar (Lower Cibulakan)

Lower Talang Akar

Bampo

Talang Akar (Upper Zelda)

Lower Talang Akar

Talang Akar (Lower Zelda)

29.5 Pematang

(30.0) Early

Lemat Parapat

Banuwati

Late

35

Middle

Unit II

Gumai

Duri Bekasap

21.5

Eocene

U. Cibulakan

Mid main

Pre-Tertiary basement

Ngrayong

Telisa

(21.0)

45

Karren

Wonocolo

Pre-Parigi

Air Benakat

Gumai

Jati Barang

Tampur

Meucampli

OFFS

Kawengan

Cisubuh

Air Benakat

Belumai

38.6

40

ONSH. Lidah

Parigi

(Binio)

Peutu (Arun)

30

v

Muara Enim

M B Sand Upper Baong Shale

20

Northeast

v

Cisubuh

v v

Petani

Lower Baong Shale Lower Baong Sand

15

Early

v

Parigi

10

Oligocene

v v

Keutapang

Northwest

Alluvium

Seurula

5.2 (5.5)

Asri Sub-basin

Sunda SE

NE NW

Pliocene 5

Java

Central

NW

Sihapas

Age

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.

Lahat (Kikim Tuffs) Middle Kikim Sand

(39.5) Eustatic curve after Haq et al., 1988.

T u b a n

Rancak

KUI/UK K u j u n g

KUII/MK

KUIII/LoK

N g i m b a n g

CD

Lahat

+

+

+

+

+

+ + + +

After Alexanders & Nellia, 1993, Fainstein, 1996, Riadhy et al., 1998.

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

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


+ +

+

After Rashid et al., 1998, Sitompul et al., 1992, Tamtomo, 1997.

+ ++

v

v

v + + +

After Aldrich et al., 1995.

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

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

The fore-arc basins

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, openmarine basins, and limited onshore space between coast and mountains was not

The 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, rightlateral, duplex transform system comprising – the Great Sumatra and the Mentawai fault zones. The accretionary wedge itself has

Kalimantan Barito

Natuna

Kutai

West Alluvial

East

Tarakan

West Mahakam

conducive to a sufficient supply of nonmarine 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 forearc 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.

East

West Bunyu

East East

Coal West

South

Shales and claystones

North

Volcanics/volcaniclastics Reefal and platform carbonates (and dolomites) Sandstones

Kampung Baru Dahor

Tarakan Muda Muda

Domaring U. Warukin

Tabul

Balikpapan

Lamaku

Landasan

Middle Warukin

Meliat

Meliat SS

Conglomerates

Terumbu

Upper Arang

Argillaceous

Latih

Pulu Balang

Upper Arang

Naintupo

v

Taballar

v v

Volcanic input

v

Arang SS

L. Warukin

Gas

Bebulu Lower Arang Tempilan

Upper Berai

Udang

Pamalusan

+ + +

v

L. T a n j u n g

v v v

After Satyana, 1995, Satyana & Silitonga, 1994, Heriyanto et al., 1996.

Kiham Haloq

A n t a n

Gabus SS

U j o h B i l a n g (

Upper Tanjung

Kedango

Gabus (

Lower Berai

S e m b u l u

Belut

Seilok

Beriun Sembakung

v v v

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

North Sumatra

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

East Natuna Tarakan

Mang Kabua

Sujau

Mangkupa

+ ++ +

Oil

Mesaloi

BatuMarah Hidup Lst.

Middle Berai

Oil and gas

Barat

Barat Shale

West Natuna Central Sumatra

C r a t o n i c

South Sumatra Sunda After Fainstein & Meyer, 1998.

After Fainstein & Meyer, 1998, Michael & Adrian, 1996, Phillips et al., 1997.

0

500km

Kutai Barito

North West Java North East Java


Bengkulu basin (including the Mentawai 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 forearc, however, which may explain these unexpected but favorable findings.

rocks that occur in the Central and South Sumatra basins and also possible fluviolacustrine 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 subbasins developed and are also recognized in the Bose and Sipora grabens of the

North Sumatra basin

Malaysia

Simeulue 1

Singkel graben 2 3 4

Sibolga basin

Singapore

5 6

Nias

Central Sumatra basin

Pini graben

e

rc

ch ren

–a

at

or e

nd

Siberut

zo n

Su

af atr S um

lt fau tra ma Su

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

ba s in Pagar Jati graben South Sumatra Mentawai A#1 basin (Jenny) Bengkulu X#2 Mentawai C#1 (Jenny) (Jenny) Bengkulu X#1 (Jenny) Pagar Jati

5 cm/year

M

en

taw

fa ai

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

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

ul

Wells 1. Palembak 1 – Union Oil 2. Singkel 1 – Union Oil 3. Telaga 1 – Union Oil 4. Lakota 1 – Union Oil 5. Suma 1 – Union Oil 6. IbuSuma 1 – Caltex

Oil seeps Volcanoes

graben

tz

on

Bengkulu basin

Volcanics

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


Bengkulu A#1x (Amin Oil)

Bengkulu A#2x e (Amin Oil)

Arwana #1 (Fina)

Kedurang graben 0

100

200 km

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 forearc, and sediments comprise marine shales, silts and limestones, including some major

L-6036

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

Inline 1515 Ibusuma prospect

2km 0 200 400 600 800

1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400

Wave-resistant reef facies

Back lagoonal fill

Back reef storm and talus deposits

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


(>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 basin There 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

Sumatra

Sunda basin rm

u

rib

fo at pl

Se

Figure 8: Simplified map of structural elements in the Southwest Java basin (after Keetley et al., 1997).

Krakatau Tangerang high

it ra st

a nd u S Pull-apart half-graben

West Java

Ujung Kulon low West Honje Malimping high low

Ujung Kulon high Ujung Kulon 1a

DDH-1 Fig.9a

Bayah high Bayah

DDH-2

d ir an m Ci

Malimping block 0

Ciletuh high

50km

Fig.9b

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 sanddominated 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

(a)

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

(b)

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


u lt i fa

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.

Figure 10: Oil source characteristics for Indonesia’s petroleum systems (Ten Haven and Schiefelbein, 1995).

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 basins There 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, AsemAsem-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 oiltype 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 shallowmarine 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.

Legend Marine (Cenozoic) Marine (Mesozoic) Lacustrine (Cenozoic) Terrigenous (Cenozoic)


Th ai Ind land on es ia E1

rid

ge NW sub-basin

Central ridge

Ra

Mergui ridge

The 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.

Ranon g ridg e no n g tro ugh Ja ur idg e

North Sumatra basin

and Thail ysia la a M Malacca platform

NSBA-1

A s ah

m

PU

RP

oun

TF LA

t hr

t fr us

M OR

tai n

NSO

a si a ay esi al n M do In

ra

M TA

M isan Bar

at

Gebang

Kambuna

Glagah low

Pak ol

rch

te

m

Kuala Simpang

an a

EP DE

ys

Su

Rantau

Glagah-1

Pusung high

NG

lt s

Kuala Langsa

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

hor s t

IA

igh

Julu Rayeu South Alursiwah Lho Sukon PasePeulalu

Yang Besar high

M TA

high

NSBC-1 NSBJ-1 Duyung 1

p kon dee Lho Su

Arun Arun

deep

au nf tra ma Su

nh

ast Jawa e

P e us a ng a

Salamanga deep

Pakol low

Ridge EAO

Topaz deep

Darat

on

Wampu

t

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).

Batumandi

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

SW

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

SLS A-11 ST2

1.7

Two-way time, sec

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,

SLS A-3

2.0

2.4 0

1

2 km

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


NE

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.

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

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 ELAN

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).

Quartz

Deviation

0

Deg

Bound water

Fracture energy

Clay 1

-15 0 (dB/m)

50

DNS T Gamma ray

DSI waveform

0

(V/V)

FMI image

Conductive fracture True dip

Conductive fracture (sinusoid) Orientation north

SWF1 .FIL . Int

Volume Hole shape

Fracture orientation

1

Ener 0

(us)

20440

0

Deg

8450

Peutu limestone

8500

90

Figure 13: Log of fractured Peutu limestone reservoir in the Pase A Field, well Pase A6, onshore North Sumatra basin. Fractures are defined using the DSI* Dipole Shear Sonic Imager and FMI* Fullbore Formation MicroImager tools (Musgrove and Sunaryo, 1998).

8550

8600 Belumai formation

8650 Bruksah formation

8700

Meta formation


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 gasprone 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)

illustrated by the potential giant Kuala Langsa gas field (Caughey and Wahyudi, 1993). Smaller-scale, Peutu ageequivalent, 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 basin The 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

Ma

lay

sia

lam Ba

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–southoriented, 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, gasfilled 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

h ug tro

Ma lac

ca S

Bangko

tra it

Kulin

eep ral d Cent

Petani

Duri

Coastal plains block

Libo Minas Zamrud

Kotabatak

Paleogene depocenters

Beruk high

Oil field Gas field

Jakarta

d ren ik t Lir

Sumatra Java

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


Bengkalis trough

Central Sumatra Basin

0

400

800km

Figure 15: Field distribution along regional, north–south trending dextral transcurrent faults in the coastal plains block of Central Sumatra (Heidrick and Aulia, 1993).

Hudbay Caltex

Coastal plains block n ila mb Se

lift up

Sia kK ec il s yn clin e

Gatam Sabak

D Lalang

Benua

Mengkapen

Dusun

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Bengkalis depression

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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 halfgraben – 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, lakemargin 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

Bengkalis Island

ak Ot

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–southwestoriented 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.

25km Pull-apart

Pop-up

Uplift

Oil field

FWA A

A A

A

Figure 16: Kerogen assemblage dominated by fluorescent amorphinite (A) and degraded, 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.

I M

M

M M

K

O F

I

K

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 intraformational 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 rightlateral faulting was active throughout and produced early Miocene pull-apart basins.

O

F

M

I O

I

O

I M

Figure 17: Photomicrograph of the lower Sihapas (Menggala) reservoir sandstone, Kurau field, Central Sumatra basin showing partly leached feldspars (F), quartz overgrowth cement (O), authigenic kaolinite (K) and excellent 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 synrift 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 basin The 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 subbasins (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.

Figure 18: Generalized structural pattern of the Southern Sumatra region (after Yulihanto and Sosrowidjoyo, 1996).

igh

oh

xi m pro Ap

Ba

k ng

at

Ce

Su t ma

ntr al su Pale Palembang/ b-b m as ban North Palembang graben in g (sub-basin)

sin matra ba h Su out

in

n fS

Ipuh graben

tal

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ig gh

to

Dun Belas Mountains

h

Jambi graben (sub-basin)

ee xte

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e Lem

Kikim high Pagar Jati graben

Kedurang graben

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50

ata

ng f a u lt Lematang/ South Palembang graben (sub-basin)

Muaradua graben

Lampung high

Lampung graben

100km


The South Sumatra basin contains diverse petroleum systems, with both oil and gas being sourced from lacustrine and fluviodeltaic 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 fluviodeltaics (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.

Figure 19: Kerogens extracted from source facies in the South Sumatra basin. Top photograph shows terrestrial oil-prone source facies dominated by cutinite (C) and other land plant material. Bottom photograph shows lacustrine oil-prone source facies dominated by Botryococcus algae (A). (Photos courtesy of S. Noon.)

C C

A

A A A

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–southeastoriented 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 overmature source facies, which include lacustrine Botryococcus- and Pediastrumrich 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).

Figure 20: Formation MicroScanner* images from a fractured granite basement reservoir, South Sumatra basin.

N

Minor fractures strike

X6.0

X0.5 W

E

S

X6.5

X1.0

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Major fractures strike

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X2.0

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E

S


Figure 21: Leached skeletal packstone from the early Miocene Batu Raja formation, Air Sedang field, South Sumatra. Porosity includes molds (Mo), vugs (Vu) and channelized pores (Ch). (Longman et al., 1993.)

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).

M

Ch

o

Ch

Vu

Mo Vu Mo

Stage II. Sag (late Oligocene–early Miocene)

Stage III. Uplift (middle–late 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 gasprone 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 solutionenhanced (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 offbank 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.

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 shallowmarine 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 KenaliAsam, 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

Sunda and Asri basins The 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) Sunda platform

Sumatra

Asri

Yani-Nst Sunda Vera

Central Ardjuna

Seribu platform

South Ardjuna

Jakarta Ciputat

Kepuh

Cipunegara E 15 Graben Pasir Bunger

Jatibarang

Cirebon

Java Tanjung TWT scale < 0.5 sec 0.5 - 1.0 1.0 - 1.5 1.5 - 2.0 2.0 - 2.5 2.5 - 3.0 > 3.0 sec

Basement time structure

0

50 mile

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

Intan

Sumatra

Maxus Widuri Janti Yani Karmila Yvonne Kartini AV Nurbani AVS AA Farida Krisna Wanda Gita Bima 'ZU' Cint A Rama Kitty Duma Nora Selatan Utari Sundari

Arco APN

P

L-Parigi SC BTS MX MR LL BZZ B MM L MQ RDL

Jakarta

MB

FW FN

UR

KL

ES

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OW OU OO XM OO Kandang Haur OM PMK Cemara XK XW OB Pagaden GG Jatibarang SDS Gantar KPT FS

Tambun Jatinegara

HZE FI

E

Cilamaya Utara Pasirjadi

Pertamina

Java


Tugubarat

Randegan

Cirebon

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 intraformationally, 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 lowpermeability, 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.

Stage III. Uplift (Pliocene–Pleistocene)

Figure 23: Amplitude map of 33 series sand of the lower Miocene Upper Gita member of the Talang Akar formation. Meandering channel systems are clearly visible (modified from Armon et al.,1995).

During the Pliocene–Pleistocene, shallowand 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.

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Figure 24: Evidence for exposure including thin coals (left top), shale-filled karst pipes (middle) and karst breccia (right) in the early Miocene Batu Raja formation. Core from well Jelita 1, Sunda basin (Wicaksono et al., 1995).

2314ft


Northwest Java basin The 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 subbasins 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).

SW

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

Stage II. Sag (late Oligocene–late Miocene)

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 fluvialsand facies are also potentially good reservoir targets in the western part of the basin (Butterworth and Atkinson, 1993). Late synrift 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 deltafront 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.

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 subbasin (Noble et al., 1997), whereas more gasprone 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 openmarine 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.

Fore arc basin

Magmatic arc

Offshore

NE

Back arc basin

Offshore

Bogor trough

Sea level Volcaniclastics

Parigi Batu Raja

Melange

Continental crust (Sunda shield/Asia plate)

Subduction of oceanic crust (Indian plate) beneath Sunda shield

Jakarta

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


Turbidites

Lower Cibulakan Jatibarang volcanics

Oil reservoir

Java

Cisubuh

Stage III. Uplift (late Miocene–Pleistocene)

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, deepermarine shales. Stabilization again led to deposition of carbonates in the late Miocene, when preParigi and Parigi formations developed as relatively low-energy, fine-grained, shalylime 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-waterequivalent marine shales. Locally, these carbonates also form oil reservoirs in the onshore area.

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 basin

Figure 26: Generalized basin configuration for East and Northeast Java basins (after Manur and Barraclough, 1994).

mba h Re g zone Nort mban e R h t Sou

Ca n–

h

North Madura platform

p

ug

tro

l-d

r ma

de

Ba

pr

es

sio

n

h

ee

arc

Sakala sub-basin Sakala fault

Ce

nt

a Tub Kujung thrust belt

ra

an we

ne ng zo

mb

M

Mu

Sibaru platform

ale

-1

h

as

oug

JS

tr riah

rid

ge

ob

as in

The 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–southwesttrending 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 subbasin, 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

Madura

RMK Inversion zone

Kangea

n high

RMK wrench zone

South Madura sub-basin

K endeng zone

Lombok ridge Lombok sub-basin

Kendeng zone

Quaternary volcanic arc

East Java

Java Ge anticline

Bali Thrust structure located at inversion zone Normal fault, NE-trending separates basinal lows from highs Strike-slip movement/wrenching, located at flank area/basinal margin

Lombok

Platformal area, arch and ridge Basinal area RMK wrench zone (high)

0

100km

Southern basin


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. 2

3

4

54.75

1

Late Eocene transgression deposited the Ngimbang carbonates which are shallowmarine, 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. 5

6

7

87.30

55.05

89.80

Figure 27: Shallow cores from locations near Nanggulan, Central Java. These Eocene fluvio-deltaic shallow 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).


8

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

(a)

(d)

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

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

(b)

(e)

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

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

(c)

Figure 28c: Middle Miocene Ngrayong sandstone. These fine to medium grained deepwater sands are interpreted as deep sea fan and/or contourite. Primary intergranular porosity is good and reservoir potential is considered excellent. Shallower water Ngrayong facies reservoir oil onshore East Java basin (photo from Ardhana et al., 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–westoriented 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.

Figure 29: Physiographic and location map of Kalimantan with distribution of hydrocarbon fields (modified from Mamuaya et al., 1995).

Sulu Sea

Semporna fault t)

a si

Tarakan basin

eso Kuch zoi ing c o hig rog h eni cb el

y la

a

Maratua Ma ng fault ka Sa lih ng a ku kir an gf au lt Kutei basin lt

n

w i b a sin

Makassar straits rift

h)

ugh

Kerenden 1 Ara ng fau lt ( hig

r tro

Sunda shield

0

assa Mak

Paternoster shelf

Ase

M (op erat h u m- iolit s mo bas Asem ic c unt om ain in ple s x)

Barito basin

Java Sea

The 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.

Sulawesi

Ketungau basi

Mel a

au tf

(M

M

Barito basin

100 200km

160–200 km

W Stable Barito shelf

Barito foredeep

Barito basin Dahor

Figure 30: Schematic geological cross-section across the Northeast area of the Barito basin (Campbell et al., 1988).


Basemen t high

Zone of wrench faulting

WaruDahor kin Berai carbonates Tanjung sandstones

Tertiary sedimentary cover up to 15,000 ft thick

E Meratus Mountains

e

ng hu

Si

Paleogene grabens Basement massif Oil field Oil shows Thrust fault, late Miocene–Recent Wrench fault, late Miocene–Recent

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

Key

Pa nn rid aan ge M rid isi ge

Ka s rid ale ge

Figure 31: Structural map of the Northeast Barito basin showing Paleogene grabens and distribution of hydrocarbons. (After Mason et al., 1993; Rotinsulu et al 1993 and Satyana 1995).

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).

s no

Didi 1 Tanjung Kambitin Bagok 1

in s

M er

at us

Tapian Timur Warukin

M er a

tu

sM

ou

nt a

SE Kalimantan

Bangkau-1 Semuda-1

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

Miyawa 1

0

25

50km

Upper and lower Tanjung formation clastics, overlain by Berai formation carbonates, were deposited as a transgressive series passing from fluvio-deltaic and shallowmarine clastics, into platform limestones. These clastics and carbonates are minor proven reservoirs in the basin.

Stage III. Inversion (middle Miocene–Pleistocene)

Q V

Corrensite

V

L F

F

Q

V

V Q

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

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.


Figure 33: Summary geological map of the lower Kutei basin, with field locations and thickest (>2000 ft) kitchen areas (from Bates, 1996 and Paterson et al., 1997).

Kutei and Makassar basins

Upper Miocene Middle Miocene

Sangatta

Lower Miocene Oligocene Source kitchen > 2000 isopach

Kerindingan Melahin Serang Semberah Attaka Santan Badak

Lampake Nilam Sanga Sanga

Tambora

Tunu

Pamaguan Sisi Mutiara Beras Samboja

Wailawi

Handil Nubi NW Peciko

Bekapai

0

20km

Yakin Sepinggan

Figure 34: Kerogen dominated by vitrinite and cutinite extracted from Miocene oil- and gas-prone shales in the Kutei basin. (Photo courtesy of S. Noon.)

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.


The 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 shallowmarine 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).

Way-up

Be dd in g

8446.5

cm in 0 0 1

cm in 0 0

8443

2

1 2

(a)

1

3 1

(b)

3

Figure 35a: Thick (10 s m) coralline limestones are developed in the Miocene Mahakam section and demonstrate reservoir potential. These core segments are from the Serang field and demonstrate good, visible moldic porosity (Photo from Siemers et al., 1993a.)

B

B

B

B

PS

PS

PS

PS

Figure 35b: A thick (approximately 3 m) massive and extensive turbidite sheet sand enclosed in shale. Turbidite fans have recently become the focus of exploration in deep water offshore from the Mahakam Delta following Unocal’s Merah Besar and West Seno oil discoveries. (Photo courtesy of J. Decker.) Figure 35c: Four stacked, delta-front, coarsening upwards parasequences. Shales pass up into thinly laminated and/or bioturbated sandstone representing mouth bars. (Photo courtesy of P. Montaggioni.)

(c)

Upper channel

Shale plug

Coaly shale Lower channel

(e)

s -bed

lon x

Epsi

Coal

e ss

a ev Cr lay

Sp

Figure 35e: Stacked distributary channels with overbank shales and a 1-m thick coal seam. Largescale epsilon cross-beds represent lateral accretion, and both channels display erosional bases. (Photo courtesy of P. Montaggioni.)

Coaly shale (d)

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


Distributary channels

Area of lower photograph

Tide-dominated interdistributary zone Tidal channels

Mouth bars

Sea

Distributary channel

Tidal channel

Distributary channels

Tidal channels

Mouth bar

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 oiland gas-prone; more liptinitic or drifted coals and carbonaceous shales in estuarine or shallow-marine settings are more oilprone; and upper coastal plain and prodelta 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.

Figure 36: Modem Mahakam Delta distributary channel and mouth-bar reservoir analogs. (SLR image from Allen and Chambers, 1998, photos courtesy of P. Montaggioni.)

Belayan trough

Katudu anticline

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 halfgrabens 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.

Murung Pembulan Tenggarong Sebulu Separi Semberah anticline anticline anticline anticline anticline anticline

W Pembulan anticline

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

Badak trend

E Tenggarong anticline

Sebulu anticline

Separi Prangat anticline thrust outcrops

Semberah anticline

Badak/Nilam anticline

Present-day Mahakam delta Pliocene Upper Miocene Middle Miocene Lower Miocene

0


10 km

Figure 37: Geological cross-sections through East Kalimantan. Top: regional cross-section across the Kutei basin. Bottom: geological cross-section of the Samarinda anticlinorium. (Allen and Chambers, 1998.)

200 m 100 0m

Sy s

t em

Se m

Zone of shale diaprism and Vanda 1 thrusting

n e Fault

Ahus arch Sembakung field Bunyu Tapa Bunyu Bangkudulis arch field field Bunyu field Juata field Tarakan Pamusian arch field Tarakan sub-basin

po rn af au lt

East Vanda high

South China Sea Berau sub-basin Latih anticline Muara sub-basin

Intrusive South China Sea

Mangkalihat Peninsula 200m

lt

Neogene carbonate complex

au

Kalimantan

1000 m

af

atu

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

Sebatik arch

Figure 38: Generalized geological map of the Tarakan basin (from Lentini and Darman, 1996, with modifications from Netherwood and Wight, 1993).

ar

Stage III. Deltaic (early Miocene–Recent)

Semporna Peninsula

M

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.

Neogene extrusive

Tidung sub-basin

Ma y

Stage II. Sag (late Eocene–early Miocene)

Quaternary

Cretaceous

Neogene

Pre-Tertiary sediments with some igneous rocks

Paleogene

Igneous rock

Oil field

Gas field

0

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.

50

100km

(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.


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 basin The 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).

Figure 39: Vuggy porosity (left and middle) developed near the top of a carbonate buildup. Shaly platy coral facies (right) of the reef front. Pliocene, Vanda 1 well, Tarakan basin (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–southeasttrending 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.

Harimau

6000 trough 4000 506000 00

Natu na arch

100 0

00 60 00

50 40 00 600 0

5000

10 00

Areas where sediment is < 3000m thick Terumbu carbonates – Miocene

30 00

Ma Ind lays on ia es ia

Areas where depth to basement > 4000m

rea

al a

0 300 0

gh

Natuna Island

lf she da n Su Anambas Islands

50km

0

rou

gt

kan

So

Natuna Sea

00 40 0 0 30 0 0 20 00 10

25

-199

asin

400

2

G P NS

AV 1X

Laut Island 0 00

1000

00 3000 4000

Penyu basin 0

Kepiting 1

h hi g bur1000 u l e S 20

Kelu 1

'L' Structure

er b Out

AI-IX

AP 1X Banteng 1&2

200 nai s-Ra Pau idge r

Central i Kakap KF high m u i-c au graben 0 m 50000 3000 Cu late CCE 1 60 0 as b p m 700 igh 4000 Ten Terubuk na ben ary h ggo d A n 00 a 40 Ikan Pari 1 u l arc 0 Bo gr 00 00 al graben h Belut 1 0 Bawal 5 aw Forel 5 B 4000 GP Kerisi 1 00 20 20 N Belida BuntaiTembong 00 S- Udang 3000 12 5 Sembilang 1 Sepat 1 Kodok 1 Sotong 40 00 Anding

00

Bursa 1X

4000

KRA 1

2000

5000 Duyong

10

2000

1000

KH

Komodo graben

high

0 300

Anoa

00

00

0 100

00 30

0 100

sin

20

0 100

00 30 000 4

0

Segili Tinggi Tiong M Bekok ala Anoa yb 50 Pulai 00 a

2000

400

20

00

1000

2000

2000

3000

Palas

Terumbu carbonate 40platform

00 10

00

West Luconia delta

5000

10

Tabu Guntong Tapis

4000

Khorat platform

Sokang 1

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

Oil field/discovery Gas field/discovery

NW

SE 0

0 West Natuna basin – Line GPNS-125

Muda formation

Muda formation 1000

1000

Inner Arang unconform

it y

Arang formation

Arang formation

Barat formation 2000

Barat formation Gabus formation

Gabus formation Pre-Gabus

3000

Depth, m

2000

Figure 41: Play concepts for West Natuna basin (after Fainstein and Meyer, 1998).

3000

Syn-rift sediments Syn-rift sediments 4000

4000 Inverted half-grabens containing lacustrine and marginal marine source rocks


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 subbasin. One of the major problems with the

proximal deltaic sands to date, however, is poor reservoir quality, with thin, finegrained 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 basin The 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–southeastoriented 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

Figure 42: Chlorococcalean type algae, Pediastrum, typical of lacustrine source rocks in Western Indonesia, Oligocene, West Natuna basin (photo courtesy of S. Noon).


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, openlacustrine 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).

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

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

The late Oligocene–early Miocene is characterized by deposition of fluviolacustrine 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.

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 oiland 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.

Bursa oil discovery

NW

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).

'L' structure Natuna gas field

SE

0

0 East Natuna basin – Line GPNS-199 Muda formation 1000

1000

2000 Gabus formation Pre-Gabus 3000

Top-oil windo

w

Top-gas

window

Arang formation

2000

Gabus formation Pre-Gabus

Gabus formation

Depth, m

Arang formation

Supergiant 'L' structure 45Tcf

Figure 43: Play concepts for East Natuna basin (Fainstein and Meyer, 1998).

Arang formation

3000 Gabus formation

4000

5000

4000

Source of hydrocarbons probably lower Arang and Gabus shales

Pre-Gabus

Kitchen for 'L' structure gas

5000


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 synrift 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

Sulawesi Southwest

Late

5

Late Middle

Fufa Wahat

Tacipi Upper Camba/ Baturare volcanics

Celebes molasse Enrekang volcanics

Lower Camba

Buakayu

Sele

Sele

Upper platform and reefal limestones

Klasafet Kais

Barracouta (Woodbine group) Woodbine group

Seka

Oliver

Kais

Sago Makale (Tonasa)

Tonasa 30

Early Late

Upper Nief

Sirga

Lower platform limestone

Toradja

Malawa

Sirga Ofu formation Onin

60 65 70 80

Basal clastics

Bua volcanics

Imskin/Waripi

?

Latimojong

Imskin

Monu

+

Cretaceous

+ + Not present in Tomori wells

Naktunu Kembelangan

Oe Baat

Kola shale

150

Ashmore Darwin Flamingo

Flamingo group

Plover

Manusela

Middle

Waingalu

Granite?

Kembelangan

Wai Luti

Saman-Saman Early

Grebe/Puffin Johnson Waingalu

Lower Nief

100

Late

Cartier

(Baham)

Faumi

Prion & Hibernia Langi volcanics

Early

Mesozoic

Viqueque

Arafura Sea (limited information)

Kais

20

50

Paleocene

Jurassic

Bonaparte basin (ZOC)

Steen kool

Klasafet

Clastic coal unit

West Timor (limited information)

Batu Putih

Klasaman

Salas complex

15

40

Timor region Bintuni

Middle

Late Early Upper

Early

Miocene Eocene

Oligocene

Cenozoic Paleogene

Salawati

n ogu Klam

Neogene

Pliocene

Pleist.

The 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

West Irian Jaya

Seram

Tomori (limited information)

Walanae

Holo.

Early

Quat.

West-central

East Natuna basin

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 syninversion 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.

Malita

Tipuma

200

Permian

Triassic

Cape Londonderry Late Middle Early Late

Devonian Silurian

Unnamed basement

+ 300

Babulu

Kanikeh

Tipuma

+

250

Early

Carboniferous Paleozoic

+

+

Kobipoto Tehoru

Age uncertain

+

400

+

Ainim

Aifat

Aifat

Cibas

Aimau

Aimau

Atehoe

Kemum

+ meta-sedimentary

+

Ordovician Cambrian

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

Davies, 1989.

Figure 44: Summary of basin stratigraphy in Eastern Indonesia.


Kemp, 1993, 1995.

Livingstone et al., 1993, Fainstein, 1998a, Lunt & Djaafar, 1991.

Maubisso

Fossilhead group Kulshill group

Hyland Bay

Weaber group Arafura group

Goulburn group Wessel group

Salawati granite

Precambrian

Mount Goodwin

Kulshill group Weaber group Arafura group

Kemum meta-sedimentary

+

500

Aifulu Niof

Ainim

Lunt & Djaafar, 1991, Fainstein, 1998a.

Goulburn group Wessel group

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

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)

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

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 Indonesia The 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).


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

Trend of volcanic inner arc

ucca

Sea

EURASIAN PLATE

Mol

PACIFIC PLATE

Sulawesi Sorong fault

North Ban da

Buru Seram

Sor o ng fault zo ne Salawati basin Bintuni basin arc h

Irian Jaya

Ar

ut

Ba nda rou gh

arc h

Banda Sea

So u t h

Flores Sumba

r mo

Ti

tr Timor

ough

AUSTRALIAN PLATE

7cm/year

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

Kalimantan

Celebes Sea (oceanic crust)

North arm (Magmatic arc)

(Magmatic arc) Halmahera

(at ten uat Ma ed kas As ian ar str con ait tin ent al c rus t)

Manado

Molluca Sea (oceanic crust)

Samarinda

Mamasa

A

Figure 46: Tectonic setting of Sulawesi with origins of Sulawesi fragments indicated (from Guritno et al., 1996).

East arm

Palu

Tiaka field Sula platform (Gondwana continental crust)

Sulawesi ? A'

Sundaland

Kendari

Banda Sea (oceanic crust with Gondwanaderived continental fragments)

Ujung Pandang South arm Legend Ophiolite

Buru

South East arm

Tukang Besi platform (Gondwana continental crust)

Metamorphic rock Paleogene/Neogene sediments Oceanic crust Continental crust Oil seep Gas seep

0

100 200km

East A' South Sulawesi x

Bone Bay Southeast Sulawesi x

Sundaland Mesozoic–Cenozoic lithosphere Scale vertical = horizontal


x

Australian-derived Proterozoic–Paleozoic lithosphere

Banda Sea

0 20 40 60 80 100

km

West Makassar Strait

Fault

Continental crust

upu

0 20 40 60 80 100

Legend Subduction zone

Mas

A

PHILIPPINE SEA PLATE

Figure 47: Regional crosssection across southern Sulawesi 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.

Sulawesi Sulawesi 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 Sulawesi In 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 deepmarine 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 intramontane 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 Sulawesi Davies (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 BanggaiSula 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)


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.

Seram Seram 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.

N

Oceanic crust

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Ambon volcanic arc

Thrust belt foreland basins

Seram thrust belt

Accretionary wedge and melange

Seram trough V V V + + +

+

Triass ic

+

to u p p

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e r M io c e n e

+

Figure 48

+

Pre-Triassic

Banda Sea (oceanic crust)

Australian plate

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

S

Line IJ97 - 0193

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N 2286

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2286

Figure 49: Detail of seismic line across the Seram trough (Fainstein, 1998a).

Western Irian Jaya

new speculative seismic surveys (e.g., Fainstein, 1998a) demonstrate the existence of further, commonly large Miocene carbonate buildups offshore in the Salawati basin.

Western 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,

Salawati and Bintuni basins The 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

Figure 50: Manusela formation carbonates in the East Nief 1 well, Seram. Ooid grainstone (left) with intergranular porosity. Dolostone (right) with modified vugular pores and black residual oil (Kemp, 1993).

Waigeo Weda basin 0

Tosem block

100km

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Salawati basin

Ayamaru plateau

Walio

Yapen fault

tre

Roabiba 1 Ubadari 1

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belt fold guru Leng

Se ram

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ridge

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ch

ne lt zo n fau Wandame

Wiriagar Wiriagar deep

lt fau

ak Sek

Mis Berau basin oo Kepal l a Bur ung Onin fore dee anticline Wahai basin pb Onin asi Bula basin n

Seram Island

iki ns Ra

Mogoi Wasian

Misool

n

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 preTertiary 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.

Kumawa Basins Continental crust

Aiduna fault

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).


Kasim stage U marker Walio–Jaya stage

West Kasim field

Kasim field

Jaya field

Reef

Cendrawash field

Textularia II

Shale

Cendrawasia–Kasim Utara stage

Platform stage

Figure 52: Stages in the development of the early Miocene Kais formation carbonate buildups, Salawati basin, Irian Jaya (Livingstone et al., 1993).

Kais platform

W

E

Kasim Utara field

1350ft

U marker

200 ft 125 ft

Kasim field

Walio field

Reef

Argillaceous limestone

Shale

Textularia II Shelf/shoal

650 ft

Possible earlier reef stage Kais platform

N

S

Reef stages

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 fluviodeltaic 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

Figure 53: Early Miocene carbonates, Bintuni basin. Dolomitized Kais formation (left) with excellent intercrystalline porosity. Mogoi formation planktonic foraminiferal packstone (right) with fracture porosity.

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 sealevel 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 Kaisequivalent 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.

Tanimbar Island

gh r trou Timo

Dili

d lan in r Is bas o ue q Tim e V i qu ge ran

ern rth e o N ang r sin Kupang a lb n a ntr ther e C ou S Bena basin

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Oil field

Late Jurassic early Cretaceous (Flamingo group)

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Triassic-mid-Jurassic Mount Goodwin and Plover formations

ul Sah rm o f plat

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5 1

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Sunrise 1

ul

a nesi Indo alia tr Aus

esia Indon ia al Austr

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-C Zoc -A Zoc -B Zoc

Indonesia–Australia zone of cooperation Oil fields 1. Puffin 2. Skua 3. Oliver 1 4. Jabiru 5. Challis

Petrel sub-basin

Australia

6. Corallina 7. Laminaria 8. Kakatua 9. Elang 10. Undan/Bayu

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


Other basins in Western Irian Jaya Other 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 Sea The 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 halfgraben (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

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

Cretaceous Kambelangan (Flamingo) group, and Permian clastics have also been targeted in the past (e.g., ASM 1X). Gasprone source rocks may include PermianCarboniferous 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.

Pleistocene to present day Pseudo-outer non-volcanic arc

Extinct (Pematian) inner volcanic arc

Timor trough

Alor Island

N

S

Timor Sea

Timor Island

Figure 55: Schematic north–south crosssection across the Timor Volcanic arc and the Timor subduction zone (Sawyer et al., 1993).

Australian crust

Oceanic upper mantle

Continental upper mantle Present-day earthquake epicenters

Line-tie SP

3817.33

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3.000

Sea floor

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Paleogene prism Paleocene Aptian Cretaceous Jurassic

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Figure 56: Southwest–northwest seismic line across the northern part of the Bonaparte basin, shelf and slope, the Timor trough and the Timor accretionary wedge (Fainstein, 1996b).

4.000

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Permian

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10.000


Geothermal energy Indonesia 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 northwardsmoving 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.

SW

NE

Londonerry high Avocet-1A

Sahul syncline

Garganey-1

Flamingo syncline

Flamingo high Iris-1

Flamingo-1

Timor trough

Kelp high (Sahul platform)

Elang-1

Mandar-1

Hydra-1

Kelp-1

0 Miocene unconformity Tertiary carbonates

1

Depth, km

2 un Bre co aku nfo p rm ity

3

Plo ve r

4 (un

Tri a

fer ssi en c tia ted )

dif

5

Ma li

fm

o nf dis c tian y p A B ase rmit Bre nfo a k u p u nco

Darwin fm/ Flamingo gp

fm

ta

Base Tertiary

Bathurst Island group

M

on

ta r

o r m it

y

disconformity Montara beds/Elang formation

fm P l o ve r fm Malita

sic Triafesrentiated)

(undif

a beds

6

7 0

50 km

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


ian

rm

Pe

Figure 58: The ‘Ring of Fire’, a volcanic belt that encircles the Pacific Ocean is the result of consumption of the Pacific and Indian ocean plates at the oceanic trench systems (subduction zones).

Aleutian trench Kurile trench

FIR

RI NG

OF

E

Japan trench

Pacific Ocean

Ryukyu trench Philippine trench

Indonesia Bougainville trench Sunda trench system

Middle America trench

Equator

Peru-Chile trench

Tonga trench

Oceanic crust

Tre n

ch

Volcan ic arc

Kermadec trench

Continental crust

Lithosphere

Lithosphere

Asthenosphere Oceanic-continental convergence

Figure 59: Location of hydrothermal prospects in Indonesia.

South China Sea sia

lay

Ma

1 2

11

3

Kalimantan

ra at

m

Su Sulawesi

Ambon Irian Java

Jawa Sea

5

Banda Sea

10

Flores Sea

4

Java 6

7

8

9

Bali Sumbawa

Flores Sumba

Location of main geothermal prospects Drilled prospects

Sumatra 1. Sibayak 2. Tarutung 3. Pusuk Bukit 4. Ulubelu

Timor

0

Java 5. Salak 6. Wayang–Windu 7. Darajat 8. Kamojang 9. Karaha 10. Dieng

400

800

1000km

Sulawesi 11. Lahendong


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

Eroded stratovolcano

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.

Lateral outflow and water rock interaction Rainfall

Vadose zone

Piezometric surface of deep, single-phase reservoir

Weak fumeroles and gas heated features

Limited boiling

Acid sulfate springs

Acid sulfate aquifer Zone of fluid mixing and mineral deposition

Sulfate–bicarbonate springs

Neutral chloride springs, possibly sinters Sea level

Limited boiling and gas separation on localized vertical permeability

Lateral outflow Recharge

Convecting neutral chloride geothermal fluid

Early venting of magmatic volatiles; porphyry type mineralization

Cooling intrusion

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


Local boiling

The future

Western Indonesia

Post-rift sequences

Indonesia 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 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.

The 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 deltafront 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. Fluviodeltaic and shallow-marine Miocene sands demonstrate very limited remaining potential for structural traps in the onshore area, with smaller and more subtle faultand 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).

N

Figure 61: Formation MicroScanner image of a fractured hydrothermal reservoir showing fracture orientations.

W

E

Fracture dip azimuth S


Syn-rift sequence

Other play types

The 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 shallowlacustrine 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.

Depending 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 TerangSirasun 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 Western Indonesia Attractive PSC terms have been offered by Pertamina for exploration in frontier areas in Western Indonesia. These include preTertiary 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.

Eastern Indonesia Eastern 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 plays With 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 fluviodeltaic 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 plays Western 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 nonprospective 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 sources The 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.


Geology Indonesia

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