899*

GEOLOGICAL SURVEY CIRCULAR 899

Assessment of Undiscovered 

Conventionally Recoverable 

Petroleum Resources of 

Indonesia
Assessment of Undiscovered 

Conventionally Recoverable 

Petroleum Resources of 

Indonesia

By Joseph P. Riva, Jr. 

GEOLOGICAL SURVEY CIRCULAR 899

Prepared in cooperation with 

Congressional Research Service, 

Library of Congress, 

Washington, D.C.

A resource assessment and a brief 

description of the petroleum geology, 

including play distribution, that accounts for 

the petroleum accumulation in Indonesia

1983
United States Department of the Interior

JAMES G.WATT, Secretary

Geological Survey

Dallas L. Peck, Director

Library of Congress Cataloging in Publication Data

Riva, Joseph P.

Assessment of undiscovered conventionally recoverable petroleum resources of Indonesia.

(Geological Survey circular ; 899)

"Prepared in cooperation with Congressional Research 

Service, Library of Congress, Washington, B.C."

Bibliography: p.

1. Oil fields Indonesia. 2. Petroleum Geology 

Indonesia. I. Library of Congress. Congressional 

Research Service. II. Title. III. Series. 

QE75.C5 no. 899 CTN876.I553 557-3: s 83-60021*9

C553.2»82 f 095983

Free on application to Distribution Branch, Text Products Section, 

U. S. Geological Survey, 604 South Pickett Street, Alexandria, MA 22304
ASSESSMENT OF ENERGY RESOURCES

The World Energy Resources Program of the U.S. Geological Survey intends 

to develop reliable and credible estimates of undiscovered petroleum resources 

throughout the world. Initial program efforts have focused on the major producing areas of the world in order to gain a broad geological understanding of the 

characteristics of petroleum occurrence for resource assessment as well as for 

analysis of production potential. Investigations of production potential are carried out in cooperation with other U.S. Government agencies; specifically, studies 

of the main exporting nations of the free world, of which this study is a part, are 

carried out in cooperation with the Foreign Energy Supply Assessment Program 

of the Department of Energy.

The program seeks to investigate resource potential at the basin level, primarily through analogy with other petroleum regions, and thus does not necessarily 

require current exploration information commonly held to be proprietary. In conducting the investigations, we intend to build a support base of publicly available 

data and geologic synthesis against which to measure the progress of exploration 

and thereby validate the assessment. Most of these investigations will lead directly 

to quantitative resource assessments; to be effective, resource assessment, like 

exploration, must be an ongoing process that takes advantage of changing ideas 

and data availability-the results produced are but progress reports reflecting on 

a state of knowledge at a point in time. Because the program is coordinated with 

the Geological Survey's domestic assessment program and uses similar assessment techniques, the user can be assured that a thread of consistency will permit 

comparisons between the various petroleum basins of the world, including those 

in the United States, that have been assessed in the overall Survey program.

In addition to resource estimates, the program provides a regional base of understanding for in-country exploration analysis and for analysis of media reports 

regarding the exploratory success or failure of ventures in studied areas.

Geological Survey publications relating to the assessment of undiscovered conventionally recoverable petroleum resources include the following:

Open-File Report 81-986 - Assessment of conventionally recoverable petroleum resources of Persian

Gulf basin and Zagros Fold Belt (Arabian-Iranian basin)

Open-File Report 81-1027-Assessment of conventionally recoverable petroleum resources, VolgaUrals basin, U.S.S.R.

Open-File Report 81-1142-Assessment of conventionally recoverable petroleum resources of Indonesia 

Open-File Report 81-1143 - Assessment of conventionally recoverable petroleum resources of northeastern Mexico

Open-File Report 81-1144-Assessment of conventionally recoverable petroleum resources of southeastern Mexico, northern Guatemala, and Belize

Open-File Report 81-1145-Assessment of conventionally recoverable petroleum resources of Trinidad 

Open-File Report 81-1146-Assessment of conventionally recoverable petroleum resources of Venezuela 

Open-File Report 81-1147-Assessment of conventionally recoverable petroleum resources of the West 

Siberian basin and Kara Sea basin, U.S.S.R.

These reports are available from Open-File Services Section, Branch of Distribution, U.S. Geological 

Survey, Box 25425, Federal Center, Denver, CO 80225.
CONTENTS

Page

Abstract ....................................................... 1

Introduction _.____.__.._.....................__.....___........__ 1

Regional geology ..__.__..._..._............__........_........_--. 2

Petroleum geology _._______._.__..........._._........---.-..._--- 3

Significant petroleum basins __________________________________________ 7

North Sumatra basin _...__..__............_._.......__..._...__. 7

Central Sumatra basin ..__..._......__........__.....__-----.-.__ 9

South Sumatra basin ..........._.._..........__.....__........__ 10

Northwest Java basin 1........_.___..__.......__.....___--...-.- 10

East Java basin _................_.._......_.__......_.---..-.. 11

Salawati basin ..............__.__..._......_.........----..-.. 11

Waropen basin _....._........._.._........._.._...._._.._..... 12

Kutei basin .................................................. 12

Tarakan basin ..........._..____.__..._.......__......__--...-. 13

Barito basin .._.............___._____.......___...._-----.-..- 13

Natuna basin .............__.___..._.........___......._-----. 13

Arafura basin .............._.___.._.........._........._-.-.-. 14

North Ceram (Bula) basin ...._.............___......__.--...._--- 14

Bone basin .__................_.___._..._._......._----..-___- 14

Resource assessment .............____.__._.............._---.-.---_ 14

References cited ..........._..____.._.._._......._._....__-.-.-.._ 17

ILLUSTRATIONS

Page

FIGURE 1. Map of sedimentary basins and major oil and gas fields of the Indonesian region .................. 4

2. Lithospheric plates of the world showing boundaries that are presently active .__-_-.---.-.------- 6

3. Diagrammatic cross section of producing Tertiary plays in Indonesia _....._._._.--------.----- 7

4. Indonesian undiscovered recoverable oil.... _________..._..__.------._----------_------ 16

5. Indonesian undiscovered recoverable total gas ______.__...__--_---------------------.--- 16

TABLES

Page

TABLE 1. Summary of petroleum information for Indonesia __..__._....._.-------_----------_-.----- 8

2. Assessment of undiscovered conventionally recoverable petroleum resources in Indonesia ............. 15

3. Supplementary and comparative data relative to petroleum resource assessment of Indonesia .......... 15
ACKNOWLEDGMENTS

The resource assessment for this report was prepared in collaboration with the 

Resource Appraisal Group of the Branch of Oil and Gas Resources.

VI
Assessment of Undiscovered Conventionally

Recoverable Petroleum Resources of

Indonesia

By Joseph P. Riva, Jr. 1

ABSTRACT

The estimates of undiscovered conventionally recoverable 

petroleum in Indonesia at probability levels of 95 percent, 5 

percent, and statistical mean are for oil (in billions of barrels): 

5, 35, and 16; and for gas (in trillions of cubic feet): 13, 94, and 

42.

In Indonesia, petroleum occurs in five types of basins: forearc, back-arc (foreland), median, inner-arc, and downwarpinto-small-ocean basins. The back-arc, median, and downwarp 

basins have significantly greater petroleum potential than do 

the fore-arc and inner-arc basins. The latter two types are expected to yield only small discoveries; also, significant portions 

of such basins Me in water depths in excess of 1,000 m. The 

back-arc basins have been the most petroleum productive, but 

they also have been the most extensively explored. The greatest undiscovered petroleum potential is estimated to lie in the 

downwarp and median basins.

In Indonesia, six general types of geological settings or plays 

have been identified as being favorable for petroleum accumulation. They are transgressive clastic sequences, regressive 

clastic sequences, deltas, carbonate platforms, pinnacle reefs, 

and fractured igneous and volcanic rocks. The multiple-pay 

transgressive clastic reservoirs in the back-arc basins have 

produced most of Indonesia's crude oil. In several basins, carbonate platform porosity has become a primary exploration 

target, but each reservoir (reef, bank, or bioclastic zone) tends 

to be restricted in size.

Typically, Indonesian oil is of medium gravity with a paraffin 

base and has a moderate to high pour point, a low sulfur content, and a relatively low gas to oil ratio.

INTRODUCTION

The history of Indonesian petroleum exploration 

and development can be divided into several 

phases (Bee, 1980). The pioneering phase began in

Congressional Research Service, Washington, DC 20540.

the 1880's and lasted into the early 1930's. Such 

early work was confined to onshore areas mainly 

on the larger islands. The second phase, the modern onshore phase, took place from about 1930 to 

1965. The first phase of exploration had been 

accomplished mostly by surface mapping, shallowcore drilling, and the drilling of oil seeps. The second phase was marked by the introduction of 

geophysical techniques, especially seismic surveys, which permitted the evaluation of deeper 

prospects. The fields that were discovered early 

were generally in shallow horizons, but in 5 of the 

11 producing Tertiary basins, the largest field was 

discovered before 1930, in the preseismic phase. 

The third phase of exploration began in 1966 with 

the signing of the first offshore production sharing 

contract. This new phase was made possible by 

advances in offshore drilling and production technology. Although most of the work from mid-1960 

to mid-1970 was done offshore, considerable onshore exploration was also going on, usually in remote areas made accessible by the use of helicopters. Exploration was mostly done by seismic surveys, but geological mapping continued to play a 

necessary part. This phase of accelerated exploration, which is sometimes called the "quiet boom," 

came to an end in 1974 with a significant downward trend in oil exploration. Throughout the 

mid-1970's, exploratory activity was low due to a 

general reorganization of the Indonesian state oil 

company, Pertamma, that resulted in the renegotiation of contracts with the international oil 

companies to provide an increased government 

share of the generated revenue. The latest exploration phase began in 1978 with governmental assurances of fiscal stability *and conciliatory incentives. By the middle of 1980, Indonesia was experiencing an exploration boom that has continued 

into 1982 (Cowan and Parker, 1982).
REGIONAL GEOLOGY

Indonesia comprises the central part of a great 

archipelago that extends between Southeast Asia 

and Australia (fig 1). Geologically, the East Indian 

Archipelago is one of the most intricate parts of 

the Earth's surface and has enormous crustal relief. The difference in altitude between the mountain ranges capped by perennial snow and the adjacent deep-sea troughs approaches 15,000 m. The 

largest of the Indonesian islands are Sumatra, 

Kalimantan (Borneo), Sulawesi (Celebes), Java, 

Timor, and Irian Jaya (New Guinea).

Zones of earthquake and volcanic activity can be 

used to divide Indonesia into four large regions 

that are parts of tectonic plates (fig. 2). The Eurasian cratonic plate contains the submerged Sunda 

Shelf in the northwest and most of the island system: Sumatra, Java, Kalimantan, and a part of 

Timor and Sulawesi. The Indian-Australian plate 

contains the remainder of the island system, 

Timor and Irian Jaya, as well as the bounding 

Java trench. To the northwest, the Caroline and 

Philippine Sea plates bound the Indonesian land 

areas.

Superimposed upon these plates are some 28 

Tertiary basins, mostly initiated by tectonic movements at the end of Mesozoic time. Little is known 

about the Paleozoic and Mesozoic rock sequences 

that locally may underlie these basins. The oldest 

rocks in the region are Precambrian crystalline 

schists, which have been encountered in drill holes 

in Irian Jaya and crop out on the small island of 

Bum. The oldest fossiliferous deposits in the region are middle and late Paleozoic in age and have 

been found mainly on Sumatra and Kalimantan. 

During the Mesozoic Era, new sedimentary belts 

evolved in Indonesia. Triassic and Jurassic age 

rocks are known from many islands. In Timor and 

in many smaller islands, Triassic sediments have 

been described as"flysch-like"and have been observed to be "more or less oil-bearing" in some 

areas (Schuppli, 1946). Beds of Early Cretaceous 

age have been reported from only a few areas; 

beds of Late Cretaceous age, however, are widespread. The Tethys character of these beds and of 

the Mesozoic in general is very pronounced in certain areas: the association of radiolarian-bearing 

beds and ophiolites/is typical of both the Mediterranean and the Indonesian areas. Remarkable 

similarities of other fauna! and lithologic characteristics between the two regions indicate similar 

depositional environments.

Orogenic movements during the Cenozoic Era 

gave the region its present configuration. Considerable Tertiary volcanic activity occurred in most 

parts of the archipelago, producing intercalated 

tuffs, breccias, and lava flows. About 75 percent of 

the surface of the islands consists of sediments 

and volcanic deposits of Cenozoic age. The Tertiary sediments in the various basins in some 

cases were deposited under conditions of high 

rates of sedimentation and reach a composite 

thickness exceeding 15,000 m. The 28 Tertiary basins of Indonesia contain a total of 14.5 million km3 

(3.5 million mi3) of Tertiary sediments (Fletcher 

and Soeparjadi, 1977). Of this total, about 20 percent is middle Miocene or older. The bulk of the 

rest is Pliocene and Pleistocene in age. Most of 

the oil and gas discoveries have occurred in early 

and middle Miocene age rocks.

Sedimentation in the Tertiary basins was cyclic, 

characterized by repetitions of marine transgressions, which commonly led to bathyal depositional 

conditions and finally terminated with a regression. However, local conditions have affected the 

stratigraphic sequences of each basin.

The Tertiary basins of Indonesia represent five 

general types (fig. 1): fore-arc, inner-arc, back-arc 

(foreland), median, and downwarp-into-smallocean basins. Fore-arc basins are located on the 

oceanic side of active volcanic arcs and lie between 

the arcs and the subduction boundaries of the 

major crustal plates. Sediments in these basins 

consist primarily of outer shelf to neritic shale, 

marl, and limestone, which are often interbedded 

with volcanic rocks. Because of low heat flow, 

poor reservoir rock quality, and a lack of trapping 

structures, fore-arc basins are generally unfavorable habitats for petroleum.

Inner-arc basins are formed behind active arcs 

and are superimposed on the oceanic plate margins. They occur in the same relative position as 

a back-arc basin but without a proximal adjoining 

craton. Thus, they do not have a quality source 

for prograding sedimentary wedges likely to provide reservoir potential. Those inner-arc basins 

which commonly contain thin and geochemically 

immature sedimentary sections are likely to have 

only marginal petroleum potential. Several of the 

basins classed as inner arc, however, do have relatively thick sections of sedimentary rocks (e.g., 

Bone, Gorontalo, and Halmahera basins), and the 

deeper parts of these basins may have been subjected to sufficiently high temperatures to generate petroleum. For the most part, these basins are
located in fairly deep waters and have not as yet 

been drilled.

Back-arc basins are located on the cratonic side 

of the volcanic arc and are formed by the relative 

subsidence of cratonic plates behind active arcs, 

and thus, are superimposed on continental plate 

margins. They contain indigenous carbonate sediments or prograding wedges of clastic sediments 

from the adjoining craton interbedded with abundant amounts of organic material. High geothermal gradients are common. Tectonic activity promotes good structural development. Prolific petroleum discoveries have been made in Indonesian 

back-arc basins, and good potential remains for future discoveries.

Median basins are small basins of irregular 

profile that are formed in the "median zone" between a subduction zone and the basins of the craton (Klemme, 1980). These basins commonly contain clastic sediments, the later cycles of which 

may be massive delta complexes. Interbedded 

shales provide both source and cap rock for the 

sandstone reservoirs, and the heat flow is 

sufficient to mature the source shales. Prolific petroleum discoveries have been made in Indonesian 

median basins, and good potential for future discoveries remains.

Downwarp basins occur on the continental margins and open into small ocean basins. They are 

asymmetric in profile and contain good potential 

source and reservoir rocks and high geothermal 

gradients.

The 28 Tertiary basins of Indonesia are classified as follows (see figure 1 for location): 

Fore-arc: North Ceram, Sumatra fore-arc, Java

fore-arc, Lombok, and Savu basins 

Inner-arc: Bone, Flores, Bali, South Banda,

Weber, North Banda, Gorontalo, Celebes,

and Halmahera basins 

Back-arc: North Sumatra, Central Sumatra, South

Sumatra, Northwest Java, East Java,

Salawati, and Waropen basins 

Median: Kutei, Tarakan, Melawi, Barito, and

South Makassar basins 

Downwarp: Natuna and Arafura basins

PETROLEUM GEOLOGY

In Indonesia, six general types of geological environments or processes have been recognized as 

being favorable plays for petroleum exporation

(Soeparjadi and others, 1975). These are transgressive clastic sequences, regressive clastic sequences, deltas, carbonate platforms, pinnacle 

reefs, and fractured igneous and volcanic rocks 

(fig. 3). These environments occur primarily in 

rocks of Tertiary age.

Transgressive clastic sequences contain coarsegrained, quartz-rich sandstones that were deposited by processes associated with a relative rise in 

sea level. These sand wedges, deposited in fluvial 

and nearshore environments and in deepwater environments by turbidity currents, generally require a nearby quartz-rich provenance for good 

reservoir development. When overlain by a seal of 

marine shales, with older nonmarine or timeequivalent marine shales as source rocks, and 

folded into large anticlines, multiple-pay transgressive reservoirs provide excellent habitats for 

petroleum and indeed are responsible for most of 

Indonesia's crude oil. Transgressive clastic reservoirs are common in back-arc basins having high 

geothermal gradients, which likely contributed to 

a more efficient generation of petroleum from the 

local source rocks. The high geothermal gradients 

presumably are associated with the generally high 

tectonic activity of the Indonesian area.

The oil produced from this environment ("typical Sumatran crude") is characteristically of 

medium gravity, with a paraffin base (waxy), and 

has a moderate to high pour point, a low sulfur 

content, and a relatively low gas to oil ratio 

(Soeparjadi and others, 1975).

Regressive clastic sequences are medium- to 

fine-grained, quartz-rich deposits that result from 

processes associated with a relative fall in sea 

level. The wedge-shaped sandstones are deposited 

in nearshore to open marine environments. 

Shoreline oscillation accompanying tectonic subsidence commonly results in multiple-pay sands; 

structural traps act as primary reservoirs for the 

petroleum. Much of the oil found in regressive 

clastic reservoirs is paraffin based, medium to 

high gravity, and has a low to moderate pour 

point, a low sulfur content, and a low gas to oil 

ratio. Some of the reservoirs, however, contain an 

overlying cap of asphalt base and low to medium 

gravity oil, having a slightly higher sulfur content, 

that has resulted from the biodegradation of the 

oil (Soeparjadi and others, 1975).
BURMA

' \C A> M B o D I AJ". /~

INNER-ARC BASINS

MEDIAN BASINS

. Numbered dots denote location 

of significant fields. See explanation 

for all field names

0 100 200 300 400 500 600 700 BOO 900 1000 KILOMETERS 

0 100 200 300 400 500 STATUTE MILES

100 200 300 400 NAUTICAL MILES

The boundary linn on this chart »r« for purpose. 

of illustrslion only, end 

the position or view of t 

 pact to the boundaries

FIGURE 1 Map of sedimentary basins and major oil and gas fields of the Indonesian assessment region.
EXPLANATION

PACIFIC

0 C E A N

NORTH SUMATRA BASIN FIELDS

1 Arun

2 Djulu Rajeu

3 Perkal

4 Guedongdong

5 Alur Tjimon

6 Tualong

7 Rantau

8 Telaga Said

9 Darat

CENTRAL SUMATRA BASIN FIELDS

10 Bangko

11 Balam

12 Sintong

13 Menggala

14 Pentani

15 Duri

16 Pematang

17 Bekasap

18 Petapahan

19 Kotabatak

20 Minas

21 Pulai

22 Sago

SOUTH SUMATRA BASIN FIELDS

23 Tempino

24 Bedjubang

25 Djirakt

26 Benakat

27 Talang Akar Pendopo

28 Abab

29 Limau

30 Djimar

NORTHWEST JAVA BASIN FIELDS

31 Krisna

32 Cinta

33 Kitty

34 Selatan

35 Rama

36 Nora

37 MX

38 MX

39 Arjuna Fields

40 Arjuna Fields

41 Arjuna Fields

42 Arjuna Fields

43 Arjuna Fields

44 Jatibarang

EAST JAVA BASIN FIELDS

45 Semanggi

46 Nglobo

47 Ledok

48 Kawengan

49 Kruka

50 Poleng

51 JS Well

52 JSWell

BARITO BASIN FIELDS

53 Kambitin

54 Tandjung

55 Tanta

56 Warukin South

KUTEI BASIN FIELDS

57 Attaka

58 Badak

59 Sanga Sanga

60 Handil

61 Bekapi

TARAKAN BASIN FIELDS

62 Bunyu

63 Mengatal

64 Pamusian

SALAWATI BASIN FIELDS

65 Klamono

66 Salawati

67 Kasim

68 Jaya ;

69 Walio ..

NATUNA BASIN FIELDS

70 Terubuk

71 East Udang

72 Udang

BONE BASIN FIELDS

73 Kampung Baru

74 Bonge

75 Walanga

NORTH CERAM BASIN FIELDS

76 Bula
60° 120? 18Cf

FIGURE 2. Lithospheric plates of the world showing boundaries that are presently active. Double line: zone of spreading, from 

which plates are moving apart. Line with barbs: zone of underthrusting (subduction) at which one plate is sliding beneath 

another; barbs on overriding plate. Single Une: strike-slip fault, along which plates are sliding past one another. Stippled 

area: part of a continent, exclusive of that along a plate boundary, which is undergoing active extensional, compressional, 

or strike-slip faulting. Much simplified in complex areas.

Deltas are vertically and laterally complicated, 

prograding sand-shale sequences concentrated in 

depocenters which, in this region, developed in response to the tectonic uplift of a river sediment 

supply area. These sequences comprise multiplepay, medium- to thick-bedded quartz sandstones 

interbedded with shales that act as both cap rocks 

and source rocks. The petroleum occurs in both 

structural and stratigraphic traps; the rapid 

sedimentation, characteristic of a deltaic environment, attenuates the structural features and 

should enhance the potential for stratigraphic 

traps. Deltaic reservoirs often contain abundant 

methane gas reserves and high-gravity, low-sulfur 

crude oil. The gas may result from the large 

amounts of terrigenous organic matter in the 

source beds or it may result from increased temperatures due to deeper burial.

Carbonate platforms include a broad category of 

reefoid and bioclastic reservoirs that have developed upon a carbonate shelf. These reservoirs 

usually contain multiple-pay zones with vugular or

intergranular porosity. Reservoir distribution is 

controlled by facies development and often modified by postdepositional tectonics. Seals are provided by shales or micritic limestones, while petroleum sources occur either within, laterally adiacent to, or underlying the porosity zones. Although carbonate platform porosity has become a 

primary exploration target in several of Indonesia's basins, each reservoir (reef, bank, or 

bioclastic zone) tends to be restricted in size. The 

oil discovered in this type of geologic environment 

is usually of medium gravity and paraffin based 

and has a low sulfur content and widely variable 

pour points and gas to oil ratios. Methane-rich gas 

is commonly found in these reservoirs, both associated with oil and as dry gas. (Soeparjadi and 

others, 1975).

Pinnacle reefs occur seaward of the carbonate 

platforms as isolated features. Their development 

is in response to a relative rise in sea level, which 

commonly results from active subsidence. Pinnacle 

reefs may also occur within the carbonate plat-
CLASTIC PROVINCE CARBONATE PROVINCE

EXPLANATION

 Oil

O Oil and gas

O Gas

Sandstone 

and conglome

Shale

Carbonate (high energy)

Carbonate (low energy)

Coal

Volcanics

Pre-Tertiary basement

Water

~=- Fractures

 Normal fault

 Unconformity

	PLAY TYPES

1 Transgressive elastics

2 Regressive elastics

3 Deltaic series

4 Carbonate platform complex

5 Pinnacle reefs

6 Fractured volcanic basement

FIGURE 3. Diagrammatic cross section of producing Tertiary plays in Indonesia.

form area in areas of local subsidence. The source 

rock is mainly adjacent organic-rich marine shales. 

Pinnacle reefs have excellent reservoir characteristics, high production rates, and thick productive 

sections, but reservoir area is commonly limiting. 

Subsequent tectonic activity has caused many pinnacle reefs to become uplifted, faulted, and tilted. 

The oil in pinnacle reefs is commonly paraffin 

based, of moderate to high gravity, and has a low 

pour point, a moderately low sulfur content, and 

a very low gas to oil ratio. Occasionally, shallow 

oil accumulations will have an asphalt base, a low 

gravity, and a higher sulfur content, probably as 

a result of the biodegradation of the original 

paraffinic crude (Soeparjadi and others, 1975).

Fractured igneous and volcanic reservoirs are 

capped by overlying finer elastics that also act as 

source rocks. They have been discovered by deep 

drilling on structural closures. The contained oil is 

low sulfur, paraffin based, moderate to high in 

gravity, and has a high pour point (Soeparjadi and 

others, 1975).

SIGNIFICANT PETROLEUM BASINS

The following discussion highlights the petroleum characteristics and prospectivity of the more 

significant petroleum basins in Indonesia. Certain 

basic data relevant to these basins is summarized 

in table 1.

NORTH SUMATRA BASIN

The North Sumatra basin is a medium-sized 

back-arc basin that produces from Miocene and 

Pliocene regressive clastic and carbonate platform-type reservoirs. The onshore portion of the 

basin is geologically well known from surveys and 

drilling. The first oil was produced in 1885. The 

Rantau field, discovered in 1929, is the dominant 

oil field of the basin. Although well into decline, it 

still produces almost half of the basin's oil and contains over half of the basin's oil reserves. A 

number of other fields that were discovered before 

1940 are also in decline or have been abandoned. 

These fields were shallow structural features that
TABLE 1. Summary of petroleum information for Indonesia

[Data source, Riva (1982)]

Basin 

Date of first discovery 

Plays

North Sumatra

1885

Regressive clastic rocks

Carbonate platforms

Central Sumatra

1939

Transgressive clastic rocks

South Sumatra

1896

Transgressive clastic rocks

Regressive clastic rocks

Carbonate platforms

Northwest Java

1969

Transgressive clastic rocks

Regressive clastic rocks

Carbonate platforms

Pinnacle reefs

Fractured igneous rocks

East Java

1888

Transgressive clastic rocks

Regressive clastic rocks

Carbonate platforms

Kutei

1897

Regressive clastic rocks

Carbonate platforms

Barito

1937

Transgressive clastic rocks

Regressive clastic rocks

Carbonate platforms

Fractured igneous rocks

Tarakan

1900

Regressive clastic rocks

Deltas

Salawati

1936

Carbonate platforms

Pinnacle reefs

Annual 

production 

bbl oil/d 

(lOW gas/d)

19,400

(600)

779,840

32,000

225,506

(58.7)

561

359,653

(530)

5,121

14,000

73,765

Cumulative Estimated 

production reserves1 

10" bbl oil 10" bbl oil 

(lOW gas) (10iaft« gas)

381 134

(13.7)

4,567 4,437

1,494 190

498 1,432

(21.4)

165 4

920 1,100

(442) (7)

112 30

260 82

.,

 '-

&

187 497

Largest Field 

% Annual prod. 

% Cumul. prod. 

% Reserves

Rantau (1929)

48%

57%

51%

Minas (1944)

43%

53%

36%

Talang AkarPendopo (1922)

2%

24%

4%

Jatibarang

(1969)

8%

11%

14%

Kawengan

(1894)

51% of

cumulative

production

Handil (1974)

46%

22%

54%

Tandjung

(1937)

100%

94%

100%

Pamusian

(1905)

28%

72%

reserves, ?

Walio (1973)

60%

38%

67%

Prospects 

(short-term 

production 

projection)1

Oil production decline;

gas production increase;

small new fields expected

onshore and offshore; moderate prospects.

Oil production decline;

relatively small new fields

expected; moderate prospects.

Oil production decline;

small new fields expected;

moderate prospects.

Oil production increase;

good prospects, especially

offshore.

Oil production decline;

most discoveries expected

offshore; moderate prospects.

Oil production stable;

gas production increasing;

good prospects, especially

offshore.

Oil production decline;

poor prospects.

Oil production decline;

prospects moderate onshore

and offshore.

 - Oil production stable;

prospects moderate onshore

and offshore.
TABLE 1. Summary of petroleum information for Indonesia Continued

Basin 

Date of first discovery 

Plays

Annual 

production 

bbl oil/d 

(lOW gas/d)

Cumulative 

production 

106 bbl oil 

(lOW gas)

Estimated 

reserves1 

106 bbl oil 

(10lsft8 gas)

Largest Field 

% Annual prod. 

% Cumul. prod. 

% Reserves

Prospects 

(short-term 

production 

projection)1

Waropen

Little exploration thus far 

Transgressive clastic rocks 

Carbonate platforms

Arafura

Little exploration thus far

Carbonate platforms

North Ceram (Bula)

1897

Regressive clastic rocks

Carbonate platforms

Bone 

1975 

3 shut-in gas discoveries

Natuna 

1974

Deltas (?) 

Pinnacle reefs

Remaining basins

927 13

26,000

Bula (1897)

100%

99%

100%

200

Prospects moderate.

Prospects moderate.

Oil production decline; 

prospects poor.

Prospects poor to moderate.

Udang (1974) Oil production increase; 

100% oil and gas prospects good. 

100% 

100%

Oil prospects poor to 

moderate.

Estimates by J. P. Riva, Jr., this paper.

were discovered by surface geologic mapping. 

Their reservoirs are upper Miocene Keutapang 

and, less commonly, Pliocene Seurula Formations. 

A major gas field, Arun, was discovered in the 

basin in 1971. The gas reservoir, middle Miocene 

Arun reef limestone, is deeper than the previously 

discovered oil reservoirs. This is the largest natural gas field in Asia.

In the 1960's and 1970's, exploration moved 

offshore and to the deeper portions of the basin 

where several discoveries have been made on the 

basis of gravity and seismic information. With 

many of the oil fields in decline, a continued decline in oil production from the North Sumatra 

basin is expected. However, exploration continues, particularly offshore, with moderate prospects for discovery. Gas production is expected to 

increase with continued development of the Arun 

field. Prospects for gas discoveries appear slightly 

better than for oil discoveries.

The North Sumatra basin produces only about 2 

percent of Indonesia's oil and contains about 1 percent of the country's reserves. However, the basin 

contributes about half of Indonesia's marketed gas 

production and contains half of the nation's estimated gas reserves.

CENTRAL SUMATRA BASIN

The Central Sumatra basin is a small but very 

prolific back-arc basin that is well known geologically from outcrops and subsurface information. 

Its high density of wells and clustering of oil fields 

indicate an advanced stage of exploration maturity. The sedimentary area of the basin appears to 

be restricted to onshore. Relatively little geological work has been done offshore, which, apparently because of a rapidly thinning sedimentary 

section, offers poor petroleum prospects (Hamilton, 1979).

The oil fields are almost all anticlinal structures 

that were discovered by seismic surveys. Some of

9
the larger shallow structures, including the giant 

and dominant Minas field, were discovered early 

in the exploration cycle on the basis of surface 

geologic mapping and shallow-core drilling. Reservoirs are in transgressive elastics of the Sihapas 

Group and the Telisa Formation of early and middle Miocene age. The major producing geologic 

unit is the Sihapas Group, which contains fairly 

massive, fine- to coarse-grained sandstones interbedded with shales. The transgressive deposit 

contains reworked older sediments and elastics derived from emergent areas. The interbedded 

marine shales have acted as both source and cap 

rock for the oil accumulations. The oil maturation 

process was aided by the generally high heat flow 

in the basin, and thus, a considerable amount of 

oil was generated from deposits of relatively small 

volume and moderate age at generally shallow 

depths.

The first oil discovery in the Central Sumatra 

basin was made in 1939, but then exploration was 

interrupted by World War II. The Minas field was 

actually discovered during the war by Japanese 

occupational forces drilling a site that had been 

selected previously and prepared by an international oil company. The Minas field is the largest 

known field in Southeast Asia and is Indonesia's 

greatest subsurface asset. The name "Minas 

crude" has become the term in world oil markets 

for waxy, low-sulfur crude oil. Minas production 

began at an initial rate of 15,000 barrels per day 

and increased steadily until it reached a rate of 

400,000 barrels per day in late 1969. It has since 

declined to about 335,000 barrels per day. 

Peripheral water injection was initiated in early 

1970 to arrest excessive pressure declines. Injection averages about 300,000 barrels of water per 

day into some 28 wells on the southwestern and 

western flanks of the field.

Minas accounts for about 43 percent of Central 

Sumatra basin oil production and contains 36 percent of the basin's estimated oil reserves. The 

Central Sumatra basin provides half of Indonesia's 

oil production; thus, Minas accounts for over 20 

percent of the nation's oil production.

The basin may be dominated by Minas, but it 

also contains three other giant fields (Bangko, 

Bekasap, and Duri) and two possible giants 

(Pematang and Pentani). However, production 

from all six of these major fields is in decline. 

There are plans to steam flood Duri in an attempt 

to increase its production. About half the Indonesian oil reserves are in Central Sumatra basin 

fields.

With the major fields in decline, Central 

Sumatra basin oil production may continue to decline in spite of a number of new but smaller fields 

being put into production. The Beruk-Zamrud 

group of fields has substantial potential but will 

not rival the basin's six declining major fields in 

total ultimate production. The prospects of additional discoveries are moderate. Because exploration is in a mature stage, any new fields discovered should be expected to be smaller than the 

major fields found in the past.

SOUTH SUMATRA BASIN

The South Sumatra basin is a moderately sized 

back-arc basin that has a depositional history similar to that of the Central Sumatra basin. It is not, 

however, nearly as prolific in petroleum occurrence. Exploration in the basin began early with 

the discovery of at least two fields before 1900. 

The earliest discoveries were in shallow, regressive upper Miocene and Pliocene sandstones 

(lower and middle Palembang Formation). The 

larger fields, however, were found later in lower 

Miocene transgressive elastics (Talang Akar and 

Telisa Formations). There is also some production 

from carbonate platform rocks (Batu Radja Formation).

The Talang Akar Pendopo field is the dominant 

field in the basin, accounting for about one-quarter 

of the oil thus far discovered. However, this field 

was discovered in 1922 and is now well into decline, producing only about 2 percent of the basin's 

oil. Most of the fields in the South Sumatra basin 

produce oil and are in a state of advanced decline, 

with many already having been abandoned. The 

basin accounts for about 2 percent of Indonesian 

oil production and contains about 2 percent of the 

nation's estimated oil reserves. South Sumatra 

basin oil production is expected to continue to decline. Because of the maturity of exploration, the 

basin is considered to have only moderate prospects for additional discoveries of small fields.

NORTHWEST JAVA BASIN

The Northwest Java basin is a moderately sized 

back-arc basin that lies mostly offshore and includes the Sunda, Arjuna, and Jatibarang subbasins. A variety of petroleum plays occurs in the 

basin. These include Oligocene and Miocene trans10
gressive and regressive clastic rocks, carbonate 

platforms, and pinnacle reefs. Perhaps the most 

unusual reservoir rock, however, is the 

Jatibarang, a fractured, volcanic sandy tuff of 

Eocene and Oligocene age. Fractures control the 

porosity of these reservoirs.

Successful petroleum exploration in the Northwest Java basin dates from the late 1960's, so the 

fields are relatively few and relatively young. 

Since they are mostly offshore, they had to await 

the development of the proper technology and 

favorable economic conditions before they could be 

exploited. The exception is the Jatibarang field, 

the largest yet found in the basin (containing 14 

percent of the basin's reserves). There are a 

number of large offshore fields under production 

(Arjuna, Cinta, Rama, Selatan, and Kitty) and 

several new fields currently being developed. 

Thus, oil production from the Northwest Java 

basin will increase. At the present time, the basin 

produces about 14 percent of the nation's oil and 

contains about 15 percent of its total estimated oil 

reserves. A small amount of natural gas is also 

produced. The prospects of additional significant 

petroleum discoveries are good, especially 

offshore.

EAST JAVA BASIN

The East Java basin is of moderate size for an 

Indonesian back-arc basin, but it is not one of the 

region's better petroleum producers. The oil fields 

occur in two groups, one in the western portion of 

the basin and the other in the east, near Madura 

Island. Exploration in the basin began in the 

1880's, and over half of the oil produced has come 

from the Kawengan field. It was discovered in 

1894 and is now about depleted. Many of the older 

onshore fields have been abandoned, and a productive offshore field (Poleng) has been shut in to conserve associated gas. Current oil production (less 

than 1 percent of Indonesia's total) comes mainly 

from a few onshore fields, which are far past their 

prime. East Java basin oil reserves are also less 

than 1 percent of the nation's total.

The recent offshore exploration in the basin has 

taken place in the eastern portion near Madura Island. In this area, the carbonate platform complex 

is the preferred target, but the transgressive and 

regressive elastics may also yield discoveries. 

These three plays have proven productive in the 

older fields of the basin. Outside of any new discoveries, the East Java basin appears to be in the 

final stages of decline. The most prospective area 

is offshore from Madura Island, but even there 

prospects for commercial petroleum discovery are 

only moderate. Thus, the basin's current decline 

in oil production is expected to continue.

SALAWATI BASIN

The Salawati basin is geologically in a position 

similar to a back-arc basin, but, owing possibly to 

dislocations along the major Sarong fault zone to 

the north, no zone of active volcanism lies between the subduction zone and the basin. Conditions of high to normal heat flow characteristic of 

back-arc basins are, however, reported (Hayes, 

1978). The basin is located west of the Vogelkop 

portion of Irian Jaya. Tertiary deposition in this 

region was characterized by a Late CretaceousEocene transgression, an Oligocene regression, an 

early middle Miocene transgression, and a late 

Miocene regression. During the middle Miocene, 

the region was inundated and downwarped to 

form the Salawati basin (Pulunggono, 1976).

Beginning in the Miocene, basinal limestones interbedded with calcareous basinal shales were 

deposited. The shales are rich in organic material 

and may be the source rocks for much of the oil 

found in the basin. As the basin filled with sediments, shallower water depths allowed platform 

carbonates to form. The shallow-water environment provided favorable conditions for the growth 

of reef masses. When the region again subsided, 

some of the reefs were able to keep pace with the 

deepening waters and grew vertically upward, 

eventually reaching heights in excess of 500 m. 

These pinnacle reefs are middle and late Miocene 

in age. The off-reef areas were filled with a basinal shale, which provided excellent side and top 

seals to entrap the petroleum now found in some 

of the reefs (Vincelette and Soeparjadi, 1976).

The reef masses that contain the oil fields in the 

Salawati basin exhibit a wide variation in size and 

shape. The Walio reef, which contains a possible 

giant oil field, is about 6 by 20 km. The Walio field 

dominates Salawati basin oil production, some 60 

percent of oil production coming from this field. It 

also contains 67 percent of estimated Salawati 

basin oil reserves. The basin accounts for about 5 

percent of total Indonesian oil production and 

about 5 percent of estimated reserves.

11
With the exception of Klamono, which was 

discovered in 1936 and is now in prolonged decline, the Salawati fields were found in the 1970's. 

Many of the newer fields, however, have also recently declined. Regional tilting and local uplift of 

the eastern reef-belt platform area have exposed 

it at the surface and have thus provided a large 

area for surface water influx, which creates a 

strong water drive in most of the reefs. This 

drive, plus exceptional porosities, results in very 

high production rates for individual wells. The significant declines and, in some cases, the abandonments of some Salawati fields indicate that high 

production rates may have caused excessively 

rapid depletion of fields, which is a common occurrence in reef-field production.

There have been a number of recent petroleum 

discoveries in the basin, some of which are 

offshore. The accumulations were all in reef reservoirs and, in some instances, were of gas and gas 

condensate. These discoveries may stabilize 

Salawati basin production, at least for a time. At 

the current stage of exploration, the prospects for 

additional discoveries are judged to be moderate 

for both the offshore and onshore portions of the 

basin.

WAROPEN BASIN

The Waropen basin is a large basin located on 

the northern coast of Irian Jaya. It is tectonically 

positioned landward of the subduction zone in the 

New Guinea trench, but the intervening volcanic 

zone required for unequivocal characterization as 

a back-arc basin is absent. Otherwise the basin appears similar geologically to a back-arc basin but 

has undergone relatively little geological and petroleum exploration, which might confirm its classification of oil and gas potential (Fletcher and 

Soeparjadi, 1977). The basin has a thick sequence 

of Tertiary sediments composed of fine elastics interbedded with platform limestones that were deposited at the same time as the Miocene reefs of 

the Salawati basin. Any reefal buildups, therefore, would be age equivalents to those in the 

Salawati basin and could prove excellent exploration targets (Fletcher and Soeparjadi, 1977). In 

the onshore portion of the basin, a thick wedge of 

coarse elastics, which prograded northward during 

late Miocene to Pleistocene time, contains an assemblage of prospective reservoir rocks. Trap 

possibilities include anticlinal features and the 

onlap of the thick Miocene section onto large basement highs (Fletcher and Soeparjadi, 1977). The 

limited drilling that has been done, however, has 

encountered poor source rocks. Thus, in spite of 

the presence of oil and gas seeps, prospects for 

large accumulations of petroleum in the Waropen 

basin are only moderate.

KUTil BASIN

The Kutei basin in eastern Kalimantan is a relatively large median basin with a superimposed 

deltaic complex. The combination of basin types 

resulted in a tectonically structured delta, a complex in which structural development has concentrated the occurrence of petroleum, uncharacteristically, into a few large fields. The basin initially 

formed in early Tertiary time and contains mostly 

clastic sediments. The maximum thickness of late 

Miocene and younger sediments is associated with 

the Mahakam delta and is located mostly offshore; 

these strata include the extensive shallow marineshelf sediments and deeper outer shelf and 

bathyal deposits. A middle Miocene tectonic event 

that uplifted central Kalimantan initiated the deposition of the massive Mahakam delta, which 

prograded eastward and reached its greatest extent during late Miocene and early Pliocene time; 

deltaic deposition has, in general, continued to the 

present time (Beddoes, Jr., 1980).

In the Kutei basin, petroleum has been produced from lower Tertiary regressive clastic rocks 

and the later Tertiary deltaic complex. These depositional environments result in multiple-pay 

zones of medium- to thick-bedded, quartz-rich 

sandstones, which contain both oil and gas. The 

intercalated shale beds are both source and cap 

rocks.

The Kutei basin contains two giant fields (Attaka and Handil) and a possible giant (Sanga 

Sanga). Exploration began onshore along the 

coast almost 100 years ago. Sanga Sanga was discovered early and is now well into decline. 

Offshore seismic exploration began in the 1960's 

with a number of discoveries being made, among 

which were Attaka and Handil.

The Kutei basin provides about 23 percent of 

Indonesia's oil production and contains a similar 

proportion of the country's reserves. Handil produces about 46 percent of this total, and Attaka 

adds an additional 28 percent. Handil contains 

about 54 percent of the basin's estimated oil reserves. Associated gas is collected from some

12
Kutei basin fields. Delta basins do not show commonly a petroleum concentration in a few giant 

fields. However, when developed over a median 

basin, the underlying structure may affect the 

normal delta structuring and thereby influence the 

concentration of oil accumulation into a few large 

fields (Klemme, 1980).

A number of recent petroleum discoveries, 

which should help maintain current production 

levels, have been made in the Kutei basin (Petroconsultants). Commercial gas production should 

increase as gas reserves are further developed; 

the geology of a delta commonly is favorable for 

natural gas. The prospects for additional discoveries are good, especially offshore where exploration is relatively immature.

TARAKAN BASIN

The Tarakan basin is a median basin located to 

the north of the Kutei basin, which it resembles in 

sedimentary history. In the middle Miocene, the 

uplifting of Kalimantan initiated the deposition of 

thick, delta complexes in the Tarakan basin. One 

of these deltas is represented by the Meliat Formation, which was formed by the deltaic sedimentation of the ancestral Sesiap River. The progradation continued into Pliocene and Pleistocene 

time with the deposition of the deltaic deposits of 

the Tarakan Formation (Beddoes, Jr., 1980).

In the Tarakan basin, oil has been produced 

from regressive elastics and deltaic deposits. Exploration began early, with the discovery of some 

fields in 1900. The older fields are generally in decline and some have been abandoned. The Pamusian field, discovered in 1905, produces nearly onethird of Tarakan basin oil. The basin is, however, 

a very minor producer, accounting for about 1 percent of Indonesia's oil from about 1 percent of the 

country's oil reserves.

Recent exploration has included deeper drilling, 

and several discoveries have been made. The 

deeper finds have been mostly gas (Petroconsultants). Tarakan oil production is expected to decline. Overall, prospects for additional discoveries 

are moderate, and, in view of the relatively thick 

offshore sedimentary section, offshore prospects 

are somewhat more favorable than onshore prospects (Hamilton, 1979).

BARITO BASIN

The Barito basin, located to the south of the 

Kutei basin, is also a median basin but lacks the 

late Tertiary deltaic event described for the eastern Kalimantan basins previously discussed. In 

the Barito basin, oil has been produced from fractured pre-Tertiary volcanics and extrusive igneous 

rocks, transgressive Eocene sandstones, regressive Miocene sandstones, and from Miocene reef 

limestones. Exploratory drilling in the basin 

began in 1937. The Tandjung field, discovered 

during the first year of exploration, has completely dominated Barito basin production. This 

field has declined by 88 percent since 1964 and will 

continue to decline. The field currently produces 

all of Barito basin oil and contains all of the basin's 

estimated reserves; this amounts to less than 1 

percent of total Indonesian oil production and oil 

reserves. Past exploration results suggest that 

the prospects for additional discoveries are poor.

NATUNA BASIN

The offshore Natuna basin, consisting of two 

parts divided by the Natuna arch, is an open 

downwarp basin located on the Sunda shield 

northwest of Kalimantan. The sediments in the 

West Natuna basin consist mostly of elastics deposited in shallow marine or lacustrine environments. Organic debris is abundant due to the proximity of land areas, and potential source rocks 

are common. Geothermal gradients range from 

normal to high. Successful wells appear to be related to the higher geothermal gradients. The 

Gabus Formation, considered to be of Oligocene 

age, is the oldest generally recognized Tertiary 

sedimentary unit. Thought to be deltaic in origin, 

it is the primary exploration objective in the 

Natuna basin. The structure of the basin includes 

strike-slip faults, thrust faults, and uplifts, all of 

which are thought to have influenced oil accumulation (DuBois, 1980). The Udang field, discovered 

in 1974, dominates Natuna basin petroleum production and reserves. Commercial production 

began from this field, which is beneath about 100 

m of water, in April 1979. Although other discoveries of oil and gas have been made in the 

Natuna basin, Udang currently accounts for all of 

the basin's production and estimated reserves, 

each of which respectively composes about 2 percent of Indonesia's totals. Oil production is ex13
pected to increase with the further development 

of the Udang field and the probable 

development of some of the other newly discovered accumulations. Prospects for additional petroleum discoveries are good.

In the eastern part of the basin, a very large 

gas discovery recently has been reported (greater 

than 100 trillion cubic feet of gas) but with a very 

high proportion of carbon dioxide (possibly 70 to 

80 percent) in the gas, which would result in 

economic problems in recovery (Aalund, 1981). 

The play appears to be related to carbonate reef 

development on the eastern edge of the Natuna 

arch platform. Additional reef development surely 

is present, but the carbon dioxide problem likely 

will remain, owing to the conditions of high heat 

flow in the area.

ARAFURA BASIN

The Arafura basin, which extends into the 

offshore region, is a closed downwarp basin on 

southern Irian Jaya. The basin is thought to contain carbonate rocks interbedded with shales as 

potential source rocks. Requisite structure and 

maturation of organic source material may be 

lacking, but Hayes (1978) does report conditions of 

high heat flow, favorable for maturation, in the 

southwest corner of the basin, and structuring associated with the impinging Banda arc may occur 

in the same area. There has been little exploration 

thus far in the Arafura basin. Prospects for petroleum discoveries are considered moderate.

NORTH CERAM (BULA) BASIN

The North Ceram basin is a fore-arc basin that 

stretches along the northern coast of the island of 

Ceram. Sedimentation began in the basin in early 

Pliocene and continued until Pleistocene time. 

Mainly, deepwater muds and silts were deposited, 

but sand and carbonate fades also occur. Pleistocene tectonic movement resulted in emergence 

and the deposition of regressive elastics (Crostella, 1977).

The Pliocene and Pleistocene sequence unconformably overlies beds thought to be of Triassic 

age. The oil has accumulated in shallow upper 

Tertiary sediments but may have been derived 

from the underlying Triassic beds, which are locally shaly with a petroliferous character; the low 

geothermal gradients in the region also suggest

that the oil may not have been generated in the 

shallow, upper Tertiary sequence.

The North Ceram basin is very small and relatively shallow and contains three very shallow oil 

fields that were discovered by drilling-oil seeps. 

Two of the fields were extremely small and were 

abandoned by 1930. The third field, Bula, discovered in 1897, has accounted for almost all of 

North Ceram basin production. Currently Bula accounts for less than 1 percent of Indonesian oil 

production and reserves. In spite of a few recent 

exploration holes, North Ceram basin oil production is expected to continue its decline, and prospects for additional commercial petroleum discoveries are poor.

BONE BASIN

The Bone basin is an inner-arc basin that lies 

mostly offshore between the south and southeast 

arms of Sulawesi. The basin is fairly small and relatively young, with most of its sediments being of 

late Miocene age or younger. It is also a region of 

low geothermal gradients. Nonetheless, there 

have been three recent shallow gas discoveries onshore on the south arm of Sulawesi on the flank of 

the Bone basin. The discoveries are in anticlinal 

traps containing Miocene limestone reservoirs. 

The wells have been shut in for further development. The sediments in the central portion of the 

Bone basin reach 5 km in thickness. Thus, in spite 

of the low geothermal gradients and young sediments, it is possible that oil has matured in the 

basin. However, much of the basin lies beneath 

over 2,000 m of water, and in the near future, 

drilling can be attempted only around the basin 

margins. Current prospects for commercial petroleum discoveries in the basin are poor to moderate.

RESOURCE ASSESSMENT 

INTRODUCTION

The location of the Indonesian Tertiary basins 

assessment region is shown in figure 1. Estimates 

by the U.S. Geological Survey of oil and gas resources in this region are given in table 2 and 

figures 4 and 5. Supplementary data of interest in 

analyzing these estimates are presented in table 3.

ASSESSMENT OF COMMODITIES

Assuming a continuation of present economic 

and technologic conditions, Dolton and others

14
TABLE 2. Assessment of undiscovered conventionally recoverable petroleum resources in Indonesia

[Resource assessment by USGS as of June 25, 1981. Fn denotes the nth fractile; the probability that more than the amount Fn is present in n percent.

Data source, Masters and Riva, 1981]

Crude oil 

in billions of barrels

Natural gas 

in trillions of cubic feet

Low High 

F.

Mean Low High 

F,

Estimate 5 35 16 13 94 42

TABLE 3. Supplementary and comparative data relative to the petroleum resource assessment of Indonesia

[The term "identified reserves" follows usage of Dolton and others, 1981; a + denotes quantity positive but estimate not available; 

one billion barrels of oil equivalent (BBOE) = 6,000 ft* x 10* of natural gas. Data source, Masters and Riva, 1981]

Cumulative production to Jan. 1, 1980 

Identified reserves to Jan. 1, 1980

T^f*m r\n QT"i*fiTYvl

Total

Original recoverable resources (ultimate)

f^lTmill flT"Mffk .1. ....

Total

TVitnl nil ciT»H (TfiQ

Crude oil 

in billions of barrels

8.7

8.0

_ + 

8.0

8.7 

8.0 

16.0

32.7

43.3 BBOE

Natural gas 

in trillions of cubic feet

0.6

20.7

_ + 

20.7

0.6 

20.7 

42.0

63.3 

BBOE = 10.6

(1981) include in the assessment of undiscovered 

conventionally recoverable petroleum resources 

those resources that can be extracted by using 

conventional methods. The assessment does not 

include inferred resources that may yet be found 

in new pay zones or extensions of existing fields. 

Also excluded from the assessment, even if present, are unconventional resources such as heavyoil deposits, tar deposits, and oil shales, as well as 

gas in low permeability (tight) reservoirs, gas 

occluded in coal, gas in geopressured reservoirs 

and brines, and natural gas hydrates.

COMMENTS ON ASSESSMENT

The potential petroleum basins of Indonesia can 

be divided into five types: fore arc, inner arc, back 

arc (foreland), median, and downwarp. The backarc, median, and downwarp basins have significantly greater petroleum potential than do the 

fore-arc and inner-arc basins. The latter two basin 

types likely will yield only small discoveries, but 

isolated reefs might yield high flow rates; significant parts of these basins lie in water depths in 

excess of 1,000 m.

Although the back-arc basins are the most extensively explored, it is estimated that at least 60 

percent of the undiscovered potential for oil lies in 

downwarp and median basins; in the case of gas, 

as much as 80 percent of the undiscovered potential is assigned to such basins. Since the assessment was made (June 25, 1981), there has been a 

report of a giant gas discovery in the Eastern 

Natuna basin; if this field exists, the estimate of 

undiscovered gas may require adjustment. The reported extremely high carbon dioxide content of

15
ESTIMATES

MEAN 

MEDIAN 

95 PERCENT 

75 PERCENT 

50 PERCENT 

25 PERCENT 

5 PERCENT 

MODE 

S.D.

15.53

13.02

4.91

8.73

13.02

19.43

34.55

9.16

10.08

16 24 32 40 

BILLION BARRELS RECOVERABLE OIL

48 56

FIGURE 4. Indonesian undiscovered recoverable oil as assessed June 25,1981.

1.0

0.8

Z

I

tu 

§0.6

MEAN 

MEDIAN 

95 PERCENT 

75 PERCENT 

50 PERCENT 

25 PERCENT 

0.5 PERCENT 

MODE 

S.D.

0.4

m

2

O 

oc

a.

0.2-

ESTIMATES

42.23

35.49

13.45

23.84

35.49

52.83

93.64

25.06

27.24

50 75 100 125 150 

TRILLION CUBIC FEET RECOVERABLE GAS

FIGURE 5. Indonesian undiscovered recoverable total gas as assessed June 25,1981.

16

175 200
the gas, however, may result in economic problems in recovery.

Of the basins actively being explored, the 

Kutei, Northwest Java, and Natuna hold the 

greatest potential. Owing to their size and 

geologic position, the Arafura and Waropen must 

be considered attractive frontier basins.

REFERENCES CITED

Aalund, L. R., 1981, Soaring refining capacity to spur oil development in Indonesia: Oil and Gas Journal, v. 79, no. 50, 

p. 99-102.

Beddoes, L. R., Jr., 1980, Hydrocarbon plays in Tertiary basins of Southeast Asia: Offshore Southeast Asia Conference, SEAPEX Session, p. 3.

Bee, Ooi Jin, 1980, Offshore oil in Indonesia: Ocean Management, June, p. 51-73.

Cowan, D., and Parker, M. A., 1982, Exploration/development 

pace picking up speed in Indonesia: Oil and Gas Journal, 

v. 80, no. 31, p. 47-51.

Crostella, A., 1977, Geosynclines and plate tectonics in Banda 

Arcs, Eastern Indonesia: American Association of Petroleum Geologists Bulletin, v. 61, no. 12, p. 2063-2081.

Dolton, G. L., Carlson, K. H., Charpentier, R. R., Coury, A. 

B., Crovelli, R. A., Frezon, S. E., Khan, A. S., Lister, J. 

H., McMullin, R. H., Pike, R. S., Powers, R. B., Scott, 

E. W., and Varnes, K. L., 1981, Estimates of undiscovered recoverable conventional resources of oil and gas in 

the United States, U.S. Geological Survey Circular 860, 

87 p.

DuBois, E. P., Sr., 1980, Synoptic review of some hydrocarbon 

and potential hydrocarbon bearing basins of Southeast 

Asia: United National Development Programme (UNDP), 

Technical Support of Regional Offshore Prospecting in 

East Asia (RAS/80/003), ROPEA-R.093, p. 23-25.

Fletcher, G. L., and Soeparjadi, R. A., 1977, The land of 

plenty: Indonesia's 28 Tertiary basins hold 99 percent of 

production: Oil and Gas Journal, v. 75, no. 1, p. 150-156.

Hamilton, Warren, 1979, Tectonics of the Indonesian region: 

U.S. Geological Survey Professional Paper 1078, 345 p., 1 

plate.

Hayes, D. E., 1978, A geophysical atlas of the east and southeast Asian seas: Geological Society of America, Map and 

Chart Series MC-25.

Klemme, H. D., 1980, Petroleum basins classifications and 

characteristics: Journal of Petroleum Geology, v. 3, no. 2, 

p. 187-207.

Masters, C. D., and Riva, J. P., 1981, Assessment of conventionally recoverable petroleum resources of Indonesia: 

U.S. Geological Survey Open-File Report 81-1142. p. 3, 6.

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*U.S. GOVERNMENT PRINTING OFFICE: 1983-421-614/590

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