UNITED STATES DEPARTMENT OF THE INTERIOR

GEOLOGICAL SURVEY

Undiscovered Petroleum Resources of Indonesia

by
John Kingston

Open-File Report 88-379

This report is preliminary and has not been reviewed for conformity with
U.S. Geological Survey editorial standards and stratigraphic nomenclature
1988
 ASSESSMENT OF RECOVERABLE ENERGY RESOURCES
The World Energy Resources Program of the U.S. Geological Survey (USGS)
Intends to develop reliable and credible estimates of undiscovered recoverable
petroleum resources throughout the world. Initial program efforts have
focused on the major producing areas of the world to gain a broad geological
understanding of the characteristics of petroleum occurrence for purposes of
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, the studies of the main free
world exporting nations, 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 estimates represent the views of a U.S. Geological
Survey study team and should not be regarded as an official position of the
U.S. Government.
The program seeks to Investigate resource potential at the basin level,
primarily through analogy with other petroleum regions, and does not
necessarily require, therefore, current exploration Information that Is
commonly held proprietary. In conducting the geological Investigations, we
Intend to build a support base of publicly available data and regional
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; resource assessment, like
exploration, to be effective, must be an ongoing process taking advantage of
changing Ideas and data availability the results produced being progress
reports reflecting on a state of knowledge at a point In time. Because this
program Is coordinated with the USGS domestic assessment program and both
utilize similar techniques for assessment, the user can be assured of a thread
of consistency permitting comparisons between the various petroleum basins of
the world, Including the United States, that have been assessed In the overall
USGS 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.
Other U.S. Geological Survey publications relating to the assessment of
undiscovered conventionally recoverable petroleum resources are available from
the Open File Services Section, Branch of Distribution, USGS, Box 25425,
Federal Center, Denver, CO 80225.
 CONTENTS
Page
Ab stract 1
Introd uctIon 2
Regional geology 5
Role of tectonics 5
Tectonic basin classification 5
Effects of underlying crust 6
Structural trap types 8
Strat Jgraphy 8
Summary 12
Individual basin assessments 13
North Sumatra 13
Centra I Sumatra 25
South Sumatra 32
Northwest Java 42
East Java Sea 55
Bar I to 65
Kute I 72
Tarakan 89
West Natuna 99
East Natuna 113
SaIawatI-BIntu nI 120
Araf ura 138
Waropen 147
Play analysis summaries 153
Deep Basin Reef, North Sumatra Basin 155
Neogene Sandstones, North Sumatra Basin 156
Shallow Shelf Reefs, North Sumatra Basin 157
Lower Miocene Shelf Sandstones, North Sumatra Basin 158
Paleogene Basal Drapes, North Sumatra Basin 159
Offshore Slope, North Sumatra Basin 160
Lower Miocene Sandstones, Central Sumatra Basin 161
Lower Miocene Sandstones, South Sumatra Basin 162
Miocene Carbonates, South Sumatra Basin 163
Miocene-Pliocene Sandstones, South Sumatra Basin 164
Paleogene Volcanlcs, Northwest Java Basin 165
Paleogene (Talang Akar) Sandstones, Northwest Java Basin 166
Lower Miocene Carbonates, Northwest Java Basin 167
Miocene Draped Sandstones, Northwest Java Basin 168
Mid-Miocene Carbonates, Northwest Java Basin 169
Shelf Reef, East Java Sea Basin 170
Shelf Drapes, East Java Sea Basin 171
Baslnal Folds, East Java Sea Basin 172
Folded Sandstones, Bar I to Basin 173
01Igocene-Mlocene Reefs, Barlto Basin 174
Drape Sandstones, Barlto Basin 175
 Neogene Delta Sandstones, Kute! Basin 176
Paleogene Drapes, Kute! Basin 177
01Igocene-Mlocene Reefs, Kute! Basin 178
MIo-PIfocene Reefs, Kutel Basin 179
Deep Water Sandstones, Kutel Basin 180
Carbonate Reefs and Banks, Tarakan Basin 181
Late Miocene Folds, Tarakan Basin 182
PIlo-Plelstocene Folds, Tarakan Basin 183
01Igocene Drapes, West Natuna Basin 184
Miocene Drag Folds, West Natuna Basin 185
Miocene Reefs, East Natuna Basin 186
Drapes, East Natuna Basin 187
SalawatI Miocene Reefs, Salawatl-BIntunI Basin 188
BIntunI Miocene Reefs, Salawatl-BIntun! Basin 189
Miocene Drapes, SalawatI-BIntunI Basin 190
Cretaceous Drapes, Salawatl-BIntunI Basin 191
Neogene Folded Sandstones Salwatl-BIntunI Basin 192
Salawatl-PIlocene DIapIrs, SalawatI BIntunI Basin 193
Anticlines, Arafura Basin 194
Miocene Reefs, Arafura Basin 195
Aru Hinge Area, Arafura Basin 196
Drag Folds, Waropen Basin 197
Drapes and Reefs, Waropen Basin 198
Miocene Drapes, South Makassar Basin 199
Miocene Reefs, Sumatra Outer Arc Basin 201
Miocene Reefs, Java Outer Arc Basin 204
Carbonate Buildups, Bone-Senkang Basin 206

Conclusion: assessment of undiscovered recoverable petroleum 207

References 214
 ILLUSTRATIONS
Page
Figure 1. Map showing significant Tertiary basins of Indonesia 3
2. Map showing petroleum occurrences In Indonesia 4
3. Map showing tectonic basin classification of Indonesia 7
4. Map showing distribution of thermally mature sediments
of Indonesia 10
5. Structure contour map of North Sumatra basin showing
depth to basement 14
6. Map of North Sumatra basin showing distribution of plays 15
7. Diagrammatic cross section of North Sumatra showing play
dIstrI but Ion 16
8. Structure contour map of part of North Sumatra basin
showing depth to a Miocene seismic horizon 19
9. Structure contour map of Arun gas field, contours on top
of Peutu carbonate 21
10. Map of shelfal area of offshore North Sumatra basin
showing reefs and reefal oil and gas fields 23
11. Sketch map of principal oil fields of Central Sumatra 26
12. Structure contour map of Central Sumatra showing depth
to basement , 27
13. NNW-SSE stratigraphic cross section, A-A , Central
Sumatra basin 29
14. Stratigraphlc chart of Central Sumatra basin 30
15. Structure contour map of South Sumatra basin showing
depth to basement 33
16. Sketch map of principal oil fields of South Sumatra 34
17. Stratigraphlc chart, South Sumatra basin 36
18. Stratigraphlc SW-NE cross section transverse South
Sumatra basin 37
19. Map showing distribution of calcareous buildups of the
Baturaja Formation, South Sumatra 39
20. Index map of Northwest Java basin showing distribution of
subbaslns, principal oil and gas fields, and location
of geologic cross sections 43
21. Stratlgraphic chart, Northwest Java basin 44
22. NW-SE geologic cross section, A-A , Northwest Java basin 46
23. South-north geologic cross-section, B-B Sunda-subbasln
Northwest Java basin : 47
24. South-north geologic cross-section, C-C , Arjuna subbasln,
Northwest Java basin ; 48
25. West-east geologic cross-section, D-D , onshore Northwest
Java basin 49
26. Map showing details of lower Baturaju paleogeography,
Sunda subbasln, Northwest Java basin 52
27. Isopach map of Baturaju Formation eastern Northwest Java
basin 53
28. Sketch map of East Java basin showing depth to basement - 56
29. Stratigraphlc chart, East Java basin 58

iv
 ILLUSTRATIONS (continued)
Page
30. South-north geologic cross-section, A-A , East Java
basin 59
31. Histograms of organic carbon values for the formations
from selected various east Java sea wells 63
32. Chart showing relationship of TAI values, formation, and
depth 63
33. Structure contour map of Bar I to basin showing depth to
basement : 66
34. West-east restored stratlgraphlc cross-section, A-A ,
Bar I to basin 67
35. Stratlgraphlc chart, Bar I to basin 69
36. Structure contour map, Kutel basin, showing depth to
basement 73
37. Index map Kutel basin showing field locations and
significant wf Idcats i 74
38. South-north restored stratfgraphlc section, D-D , Kutel
I n m,mmm,mmmmmmmmm,m,m,mmm,m,m,m,mm^,mmm,m,^m,m,mmm,mm^mmm,m,m,mm,mm,mm,mmfm,tmm,mmmmm,m,imm,m,m,mmm,im [^

39. West-east composite geologic cross section, A-A , Kutef

basin 77
40. Diagrammatic stratlgraphlc chart, southeast Kutel basin - 78
41. Map showing distribution of plays, Kutef basin 79
42. Section showing organic matter In a sedimentary cyclothem,
Kutel basin 82
43. South-north section showing spatial relations of thermal
maturity to overpressured shale, Kutel basin 85
44. Structural contour map showing deltaic sandstone play
structure based on regional seismic mapping, Kutel
bas I n 87
45. South-north stratfgraphlc section along Bekapal-Attaka
trend showing delta fades, Kutel basin 88
46. East-west geologic sections transverse to the western
margin of the Makassar Strait, Kutel basin 90
47. Structure contour map of Tarakan basin showing depth to
basement 91
48. Index map of Tarakan basin showing fades outlines and
significant fields and wildcats 93
49. Geololgc map of the Tarakan basin showing In particular
the trace of the PI locene unconformity In map and section
view 94
50. Generalized Neogene stratfgraphlc chart, Tarakan basin 96
51. Isopach map of West and East Natuna basins, southeast
Asia -100
52. Well location map, West Natuna basin 102
53. Map showing early tectonic elements, West and East Natuna
basins 103
54. Map showing early-middle Miocene tectonic elements, West
and East Natuna basins 104
55. Seismic sections (A, B, and C) showing structural styles
In West Natuna basin (A) and East Natuna basin (B and C) 105
56. Seismic structure map showing depth to top 01 Igocene
strata on a typical drag fold, West Natuna 106
 ILLUSTRATIONS (continued)
Page
57. NW-SE geolofgc cross-sections, West Natuna basin 107
58. Structure map showing depth to top of OlIgocene strata
Udang Field, West Natuna basin 109
59. Stratfgraphfc chart, West Natuna basin 110
60. Index map of East Natuna basin showing fades, and
wildcats 114
61. West-east geololgc section across east edge of
carbonate platform, East Natuna basin 116
62. Well summary, AL-1X wildcat, East Natuna basin 117
63. Map showing tectonic elements of Irlan Jaya
(Indonesian New Guinea) 121
64. Structure contour map of the Salawatl-BIntunI basins
showing the depth to basement and principal tectonic
e I ements 122
65. Index map showing location of fields and significant
wildcats, SalawatI subbaslns 124
66. Map of SalawatI Blntunl basin showing areas of plays,
trends, and significant tests 126
67. West-east outcrop sections, Arafura basin, Irlan Jaya 128
68. West-east geololgc cross-section A-A, SalawatI
subbasln 129
69. NW-SE Stratfgraphfc sections, A-B, Blntunl subbasln 132
70. Kals fades map, SalawatI subbasln 133
71. Map showing tectonic elements and basement depth,
Arafura basin 139
72. Geologic sketch map of part of the Tarera fault zone and
other features, southwest New Guinea 141
73. Aru trough cross section, Arafura Basin 142
74. Map showing tectonic elements, Isopach of Neogene
sediments, wildcats and outcrop stratlgraphlc column
locations (fig. 75) Waropen basin, Irlan Jaya 148
75. Stratlgraphlc columns along north flank of Waropen
basin; location of columns (fig. 74), columns from
Vlsser and Hermes (1962) 149
76. Isopach of south Makassar basin 200
77. West-east geologic section across west flank of south
Makassar basin 200
78. Map showing tectonic elements and Isopach of Neogene
sediments, Sumatra Outer Arc.basin 202
79. Geologic cross-sections, A-A , across the Sumatra Outer
Arc basin 203
80. Map showing tectonic elements and Isopach of Neogene
sediments, Java outer arc basin, contour Interval
1 kilometer, after Hamilton (1979) 205
81. Cumulative probability curve Sumatra/Java, recoverable
Of | 209
82. Cumulative probability curve Kalimantan, recoverable
Of | 209
83. Cumulative probability curve, Natuna, recoverable oil 210
84. Cumulative probability curve, Irlan Jaya, recoverable
0 11 210
 ILLUSTRATIONS (continued)
Page
85. Cumulative probability curve, Sumatra/Java, recoverable
gas 211
86. Cumulative probability curve, Kalimantan, recoverable
gas 211
87. Cumulative probability curve, Natuna, recoverable gas 212
88. Cumulative probability curve, Irlan Jaya, recoverable
gas 212
89. Cumulative probability curve, recoverable oil 213
90. Cumulative probability curve, recoverable gas 213

vn
 Undiscovered Petroleum Resources of Indonesia
By
John Kingston
ABSTRACT
Thirteen of the 44 sedimentary basins along the 2,900-mile east-west
extent of Indonesia are believed to contain nearly all of Indonesia's petro-
leum resources. Western Indonesia, underlain by the Asian (Sunda) continental
block, comprises the Sumatra-Java archipelago, the Island of Kalimantan, and
the Intervening Sunda Shelf. This area contains more than 95 percent of
present Indonesian petroleum reserves, and exploration has reached the stage
of early to middle maturity. Reserves are concentrated In the five larger
back-arc basins of the archipelago and In three rifted basins of the
KalImantan-Sunda Shelf area.
Eastern Indonesia, essentially Irlan Jaya (western New Guinea) and the
adjoining shelf, was formed by tectonic activity along the north edge of the
Australian-New Guinea continental block, whwere locally derived coarsely
clastic, non-marine In nature (fig. 7), followed by dark, carbonaceous,
brackish water shales. By early Miocene time, continued subsidence west of an
early Miocene hinge line resulted In coalescing of the subbasins In a quiet,
marine environment. West of the hinge line, deposition was largely shale with
carbonate fades over horst-block highs, while calcarenfte and sandstones or
reefa I carbonates were deposited on the platform east of the hinge line.
Continued slower subsldey eight USGS geologists with 48 play analyses In 17
basins as a guide, and the results are shown as probability curves.
Aggregation of the mean estimates for the four main groups of basins:
Sumatra-Java, Kalimantan, Natuna, and Irlan Jaya, Indicates that undiscovered
recoverable petroleum resources of Indonesia are 10 billion barrels of oil
(BBO) and condensate, and 95 trillion cubic feet (Tcf) of gas (not Including
60 Tcf of discovered, but undeveloped gas).
 INTRODUCTION
Indonesia Is a country of great lateral extent, measuring about 2,900
miles from east to west with 44 onshore and offshore sedimentary basins
covering an area of approximately 550,000 ml (fig. 1). The resource
assessment study concentrates on 13 of these basins which have an overall area
of about 420,000 ml , and for reasons discussed below are estimated to have at
least 90 percent of the Nation's discovered and undiscovered petroleum.
Discovered or producing fields of Indonesia have original reserves of
some 20 billion barrels of oil (BBO) (and condensate) and over 100 trillion
cubic feet (Tcf) of gas (Including about 60 Tcf of gas which are believed to
be discovered but not on production). Petroleum production Is confined to 10
basins, plus significant discoveries or shows Indicating potential production
In two additional basins (fig. 2).
Proved reserve estimates are beyond the scope of this study but are
presented as a scaling tool for the resource estimate of each basin. Various
published estimates or Indications of reserves differ considerably, but not so
much as to affect such an application. Used In this study were the latest
available oil and condensate estimates, as of 1983, published by the Energy
Information Administration (ElA) (DIetzman, 1984). The only available gas
reserve numbers (1979) are those derived from the combined data of HarladI
(1980) and Patmosuklsmo (1980) of Pertamlna.
The level of petroleum exploration In Indonesian basins varies. Some
basins, such as South Sumatra, are explored rather thoroughly and have been
declining In production for years; others, such as those of Irlan Jaya (Indo-
nesian New Guinea) and eastern Indonesia, are very sparsely explored. Details
of exploration and production history are discussed under the Individual
basins.
The purpose of this study Is to provide a basis for a quantitative
assessment of undiscovered petroleum resources of Indonesia. To this end,
every appropriate estimate of a geological or historical factor Is quantified,
even though It may be only a guess, and the derivation of, or rationale
behind, each estimate Is given. New Information may cause a revision of a
particular number; the revision can then be plugged back Individually Into the
system effecting a corresponding change In the overall resource estimate.
Data sources of the study are essentially limited to available published
Information, though some unpublished maps and other data have been referred
to.
Although background geology Is covered briefly, the focus of this study
Is on the significant geologic factors bearing directly upon petroleum
occurrence. The study Is structured to support a play analysis approach.
Estimates of the significant geologic factors for 48 plays In 17 basins are
summarized In play analysis form.
The play analysis method used here Is a modified volumetric yield method
with each of the appropriate geologic factors considered separately (Roadlfer,
1979). In this play analysis, estimates are made of seven principal factors;
1) acres of untested trap, 2) percent of untested trap area which Is
productive, 3) percent of oil versus gas, 4) feet of average effective pay, 5)
oil recovery In barrels per acre-foot (a function of reservoir quality), 6)
gas recovery In thousands of cubic feet per acre-foot, and 7) natural gas
liquids (NGL) In barrels per million cubic feet of gas. The estimates are
given as ranges to Indicate varying degrees of certainty. For brevity, only
the most likely value (or mode) Is used In the text discussion of the
 106* 110* 114* 118* 122' 128* 130* 134' 138* 142'

Numbered basins: sediments thicker than

II I I. I P.-'fOf N ti S 6000 feet 8*
CHINA SKA Unnumbered basins: sediments thicker
than 3000 feet
~~l Structural basin: sediments less than
' 3000 feet
Regional thickness: greater than 3000
feet, but no depocenter 4*
/>

0'

?L

SIGNIFICANT BASINS
1. North Sumatra 9. Sumatra Outer Arc 17. Waropen
2. Central Sumatra 10. Java Outer Arc 18. Malawi 26. Bone
3. South Sumatra 11. Lombok 19. W. Natuna 27. Gorontalo
4. N.W.Java 12. Savu 20. E. Natuna 28. Banggai
5. East Java 13. Timur Trench 21. Barito 29. Salabangka
6. Bali 14. N.Ceram Trench 22. Spemonde 30. Celebes
7. Flores 15. Arafura 23. S. Makassar 31. Halmahera
8 V South Banda 16. Salawati-Bintuni 24. Kutei +13 smaller basins
Ti

Figure l.--Map showing significant Tertiary basins of Indonesia.

 -h

142"

MELAWI
BASIN

MAKASSARBONEE ,^
I BASIN-;.-.

ULTIMATE RESERVES

OIL RESERVES IN BILLIONS OF BARRELS

Figure 2.--Map showing petroleum occurrences in Indonesia.

rationale behind each estimate. As an additional assessment guide, the
limiting factor or factors affecting the play are emphasized.
The petroleum geology outlined In this report, along with the play
analyses, was presented to a board of eight U.S. Geological Survey (USGS)
geologists who, after discussion and deliberation from the perspective of
their Individual experiences, arrived at a subjective consensus as to the
amount of undiscovered recoverable petroleum resources In each basin or group
of basins (a modified Delphi method described by Do I ton and others In USGS
Circular 860). Because the unknown cannot be predicted with precision,
probability curves better convey the true nature of the estimate rather than a
single, or point value. On the condition that recoverable resources are
Indeed present, Initial assessments were made for each of the provinces as
follows:
1) A low resource estimate corresponding to a 95-percent probability that the
resource quantity exceeds that amount,
2) A high resource estimate corresponding to a 5-percent probability that the
resource quantity exceeds that amount,
3) A modal (most likely) estimate of the quantity of resource.
Final estimates of the group are averaged, and those numbers are computer
processed by using probabilistic methodology (Grove I I I, 1981). The resulting
curves show graphically the resource values associated with a full range of
probabilities and determine the mean, as well as other statistical parameters.
The resultant curves for each province are shown. Estimates drawn from these
curves form the conclusion of this report.
REGIONAL GEOLOGY
Role of Tectonics
Tectonics assume a special Importance In Indonesia In regard to petroleum
accumulation. Maturation of source rock, preservation of source material,
development of reservoirs, and the formation of traps are all directly
affected by the movements and Interaction of llthospherlc plates. The
principal plates Involved are the Asian Plate (Including the accreted Sunda
continental fragment), the Pacific Plate, and the once separate Indian and
Austral I an Plates.
There are five principal Tertiary tectonic events or Interactions, In
order of Importance affecting basin formation and the accumulation of
petroleum:
1. Subduct Ion of the Indian Plate beneath the Asian Plate
2. Rifting of eastern Sulawesi (the Celebes) from Kalimantan (Borneo)
3. Relative westward and southward thrust of the Pacific Plate Into the
region, causing disruption of previous terrains, slnlstral wrenching, and
oblique collision and subductfon under the Australian continental block,
which Includes southern New Guinea
4. Rifting and opening of the South China Sea
5. Opening of the Thai-Ma I ay Graben
Plate Interactions are considered In more detail In the discussions of the
Individual basins.
Tectonic Basin Classification
It Is difficult to define sedimentary areas as to what should be basins
or subbaslns In this complex region. For the sake of conformity, the
definitions of previous authors, I.e., Hamilton, 1974, 1978; Fletcher and
Soeparjadl, 1975, 1977; KartaadJputra and others, 1982, were used. A
significant basin Is defined as one containing sediments with thicknesses
greater than about 3,000 ft (about I km, or I second of seismic reflection
time). On that basis, I have shown 44 basins comprising an area of 550,000
ml (fig. 1). In the exceptional case of the eastern Java Sea, where the
whole shelfal region has a sedimentary thickness of over 3,000 ft, Individual
depocenters of somewhat thicker sedimentary fill (I.e. approximately 5*000 ft)
are designated as basins. More than half of the basin area (300,000 m ) Is
over oceanic or attenuated continental crust regions In deep water; this
baslnal area would be much larger If It were not limited, by my definition, to
basins having over 3,000 ft of sediment. In fact, some of the structural
basins of the oceanic crust areas Indicated as major basins (e.g. Weber, North
Banda) by some authors, have been shown by Kartaadlputra and others, 1982, to
have minimal sediment thicknesses.
Basins may be categorized tectonlcally by their positions on the Inter-
acting plates or continents of the region. Figure 3 shows the predominant
tectonic characteristic of each of the principal basins; not Indicated Is that
wrenching Is a dominant trait of many of the basins, particularly those of
Sumatra, West Naluna, and Irfao Jaya. The area I extent of these basins varies
from 1,000 sq ml to 75,000 ml (Sumatra Outer Arc), and sedimentary
thicknesses range up to over 30,000 ft (Kutel basin).
The effect of the position of the basin, In relation to the Interacting
plates, on the thermal gradients Is of paramount significance for petroleum
generation. In general, the Inner- or back-arc basins are the warmest, the
rifted continental margin basins are next warmest, and the outer arc basins
are the coolest.
Effects of Underlying Crust
Indonesia Is divided, geologically, Into three regions on the basis of
the underlying crust, 1) Asian continental crust, 2) Australian continental
crust, and 3) oceanic and Island-arc crust (fig. 3). Continental crust
regions, being more buoyant, approximate topographically higher areas where
water depth Is less than 600 ft. The continental crust Is made up mostly of
old, granite-Intruded terrain (craton). Fourteen of the 44 basins are
underlain by continental crust (fig. 3). The other less buoyant crustal
areas, those underlain by oceanic crust or attenuated continental crust, are
generally covered by more than 600 ft of water.
The distribution of continental versus oceanic crust also affects the
thermal gradient of the basins; gradients over continental crust areas are
significantly higher. For example, the foreland basins of Sumatra, underlain
by craton, have a high gradient but gradually become cooler In the East Java
basin, underlain by accreted continental crust, and even cooler In the Ball
and Flores basins, which are underlain by oceanic crust.
Basins off the continental crust area are generally of poorer source,
being of low thermal gradient and further from the source of terrestrial
organic matter, the prime source material of the generally high parafflnlc
petroleum of Indonesia. These basins also generally lack adequate reservoir
rocks because they are further from quartz-rich provenances and lack a high-
energy nerltlc deposltlonal environment. Basins underlain by oceanic or
attenuated continental crust are, therefore, less prospective and contain a
negligible amount of undiscovered petroleum. They, therefore, are not discus-
sed further. However, because three of these deep-water basins, the Sumatra
 110* 130* 134* 138* ur

r3 Wtf 9 200400 600km

/' <P" 0 30O ml
PHILIP.
EDGE OF CRATONIC CONTINENTAL CRUST

_t I m / v_f .
~\ 5' KUUAtfSiJi /
L V ' . -' . /

S f*js\ BASIN
- JSb 2

>VN ARAFOrmjJASIN «
^ --Xs

1 RIFT. PULL-APART
2 BACK- OR INNER ARC
3 FORE- OR OUTER ARC
4 TRENCH '
5 FORELAND (including collision zone)
i

Figure 3.--Map showing tectonic basin classification of Indonesia.

Outer Arc, the Java Outer Arc, and the South Makassar basins, have such a
great volume of sediment a play analysis of each Is Included In this report.
Structural Trap Types
Individual trap-forming structures are discussed under each basin, but In
general, there are four major types of relevant structures:
1. Early horst and graben block-faulting, usually lower Miocene or older,
forms fault traps In older (Cretaceous to lower Miocene) sediments, drape
closures In younger (Neogene) sediments, and growth sites for Miocene reefs.
2. Drag-fold structures are prevalent In Sumatra, West Natuna, and In
Irlan Jaya where wrench faulting Is dominant.
3. Anticlinal folds of probable compresslonal origin are extensive along
the east coast of Kalimantan (Borneo) and In central Irlan Jaya.
4. Dlaplrlc folds or folds with considerable shale flowage are common In
the North Sumatra, East Java, eastern Kalimantan, and Waropen basins.
Regional Stratigraphy
Because the stratigraphy of Indonesia Is highly variable, It Is best
described If the rocks of the Asian continental block are considered
separately from those In the Australian continental block.
Asian Continental Block
The Asian block (Sundaland) Is ringed by a line of Tertiary basins (fig.
3). Although these basins vary In detail, their sedimentary record has a
parallel, one-cycle history, broken down Into three phases, 1) transgression,
2) still stand, and, 3) a regression:
1. Eocene to early Miocene - Initial filling of Isolated terrestrial
basins, largely grabens, followed by marine transgression and delta develop-
ment at the end of the period
2. Early to middle Miocene - regional quiescence characterized by shale
and carbonate deposition
3. Middle Miocene to Pliocene - regression with coarser elastics and
deltaic deposition.
Australian Continental Block
The southern half of the Island of New Guinea had been a north-facing
continental shelf from Middle Jurassic to mid-Tertiary. Shelf sedimentation
of mainly Australia-derived sandstones and shales (Kembelangan Group)
persisted through the Jurassic, Cretaceous, and early Tertiary. During early
Tertiary through late Miocene, clastic Inflow diminished, and sedimentation
was mainly carbonate and shale (New Guinea Limestone Group). Near the end of
the Miocene, more coarse clastic sediments (Klasaman, Steenkool, and Buru
Formations) filled the shelf area basins of southern and western Irlan Jaya.
These sandstones and shales, In contrast to the older, Australia-derived
sediments from the south, were derived from the medial, east-west trending
mountains of Irlan Jaya to the north, which were formed by the Miocene
collision of the Australian continent with an Island arc of the Pacific Plate.
At about the same time, Miocene and Pliocene sediments, which were derived
from the collision zone and from the higher parts of the finally accreted
Island arc forming the north coast of Irlan Jaya, filled the Waropen Basin of
north Irlan Jaya.
Probable Source Rocks
Figure 2 shows petroleum production and reserves, and substantial
occurrences (I.e. Indications of potential production), or discoveries. It
also shows that production Is limited to ten basins, and production plus
significant occurrence to 12 basins.
Figure 4 shows the thermally mature rock distribution of Indonesia. This
map was constructed by projecting the approximate top of thermally mature
sediments In each basin laterally to the Intersection with the basin flank.
Determinations of the top of thermally mature sediments were derived from
published maturity Indices, or by estimation (method of Hood, 1975) from
published thermal gradients and age-depth data. In analogous areas, estimates
of thermal maturity were made by comparison of thermal gradients.
Figure 4 shows that only 18 of the 44 basins analyzed are underlain by
significant amounts of thermally mature source sediments. In 14 of these 18
basins, thermally mature sediments appear to be of appreciable organic
richness. Thermally mature sediments of 4 (the Sumatra and Java outer-arc
basins and the Timor and N. Ceram Trenches) of the 18 basins, however, appear
to be In a melange open-sea fades so that any organic richness might have
been diluted or destroyed, and therefore have a much lower generating
potential.
However, melange-type sediments do have some limited petroleum generating
capacity, as Indicated by oil and gas seeps along the edges of the Sumatra and
Java outer arc basins, In addition to seeps on the Island of Timor, and a
small oil field (Bula) on the Island of Ceram. An oil seep on the north side
of the Waropen basin may emanate from melange or Island-arc material.
A comparison of petroleum production and discoveries (fig. 2) with
thermally mature source rock occurrence (fig. 4) shows that only three basins
have an appreciable volume of thermally mature rock (non-melange), but no oil
or gas discoveries (Waropen, Arafura, and South Makassar). Perhaps lack of
discoveries may be related to the relatively minor exploration effort In these
basins.
A comparison of the overall basin distribution (figs. 1 and 3) and mature
source rock occurrences (fig. 4) Indicates that the source rocks are confined
to the continental crusted areas, but more Importantly, only 14 of 44
Indonesian basins have an appreciable potential for generating petroleum.
Reservoirs
There are six groups of reservoirs, three associated with the Asian
Continental Block and three with the Australian Continental Block.
Asian Continental Block Reservoirs
Reservoirs of western Indonesia are related to the previously described
three phases of sedimentation of the Asian Continental Block.
a. Paleogene and lower Miocene TransgressIve and Deltaic Sandstones
During early Tertiary, the western part of the Asian Continental Block
was emergent and terrestrial sediments filled In and levelled Intermontane
94' 98* 106* tt<r 114' 12T 134* 138*
10T itr tar 13<r

I GCAMHOnlA

0 \ /§! MALAV

f^jRj \__

ORONTALO*SAslr3

WAROPEN \
BASIN

*
ARAFURAl BASIN 5^1 NEVV
x- \ wl^UINE
"*- ^~ *C s > >15^

THERMALLY MATURE SEDIMENTS

MATURE. BUT ORGANICALLY POOR, E. G. MELANGE, TECTONIZED ETC.

A U VS T R A L

Figure 4.--Map showing distribution of thermally mature sediments of Indonesia.

lows. In the east, Eocene to 01Igocene seas transgressed westward over the
continent and carbonate rocks are abundant In the East Java Sea area. The
terrestrial rocks contain only poor to fair reservoirs, although reserves of
217 MMBO have been found In fractured Eocene volcanlcs/tuffs In west Java,
near Jatlbarang. The marine transgress Ive Eocene sandstones of east
Kalimantan (Borneo) have better reservoir properties; In the Barlto basin they
have 20 to 25 percent porosity.
In late 01Igocene to early Miocene, there was even more widespread
transgression, and these transgresslve basal sandstones are productive of oil
In North Sumatra and Central Sumatra and possibly In South Sumatra and West
Natuna. Though as yet unproductive, these sandstones are of high potential In
East Kalimantan. During the end of this geologic time range, rising highlands
of Malaysia were the source of the Slhapas and Talang Akar deltas In the
Central Sumatra, South Sumatra, and West Java basins. These deltaic
sandstones, along with basal transgresslve sandstones, have yielded most of
the Indonesian petroleum produced In recent years. Central Sumatra deltaic
sands alone provide about half of Indonesia's production of 1.4 MMBOPD.
b. Miocene Reefs
A single, lower Miocene, deeply burled, porous reef of central North
Sumatra basin, the Arun Field, produces almost two-thirds of the reef
production of Indonesia (73 MMBOE gas and 22 MMBOE condensate In 1980). Other
deeply burled reefs are Indicated, and upper Miocene reefs yield oil and gas
on the shallow foreland of the North Sumatra basin. In the South Sumatra and
Northwest Java basins, the lower Miocene Is represented In part by carbonate
rocks In the form of Isolated reefs (Batu Raja Formation), but eastwards, In
the East Java Sea and Barlto basins, equivalent age carbonates were deposited
as a thick platform sequence.
In the middle Miocene, an extensive, 1,000 to 3,000-ft thick carbonate
platform with large (up to 25,000 acres) reefs (Terumbu Limestone) occupied
the East Natuna Basin Shelf (the Terumbu Limestone). In one structure, the
"L" structure, the porous zone (extending down Into the platform carbonate) Is
5,261 ft thick. Hydrocarbon gas (I.e., excluding 72 percent carbon dioxide)
reserves of this single unproduced structure are estimated to be more than 60
Tcf.
c. Neogene Regressive and Deltaic Sandstones
Starting In about the middle Miocene, seas began to regress from the
Asian Continental Block as a result of widespread deltaic deposition around
the perimeter of the block. The deltaic sandstones, although not as abundant
as Paleogene and lower Miocene deltaic sandstones, produce one-third of the
oil and gas In Indonesia. These sandstones are of secondary Importance In
Sumatra, but they are the primary producers In the West and East Java and
Kutel basins. Upper Miocene sandstones are also the main producers (over
100,000 BOPD and unknown amounts of gas) In the adjoining, down-dip Malayslan
portion of the Indonesian West Natuna basin.

11
 Australian Continental Block Reservoirs
There are three groups of reservoirs corresponding to the main
sedimentary groups of the province on the Australian Continental Block.
a. Cretaceous Sandstones
Sandstones and shales, ranging In age from Jurassic to Paleogene, but
mainly of Cretaceous age, are present In most of southern New Guinea. They
exceed 1,500 ft In thickness, and, although details of reservoir quality are
unavailable, appear to be prospective as reservoirs In the Salawatf-Bfntunf
and Arafura basins.
b. Miocene Reefs
Middle to upper Miocene reefs produce oil In the Salawatl subbasln and
are the objectives In drilling of the Blntunf subbasln and the Arafura basin.
Many reefs are dry and are believed to have been especially prone to leaking
and flushing because of Insufficient penecontemporaneous shale cover which Is
an important requirement for petroleum accumulation In these basins.
c. PIlocene Sandstones
There are two different geographic groups of Neogene, Pliocene,
sandstones In Irlan Jaya. One group Is made up of the Steenkool, Klasaman,
and Buru Formations, and extends east-west along the southern side of Irlan
Jaya Central Ranges. This group Is shale and sandstone, with many, extensive
sandstones at least In the BIntunI subbasfn.
The second group, The Mamberamo Formation and Its equivalent, Is as much
as 15,000 ft In thickness In the Waropen basin. It Is derived from the
Central Ranges to the south and from accreted island arc to the north. Gross
descriptions report an abundance of graywackes and subgraywackes In the
section, Indicating less favorable reservoir quality. However, reported
graded bedding Indicates that turbldftes exists In the deep Waropen basin and
that there Is some chance that adequate reservoirs are present.
Summary
1. Fourteen of 44 Indonesian basins are considered to have adequate thermally
mature, organic-rich source rocks. There may be undiscovered petroleum
resources outside of these 14 basins, but the amounts are not significant In
this assessment, and are not considered further In the text of the report.
2. Four additional basins may have sufficient thermally mature source
sediments but the organic richness of the sediments Is In doubt. Three of
these basins, though not included In the text discussion, are included In the
play analyses.
3. Reservoirs of varying but adequate quantity and quality are present In the
14 basins with presumed favorable source rock, with the possible exception of
South Makassar basin, leaving 13 basins with both adequate source and
reservoir rock, which form the text of the report (South Makassar, however, Is
Included In the play analysis).

12
4. Half of the oil and gas (58 percent of the oil) produced In Indonesia
comes from Eocene - lower Miocene transgressIve and delta front sandstones,
which are largely confined to three basins, Central Sumatra, South Sumatra,
and Northwest Java basins.
5. One-third of the oil and gas (31 percent of the oil) Is produced mainly
from regressive Miocene-Pliocene sandstones In the Kutel basin (94 percent),
with the remaining 6 percent from the North Sumatra and Java basins.
6. Seventeen percent of Indonesian oil and gas (10 percent of the oil) Is
produced from Miocene reef reservoirs. When the "L" Structure Gas Field (East
Natuna) Is developed, most of Indonesian petroleum, mainly gas, will be from
Miocene reef reservoirs.
7. Most of the Irlan Jaya basins, I. e., the Arafura basin, the Waropen
basin, and the BIntunI subbasln, apparently have adequate source and reservoir
rocks where exploration has been minimal and no discoveries have been made.
INDIVIDUAL BASIN ASSESSMENTS
North Sumatra Basin
Location and Size
The North Sumatra basin Is the westernmost of the Indonesian basins (fig.
1). As In the case of the other Sumatran basins, It Is on the western edge of
the Sunda continental block. It occuples^the northwestern part of the Island
of Sumatra and has an acea some 33,000 ml with a sediment volume of
approximately 97,000 ml (fig. 5).
Exploration and Production History
Oil production began In 1885 from the Telaga Said Field, the first
production In Indonesia and the birth of Shell Oil Company. By World War II,
exploration resulted In a modest potential production of some 20,000 BOD.
After a long Interruption by World War II and subsequent political unrest, oil
production slowly rose to about 25,000 BOD. Initial exploration targets were
relatively shallow Miocene-Pliocene sandstones; the traps were largely found
by surface geologic Investigation. Later geophysical work led to the
discovery of relatively deep (10,000-foot) gas In lower Miocene carbonate
rocks at Arun In 1971, which was estimated to contain about 14.25 Tcf of gas
plus approximately 755 MMB of condensate. Gas and oil were later discovered
In sandstones and In small offshore reefs on the North Sumatra Shelf.
Six plays have been developed In North Sumatra (figs. 6 and 7) (1) deep
basin reefs, 2) Neogene sandstones, 3) shallow shelf reefs, 4) early Miocene
shelf sandstones, 5) Paleogene basal drapes, and 6) offshore slope, which will
be discussed In some detail. Only one of these plays (deep basin reefs) has
major production, one play (Neogene sandstones) has minor production, two
plays (shallow shelf reefs and early Miocene shelf sandstones) have Indicated
discoveries but are yet to be put on production and two plays (Paleogene basal
drapes and offshore slope) have yet to provide a discovery.
The estimated future discovery rate for the deep basin reefs Is 20
percent; the Neogene sandstones, 14 percent; the shallow-shelf reefs, 22
percent; the early Miocene shelf sandstones, 20 percent; the Paleogene basal

13
 100°

NORTH SUMATRA
6° TOP PRE-TERTIARY
0 60 KM

CONTOUR INTERVAL 4000 FEET

OIL FIELD
GAS FIELD
FORELAND EDGE EFFECTIVE BASIN
UPLIFTED MONTAIN EDGE OF BASIN
EARLY MIOCENE HINGE LINE
- 200 M WATER DEPTH
- INTERNATIONAL BOUNDARIES

Figure 5.--Structure contour map North Sumatra basin showing depth to basement
After Kingston (1978).
 EARLY - MIDDLE MIOCENE PLAYS

BASINAL SHELFAL

Peutu carbonate Malacca carbonate

Parapat drapes Belamai drapes

Note: Play (|)Mio-Plio folds, approximately

covers basinat area^except deep water
Play © Deep water

Figure 6.--Map of North Sumatra basin showing distribution of plays

 EAST

SEURULA FORMATION

BAONG FORMATION

NORTH SUMATRA
DIAGRAMMATIC CROSS SECTION
PLAYS

Peutu carbonate (gas)

2 Mid-Pliocene sands (oil and gas)

Malacca carbonate (oil and gas)

Belamai sands (oil and gas)

Parapat sands (gas)

Edge of over-pressured shale

VARIOUS FORMATIONS

Figure 7.--Diagrammatic cross section of North Sumatra showing play distribution.

drapes have an assumed average of about 7 percent and the offshore slope even
less, about 5 percent.
Exploration fs stfll In an early mature stage; for the deep basin reefs,
about 50 percent exploration Is estimated; for the Neogene sandstones, 75
percent; for the shallow shelf reefs and early Miocene shelf sandstones, an
average of about 30 percent; and for the Paleogene basal drapes, 10 percent.
The offshore slope Is yet to be explored.
Original primary reserves appear to be about 2.1 billion barrels of oil
and condensate (2.377 according to EIA, 1984) and 16.25 Tcf of gas, Including
14.25 Tcf of Arun proven gas reserves and an estimated 2 Tcf of undeveloped
gas discovered In the shelf reefs.
Structure
General Tectonics
The North Sumatra basin Is one of three Inner-arc (back-arc) basins along
the east side of Sumatra (figs. 1 and 5). The trace of the subduct Ion zone,
where the Indian Plate subducts obliquely beneath the Sunda Continental Block,
Is about 160 ml offshore, west of and parallel to the west coast of Sumatra;
the related volcanic arc forms the Barlsan Mountains along the west side of
Sumatra. The North Sumatra basin lies between the Barlsan Mountains on the
west and the Malaysia craton area on the east and Is underlain by continental
crust of the Sunda Continental Block.
The formation of the North Sumatra basin began with the development of
Isolated subbaslns In a north-trending Paleogene, or older, down-faulted
trough with horst-graben structures. Initial sediments were locally derived
coarsely clastic, non-marine In nature (fig. 7), followed by dark,
carbonaceous, brackish water shales. By early Miocene time, continued
subsidence west of an early Miocene hinge line resulted In coalescing of the
subbaslns In a quiet, marine environment. West of the hinge line, deposition
was largely shale with carbonate fades over horst-block highs, while
calcarenlte and sandstones or reefa I carbonates were deposited on the platform
east of the hinge line. Continued slower subsidence resulted In deposition of
shale Interbedded with sandstones of probable turbldlte origin coincident with
the rise of the Barlsan Mountains on the west side of the basin. From middle
Miocene and later, the principal source of the sediments was from the Barlsan
Mountains. Prior to this, the Malaysia craton on the east was the source
area.
Structural Traps
The most petroliferous traps In the basin are stratlgraphlc and are
discussed under reservoirs (deep basin reefs and shallow shelf reefs).
The oldest structural traps are those associated with Paleogene north-
trending horsts and grabens, which are largely confined to the deeper, baslnal
area west of the hinge line (fig. 5), and cover an area approximately 5.6 mil-
lion acres (MMA), the Paleogene basal drape play area (fig. 6, area 5). The
total area of all traps, Including largely drape structures and some fault
closures Is estimated to be 5.5 percent of the play area or 308,000 acres.
Reefa I buildups associated with the horst and graben features, discussed under
reservoirs, are Important petroleum reservoirs, but are restricted In area
(fig. 6, area 1).

17
 East of the early Miocene hfnge line (fig. 5) Is the shallow Malacca
Shelf, which has an Irregular pre-Tertlary erosion surface of low relief,
faulted knobs, following an approximate north trend. The knobs are the loci
of draped sandstones and carbonate buildups of Tertiary age. In general, the
knobs are mainly, but not exclusively, associated with reefal buildup In the
northern one-fourth of the shelf (figs. 6 and 10), an area some 2.7 MMA
compared to 10.7 MMA for the entire shelf area. Drape structures are present
over the entire shelf. On the onshore part of the shelf, Isolated highs, I.e.
drape trap areas, make up 2 percent of the shelf area.
Apart from these older, basement-controlled structures are younger
northwest-trending anticlines Involving Miocene and Pliocene sandstones.
These folds appear to be partly of compresslonaI, and of dfaplrlc origin, and
are present over the entire baslnal area west of the hinge line (fig. 6), an
area of 5.6 MMA. Based on Mulnadlono's (1976) map of part of the area (fig.
8) approximately 8.3 percent of the Neogene sandstone (fig. 6) play area lies
within closed anticlines, comprising 470,000 acres.
Sumatra was affected by dextral strike-slip (wrench) faulting, from at
least the middle Miocene, as the Indian Plate slipped northward past the Sunda
Continental Block. This event produced drag folds In Central Sumatra, but the
drag origin of any of the folding has not been recognized In the North Sumatra
basins, possibly due to the masking effect of shale dlaplrlsm.
Stratigraphy
General Stratigraphy
General stratigraphy of North Sumatra Is summarized In figure 7. Basal,
non-marine, coarse elastics (Parapat Formation) were deposited Initially as
basal sandstones In Isolated graben-type basins In Paleogene time, followed by
the deposition of brackish water, carbonaceous shales (Bampo Formation).
Subsidence continued In early Miocene time, and Isolated subbaslns
coalesced with the deposition of the marine Peutu Formation more seaward
(westward) of the early Miocene hinge line (fig. 5), and deposition of the
Belumal Formation on the shelf to the east. The Peutu Formation Is a
calcareous shale-carbonate unit with the carbonate fades In the form of reefs
(principal gas reservoir) on topographic highs. The Belumal Formation Is a
calcarenlte, or sandstone, and shale unit with an equivalent carbonate fades;
the carbonate fades (Malacca Limestone Member) forms carbonate buildups over
basement highs. Maximum marine encroachment occurred In the middle Miocene,
when the thick shale of the Baong Formation was deposited. Interbedded with
the shale are Isolated sandstone bodies, which have produced minor amounts of
hydrocarbons to date.
Accelerated uplift of the Barlsan Mountains In Miocene and Pliocene led
to deposition of sandstone and shales of the Keutapang, Seurula, and Julu
Rayeu Formations. In the west and south, adjacent to the Barlsan Mountains,
these formations are mainly sandstone but become more shaly to the east and
north. These sandstones are the principal oil reservoirs In the North Sumatra
basin.
Reservoirs
The five principal reservoirs of the North Sumatra basin Tertiary section
are, In chronologic order: 1) Paleogene basal sandstones (Parapat Formation),
2) deep basin reefs (Peutu Formation), 3) lower Miocene shelf sandstones

18
 £.?$ TRAP AREA
TOTAL AREA
PERCENT TRAP

SEISMIC STRUCTURAL CONTOUR MAP Of H,

Figure 8.--Structure contour map of part of North Sumatra basin showing depth
to a Miocene seismic horizon. After Mulhadiano (1976).
(Belamaf Formation), 4) shallow shelf reefs (Malacca limestone Member, Belamal
Formation), and 5) Neogene sandstones (Baong, Keutapang and Seurula
Formations). These reservoirs are each of a unique geologic setting, and In
four of six settings, the reservoir characteristics designate the play. The
greatest hydrocarbon (gas) producer Is the deep basin reefs. Neogene
sandstones have produced all the oil to date from the basin, and gas and oil
production Is planned from the shallow shelf reefs. The lower Miocene shelf
sandstones have yielded gas and oil, but at rates that are only marginally
economic and the Paleogene basal sandstones have had only minor shows.
1. Paleogene sandstones (Parapat Formation)
Quartzose sandstones are present locally around the horst paleotopography
that formed In the deeper part of the basin In late Mesozolc-early Paleogene.
No data are available concerning effective pay thickness; In any case, this
would not be a limiting parameter, and one hundred feet Is assumed as an
average effective pay. The porosity of these basal sandstones Is poor,
averaging about 12 percent where measurable.
2. Deep basin reefs (Peutu Reefs)
Gas accumulations occur In carbonate reefs and banks of the lower Miocene
Peutu Formation. The play Is limited to carbonate platforms over Paleogene
horst blocks In the deep, central pact of the North Sumatra basin (fig. 6).
The area of the play Is about 860 ml or .55 million acres (MMA).
Reefs appear to have grown on the higher parts of an Irregular carbonate
platform. At Arun Field, reef growth, starting perhaps from a number of
paleotopographlc highs In this case, may have coalesced to form one large
(42,000-acre) reef complex (fig. 9). Extrapolation fn a part of the play
Indicates that about 13 percent, or about 71,000 acres, of the play area may
be untested carbonate buildup.
Information concerning the reef objectives of this play Is limited to the
Arun Limestone (a member of the Peutu Formation from which gas of the Arun
Field Is produced). The reservoir In the Arun Field has an average net pay of
503 ft, and an average porosity of 16.2 percent with a water saturation of 17
percent. The Arun reef Is probably one of the thickest reefs of the Peutu
Formation; a realistic average pay thickness for the play Is about 350 ft.
The reservoir parameters of the Arun Field, mentioned above, are assumed to be
average for the play. The volume of recoverable gas In these deep basin reefs
Is enhanced by the effects of over-pressure; reservoir pressure Is reported to
be about 7,000 pounds per square Inch at the Arun Field at a depth of about
10,000 ft.
3. Lower Miocene Shelf Sandstones (Belumal Formation)
The Belumal Formation, made up of quartzose sandstones, calcarenltes, and
shales, overlies the shelf area of the basin (areas 3 and 4 of fig. 6). The
quartzose sandstones are plentiful In the south, but carbonate-cemented
sandstone and carbonates predominate to the north; therefore, the IImlted
prospective reservoir, confined to area 4 (fig. 6), Is about 8 million acres
(MMA).
Effective thickness of pay Is very Irregular owing to unpredictable and
rather pervasive effects of calcium carbonate cementation. Available data
Indicates that the average effective pay may be about 150 ft. Hydrocarbon
recovery generally Is low owing to the effects of both this carbonate
cementation and to flushing. Fifteen percent porosity, 25 percent water
saturation are good averages for the Belumal Formation reservoirs.

20
Figure 9.--Structure contour map of Arun gas field, contours on
top to Peutu carbonate. After Alford et al. (1975).

21
4. Shallow Shelf Reefs (Malacca LInestone Member, Belumal Formation)
Reefs are situated on the Irregular surface of the shallow Malacca Shelf
east of the hinge line (figs. 5, 6, 7, and 10). They appear to be confined
to the northern third of the Malacca Shelf, an area of about 2.7 million
acres. Distribution of the reefs follows a northerly trend along pre-Tertlary
and Paleogene paleotopography similar to early Miocene drape features (see
Structural Traps) (fig. 10). Some 70 carbonate buildups were mapped by 1982,
which had areal closures ranging from 125 to 10,000 acres and vertical relief
of up to 1,100 ft (McArthur and Helm, 1982). The trap area of the reefs Is
estimated at 3.5 percent of the play area, and only about one-half of this
area has been tested.
Reported hydrocarbon columns In the reefs range up to 680 ft, and average
effective pay In the play Is 200 ft. Average porosity value of reef limestone
Is around 24 percent, and the reef dolomite Is about 20 percent, for an
overall average of 22 percent. Permeability Is variable and, as Indicated by
drill-stem test data, Is appreciably affected by fracturing.
5. Neogene Sandstones
These shaly sandstone reservoirs largely derived from the rising Barlsan
Mountains to the west, are most prevalent In the western, more basfnal part of
North Sumatra basin. These sands are Involved In structural folds In area 5
(fig. 6). Reservoir sandstones occur In three formations, Baong, Keutapang,
and Seurula (fig. 7). The Baong Formation Is largely a shale unit with
Interspersed Isolated sandstones; the Keutapang contains many sandstones and
the main potentially productive reservoirs; the Seurula has relatively little
sandstone. The maximum gross sandstone thickness In the Keutapang Formation
Is 468 ft with In 14 zones; sandstones average 10 to 20 ft In thickness.
Average sandstones thickness over the play area Is estimated to be 150 ft.
The sandstone reservoirs are shaly and porosity ranges from 15 to 20 percent.
Seals
The seals consist of shales of varying effectiveness. Of some concern
are the blanket sandstones of the shelf part of the basin (Belumal Formation),
which extend to the outcrop area, and where there has been extensive flushing
of reservoirs on a regional scale.
Seal for the deeper basfnal gas plays, that Is, the deep basin reefs and
probably most of the Paleogene basal sandstones, Is massive, thick over-
pressured shale. The younger, oil and gas-bearing Miocene-Pliocene clastic
section has a high shale content. The sandstones also have a high clay
content and generally low permeability, and so the clay Is believed to be a
fairly effective seal. The shallow shelf reefs of the eastern shelf generally
have a thin shale cover. Because of this, leakage may have occurred from
these reefs.
Source Section
The main source rock Is confined to the lower Baong Formation and the
older part of the section below approximately 8,000 feet (see below).

22
 ^MALAYSIA
V\

\ SUMATRA)

CO

Figure 10.--Map of shelfal area of offshore North Sumatra basin showing reefs and reefal
oil'and gas fields. After McArthur and Helm (1982).
Petroleum Generation and Migration
Richness of Source
Measurements of the total organic carbon In the thermally mature
sediments averages about 1 percent, which Indicates an adequate, but not rich,
source rock (Kingston, 1978). Organic matter appears to be a mixture of gas-
prone and oil-prone kerogen. Adequacy of source, as well as seals, Is
confirmed by the 60 percent fill of the Arun reef reservoir, 40 percent oil
and gas fill for the Miocene-Pliocene folds, 30 percent fill for the shelf
sandstones, and a high 80 percent fill for the shelf reefs.
Depth and Volume of Source Rock
Depth to the top of the mature sediments Is confirmed by vltrlnlte
reflectance and carbon preference Index measurements from a number of wells
(Kingston, 1978). However, the depth varies throughout the basin because of
local variable thermal gradients and subsidence rates, but averages about
8,000 ft, Indicating that there Is a volume of mature or over-mature sediments
of about 25.6M ml.
011 versus Gas
The major gas zone Is limited to the deep, predominantly shale basin
within overpressured depths, while the oil Is limited to the shallow edges and
shelf of the basin. It Is believed that most undiscovered petroleum would be
In the deeper, less explored parts of the basin, and would be only 7.5 to 15
percent oil versus gas while the shallower platform areas would be 25 to 75
percent olI.
Migration Timing versus Trap Formation
Assuming a uniform subsidence and thermal gradient through the Tertiary,
petroleum generation and migration from source rocks would have commenced In
about early Miocene time, when subsidence of the deeper parts of the basin
reached 8,000 ft, and continued to the present. Source rocks affected range
In age from 01Igocene to late Miocene. Since the principal reservoirs are
lower Miocene reefs and Pliocene structural folds Involving upper Miocene
sandstones, It appears that the beginning of migration followed the formation
of carbonate traps, but generally antedates the structural traps that contain
sandstone. Migration was considerably Impeded by a thick, massive section of
overpressured shale of 01Igocene to middle Miocene age. It Is believed that
the overpressured shale allowed only the migration of the smaller hydrocarbon
molecules (I.e., gas) by molecular diffusion. The larger molecules (I.e.,
oil) remaining locked In the shale until continued subsidence and heat
eventually cracked the molecules to gas. Under these conditions, the deeper,
central basin shale-enveloped reefs, e.g., the Arun reef, accumulated only
gas. In contrast, the shallower basin edge sandstones accumulated oil,
derived from shallower shales Interbedded with the sandstones which bled off
the overpressure that Impeded migration of the larger oil molecules. The
amount of oil that migrated and accumulated Is limited, however, Inasmuch as
only a relatively small part of the total volume of thermally mature strata Is
In the relatively shallow shale and sandstone section above the overpressured
shale. Some, or all, of this shallow oil (67 percent gasoline) may be

24
retrograde condensate derived from gas/condensate which migrated along faults
from the deep, geopressured section.
Plays
North Sumatra basin Is divided Into six principal plays, which are
discussed In detail In the play analysis sheets and listed In order of their
estimated potential, as follows:
1. Deep basin reef play. Gas accumulations In deep basin carbonate reefs
and banks In the lower Miocene Peutu Formation (figs. 6 and 7).
2. Neogene sandstone play. Oil and gas accumulations In middle Miocene to
lower Pliocene sandstones of the Baong, Keutapang, and Seurula Formations
trapped In Neogene anticlines (figs. 6 and 7).
3. Shallow shelf reef play. OH and gas accumulations In Miocene carbonate
buildups (Malacca Member, Belumal Formation) on the relatively shallow
foreland shelf (figs. 6 and 7).
4. Lower Miocene shelf sandstone play. Oil and gas accumulations In lower
Miocene clastic reservoirs of the Belumal Formation, draped over north-
trending, low relief basement highs on the foreland shelf (figs. 6 and 7).
5. Paleogene basal drapes play. Oil and gas accumulations In Paleogene
basal sandstones of the Parapat Formation draped over horst blocks In the
deeper part of the basin (figs. 6 and 7).
6. Offshore slope play. Oil or gas accumulations In folded or faulted rocks
of the deep-water slope off the north coast of Sumatra.
Central Sumatra Basin
Location and Size
The Central Sumatra basin Is In the central part of eastern Sumatra (fig.
1), near the west edge of the Asian Continental Block. It has an area some
27,000 ml , or 17.2 million acres, and Is a relatively shallow basin with a
volume of approximately 29,000 ml (figs. 11 and 12).
Exploration and Production History
Petroleum exploration, begun In 1938, Included outcrop surveys, shallow
stratfgraphlc dug-pits and holes, followed by seismic surveys. A shallow gas
field, Sebanga, was discovered In 1940. The discovery well of the MInas oil
field was located just prior to World War II and actually was drilled by
Japanese occupation troops In 1945. Subsequent exploration of the Central
Sumatra basin resulted In the discovery of about 125 oil fields, with original
reserves (as of 1978) of approximately 8.746 BBO (EIA, 1984) (fig. 11).
It Is estimated that exploration of the basin Is In a mature stage, about
75 percent complete. Greater than ninety percent of the petroleum comes from
one play, the Slhapas sandstones (lower Miocene deltaic sandstones). The
discovery rate Is about 22 percent, but Is probably declining. It Is

25
 RUPAT ISLAND

Duma!
Oil Wharves
RANTU BAIS
BATANG

N. MENGGAl

MENGGALA SIKLADI

CENTRAL SUMATRA

IDUSAN

rpuSAKA

2AMRUD
\KOTAGARO

BUNGSU

NORTHERN CENTRAL SUMATRA

Figure 11-. Sketch map, principal oil fields, Central Sumatra.

26
 THICKNESS OF
ERTIARY SEDIMENTS

Figure 12.--Structure contour map of Central Sumatra showing depth to basement.

After Wongsosantiko (1976) and Eubank and Makki (1981).
estimated that perhaps 15 percent of the untested, available trap-area may
contain petroleum.
Structure
General Tectonics
The Central Sumatra basin Is one of a series of back-arc (Inner-arc)
basins between the Barlsan Mountain volcanic arc range and the Sunda Shelf
(craton) to the northeast. In general, the basin Is a shallow shelf generally
less than 5,000 ft deep with generally north-trending graben-deeps or
trenches, reaching 8,000 ft deep. While the southern part of the basin Is
shallow, the northwestern one-eighth, the so-called Baraman subbasln, Is about
12,000 ft deep (fig. 12).
There appears to have been two structural events: 1) A Pre-Tertlary to
Paleogene extension, which resulted In a series of approximately north-
trending horsts and grabens, or troughs, which were filled with Paleogene (?),
largely non- marine sediments, and 2) extensive, generally northwest-trending,
dextral wrench faulting and accompanying drag folding, which probably
prevailed through most of the Tertiary, reaching a climax In the Pliocene-
Pleistocene.
Structural Traps
The petroleum-bearing structures of the basin In part resulted from
sedimentary drape over older fault blocks, e.g., MInas and Durl Fields, and In
part, from drag folds associated with wrenching, which Includes most of the
smaller accumulations. Extrapolation from field maps Indicates that an
estimated 5.5 percent of the basin Is trap area. An estimated 75 percent of
the Individual traps have been tested, leaving some 236,000 acres to be
tested.
Stratigraphy
General stratigraphy Is summarized In Figure 14. In essence, the
extenslonal horst and graben structure of the early Tertiary and pre-Tertlary
was leveled by erosion of highs and Infilling of the deep grabens In the
Paleogene by the Pematang non-marine, largely lacustrine strata. In lower
Miocene, the Slhapas Group, a wedge of deltaic-marginal marine sandstones,
derived from the Sunda Shelf encroached southwestward Into the basin. The
Tellsa Formation of open-marine shales Is largely the baslnward equivalent of
the Slhapas Group but also Is In part younger, and Its younger part extends
northeastward over the top of the Slhapas delta beds. Following middle
Miocene uplift and erosion, the basin was filled by coarser elastics derived
largely from the Barlsan Mountains on the southwest.
Reservoirs
Reservoirs of the Slhapas Group contain over 90 percent of the oil of the
Central Sumatra basin. The three principal reservoir units within the group
are the Durl, Bekasap, and Menggala Formations (figs. 13 and 14). The
closures often have stacked reservoirs so that the net effective pay may be as
much as 800 ft, often 200 to 400 ft. It Is estimated, however, that new finds
will be In somewhat less favorable parts of the basin and will average a

28
 '3 >
to 0 Z X r X
cr u> IB IB M u
* 2 - "r __ _, - -1 -. M 1 - 5I -r
3 5 O
«s -
«L s m r> PI s m
I m ROKAN I
GO
I
00
rt
O
-$
to
oo n>
fD O
-n o
I"-3
If
00
c
CT
O>
to
_j.
13
SANGSAM I
m
 FAUN AL
^^H^"^ ^ ^

ZONES LOCAL
M.Y. AGE EPO rw
Ln UNITS
h ANNG- STAGES LITHOLOGY
HIM HA UAMKTON SW NE
PLEISTO-
CENE a MINAS FM./ALLUVIUM Grovel, sond ond cloy
RECENT
2 8
PLIOCENE
5 2 .
MESSINIAN u NI7
6.6 1-
TORTONIAN NI6 Greenish gro/ shole. sondstone
j
H0.3- 6 PETANI FM. ond siltslone
N 15
NN9
N 14
NNB

SERRAVAL- UJ N 13 NN7
_J
LIAN
O N IO
Ic
UJ
o NN6
N II
15.5 2 N 10 H, Brownish groy , calcareous shale ond
Z N 9 NN5
LANGHIAN H ... sdtstane , accosianol limestones
-16.5 UJ N8 H2 TELISA"^n£^
o NN4 J
Fin* to medium groined sandstone
o N7 K ond s(hole interbeds
BURDIGA- L
LIAN NN3 Medium to coarse groined sandstone
2 rr
N6 M ond minor shale

Gray .calcareous shole with sandstone

N5 NN2 N BANGKCjR*^^- < interbeds and minor limestone
UJ
22-S
iafc W^

AOUITANIAN N4 ? NNI 0 MENGGALAFM. ~

Fine to coarse groined sandstone,
conaiomerati'c
-24

PALEO- Red ond green variegated cloystonc

P PEMATANG FM. and carbonaceous shale ,and fine to
6ENE medium grained sondstone

65

PRE- Greywacke.quartzite .granite t argiilile

BASEMENT
TERTIAR^t

Figure 14.--Stratigraphic chart of Central Sumatra basin. From Eubank and Makki (1981).

30
little less pay, probably around 200 ft. Porosity ranges from 10 to 40
percent, averaging 27 percent In the MInas Field; this Is taken to be the
average of the basin. The primary oil recovery factor varies from a low of
7.3 percent at Durl to 25 percent. It Is estimated that the average recovery
Is 350 barrels of oil per acre-foot.
Minor production has developed from the fluvial-lacustrine sands under-
lying the Slhapas Group (Pematang Formation) and from lower TelIsa marginal
marine sandstones, but these possibly additional prospects would not
appreciably add to the estimates of undiscovered petroleum for the basin.
Seals
The regional seal for the Slhapas sandstones are the shales of the TelIsa
Formation, which appear to be quite effective. Intra-Sihapas shales,
particularly of the Banko Formation, are good seals of the Individual stacked
reservoir sandstones.
Source Section
The source section appears to be largely In the Paleogene (Pematang
Formation), but In the more deeply depressed parts of the basin, may be the
Intra-SIhapas shales or, to a slight extent, the TelIsa Formation (see section
on Petroleum Generation and Migration).
Petroleum Generation and Migration
Richness of Source
No organic richness data are available, but It appears that the largely
non-marine, appreciably lacustrine, Pematang Formation must be the principal
source, since 1) It Is the only major unit of which a considerable volume Is
sufficiently deep to be mature, and 2) Central Sumatra basin crude has the
character of non-marine oil source, being of a high wax content and high pour
point.
The organic richness of the Pematang must be extremely high, as may be
deduced by the great volume of oil In relation to the apparent small volume of
source rock, confined as It Is to the deeper grabens below 5,000 ft.
The amount of petroleum fill In available traps may be an Indicator of
the richness of the oil sources. The amount of fill varies from field to
field; some are filled to the spill point while others are only 22 percent
filled. The average fill Is about 40 percent.
Depth and Volume of Source Rock
The average thermal gradient of the Central Sumatra basin Is about 3.7°F/
100 ft. This, together with Its present average subsidence rate, places the
top of the thermally mature zone for petroleum production at about 5,000 ft.
Most of the basin Is shallower than this depth so that the generating area Is
limited to the relatively narrow, deeper troughs, which are largely filled by
the Pematang Formation (see fig. 12). It Is estimated that the source volume
Is 9,200 ml.

31
 011 versus Gas
The gas-oil ratio Is unusually low over most of the basin, 35 SCF/STB at
MInas. It Is estimated that undiscovered petroleum will be 95 percent oil.
Minor gas occurrence In the western part of the basin has been related to coal
versus lacustrine fades In the underlying Pematang source rock.
Migration Timing versus Trap Formation
Assuming generally uniform subsidence and thermal gradient through the
Tertiary, petroleum generation and migration In appreciable quantities would
have started when sufficient source rock reached a depth of 5,000 ft In the
early Miocene. Trapping would not have commenced until shale cover developed
In the early Miocene In the central part of the basin and middle Miocene along
the northeast basin rim, so perhaps some oil escaped, but In general the
timing was early and favorable, perhaps preserving the Sihapas sandstones from
deterioration.
The Sihapas sandstones are good reservoir and conduits, and secondary
lateral migration after the oil reached these sandstones was probably
extensive. It Is believed that a considerable portion of the present drag-
fold closures were filled by secondary migration, I.e., oil already within the
reservoir flowing laterally Into the structure as It was raised.
Plays
Although the Central Sumatra basin Is the most prolific of the Indonesian
basins, ft Is geologically the simplest and Is essentially one play; the
Sihapas sandstones accumulations trapped In either sedimentary drapes or drag
folds.
South Sumatra Basin
Location and Size
The South Sumatra basin Is on the southern end of Sumatra near the west
edge of the Asian Continental Block (fig. 1). It partially Is separated from
the Central Sumatra basin to the north at about 1° south latitude by a large
basement outcrop, the TIgapuluh Mountains, and from the northwest Java basin
by the shallow Lampung Platform (fig. 15). The basin has an approximate area
of 18,300 ml and a sedimentary volume of some 40,000 ml .
Exploration and Production History
Oil production was established In South Sumatra In the late nineteenth
century from the regressive middle-upper Miocene sandstones (Air Benekat
Formation). In 1922 oil production was obtained from the Talang Akar deltaic
sands (Talang Akar Field, fig. 16), which have subsequently proved to be the
primary producing formation of the basin from which, as of 1981, 1.3 BBO have
been produced (Hutapea, 1981). Between 1938 and 1941, gas was discovered In
three small fields from carbonate reservoirs of the Baturaja Formation, which
has developed Into the secondary petroleum and largely gas producer of South
Sumatra. However, recent discoveries of substantial oil have been made In the
Baturaja Formation In the Ramba and nearby fields.

32
lore 104°E

CONTOUR INTERVAL-1 KILOMETER

SCALE 1:2.500,000

VV

LAMPUNG
PLATFORM

Figure 15.--Structure contour map of South Sumatra basin showing depth

to basement., From Hamilton (1979).

33
Figure 16.--Sketch map of principal oil fields of South Sumatra .From
Petroconsultants (1980).

34
 Most of the larger fields, I.e., reserves of more than 50 million
barrels, were discovered prior to World War II. The size of discoveries after
World War II has been declining, and, except for some notable exceptions,
e.g., Ramba, the curve appears to be generally asymptotic to fields of about
10 million barrels of reserves. The anticlinal discovery rate Is declining
and appears to be averaging 10 percent and, at the present activity level,
approaching an average of three successful wildcats per year. The Baturaja
reef discovery rate Is somewhat higher, about 13 percent. The basin Is
estimated to be about 80 percent explored.
Results of exploration to date have been to establish original oil
reserves of 1.7 billion, of which about 1.5 billion had been produced (ElA,
1984). Gas reserves appear to be 4 Tcf, of which 1.7 have been produced as of
1980 (HarladI, 1980; PatmosukIsmo, 1980).
Structure
General Tectonics
The South Sumatra basin Is one of a string of back arc (Inner-arc) basins
between the BarJsan Mountain volcanic arc to the southwest and the Sunda Shelf
(craton) to the northeast. A late Cretaceous to Paleogene tensfonal (and
wrenching) regime resulted In a number of north-northwest-trending, tilted
horst blocks and grabens, half-grabens, or troughs. The Miocene-Pliocene
wrenching, which Is prominent In the Central Sumatra basin, Is not so evident
but surely present (although probably to a lesser degree).
There are little data concerning the amount of structural traps. It
appears that the structures are dominant Iy sedimentary drapes and
stratfgraphlc traps associated with the tilted fault blocks of the late-
Cretaceous-Pa I eogene tenslonal (and wrenching) period. An unknown number of
the productive traps may be drag folds, e.g., the Talang Akar Field.
Structural Traps
Individual structural closures are distributed over the basin. There are
not sufficient data at hand to separate the drapes over tilted horst blocks
from the drag folds associated with wrench faults, but a structure map of part
of the basin where oil fields appear concentrated Indicates that folds, of
either origin, make up 11.5 percent of the area. The percentage probably
would be lower, perhaps 7 percent for the whole basin. These structures
Involve both of the principal sandstone horizons, the lower Miocene (Talang
Akar) sandstones and the middle Miocene-Pliocene sandstones. The lower
Miocene (Baturaja) reefs are localIzed on some of these structures (see
Reservoirs).
Stratigraphy
The Paleogene sedimentation was largely non-marine and volcanic (figs. 17
and 18), filling the lower part of the local grabens and troughs caused by the
tenslonal (and wrenching), block-faulting tectonics of the late Cretaceous-
early Tertiary so that by early Miocene many separate basins had coalesced
Into the South Sumatra basin (figs. 15 and 18). In the early Miocene, the
extensive Talang Akar delta system of light-colored sandstones and dark shales
prograded from the Sunda Shelf westward and southward Into the basin. The
sandstones developed over topographic highs and the shales filled the lows.

35
 ENVIRON
MENT HYDRO CARBON 'OTENTIAL
'ION
AGE FORMA! LITHOLOGY
Member
QUATER
o o o o o NARY Clays, tuff, gravels, sands.
.'x/WWWV UNCON-, <^^vv%«»^V^w*vA,^^V'>^Vi^«< *»^vW*^»«wN^WWVWv'VlS'WV*»<W /NN/WV^
FORMITY
Tuffaceous clays and
II ll KASAI
sandstones, tuff.

« Coals, shales, blue-green RE>

GRES IVE
STT.JJ^i MUARA
ENIM
b Coals, clays, sands
^r.i=*
.

Alternating layers of sands, O

AIR BENAKAT
shales and clays.
_ __ __

cc
_ _ _
GUMAI
cc Shales, clays, claystones.
UJ (TELISA)

*XT; i |_L
JT 1 IT
1 ' 1 ' 1 ' I
i 1 1 1
BATURAJA Limestones and/or marls. TR>
ANSGRES IVE
.,,.,.,..1^1 , 1

sill
Trans - Shales, clays, interdigitating
C - _
TALANG itional f.-m. sandstones
AKAR m.-c. grained sands, inter-
Gritsand
jA-^fEf*?! calations of shale, lignites,
^ 0 l| . . .
Tuff, agglomerates,
LAHAT
breccias, gravel washes
UNCON-
& -JS*******"'"' ^^»W^^v^<vWs/wwvN^^. v^VVVXv*"*vvv*wV'l'''*'vvv'vv"v'v>^v''
' FORMITY
Metamorphosed
PRE-
BASEMENT sedimentary and
TERTIARY
igneous rocks

(Modified from Basuki and Pane, 1976)

Figure 17.--Stratigraphic section, South Sumatra basin.

36
 sw NE

MUARA ENIM PENDOPO-BENAKAT PALEMBANG DJAMBI

ANTICLINORIUM ANTICLINORIUM ANTICLINORIUM ANTICLINES

5,000

10,000
CO

15,000

80 KILOMETERS

50 MILES

After J. M. L. Wennekers, 1958 from Petroconsultants

Figure 18.--Stratigraphic SW-NE cross section transverse South Sumatra basin

About middle Miocene, there was a quiescent period allowing carbonate
deposition on highs (Baturaja Formation), followed by a widespread
transgression of the sea (TelIsa Formation). A regressive period of deltaic
and coarse clastic sedimentation began In late Miocene and has continued to
the present.
Reservoirs
The principal reservoirs are the lower Miocene deltaic (Talang Akar)
sandstones, lower Miocene (Baturaja) reefs, and middle-upper Miocene (Air
Benekat-Maura Enem) sandstones. Each of these reservoirs constitutes a play
and Is discussed more fully In the play analyses. The lower Miocene
sandstones contain some 90 percent of the petroleum reserves.
1. Lower Miocene Talang Akar Sandstones
The Talang Akar Formation contains many discontinuous sandy zones, as
might be expected In a deltaic environment. In the Raja field, there are 16
production sandstones. In an Illustration of a rather thin Raja field
section, which contains only 11 production zones (Hutapea, 1981), there
appears to be about 165 ft of net sandstone development. Elsewhere Basunl
(1978) reported 517 ft of "hydrocarbon bearing sandstones" In the same field.
It Is estimated that the average net thickness over the Raja field may be 200
ft and that this thickness would be a reasonable net average for the South
Sumatra basin reservoirs.
The porosity of the Talang Akar sandstones ranges from 15 to 23,
averaging perhaps 19 percent at the Raja field, which Is taken to be the
average for the basin.
2. Lower Miocene (Baturaja) Reefs
The Baturaja Formation Is a carbonate unit that extends dlscontlnuously
over the South Sumatra basin, the carbonate buildups being concentrated over
Paleogene highs. Extrapolation of a reef distribution map (fig. 19; after
Basukl and Pane, 1976,) Indicates that 1 percent of the play area contains
carbonate buildup, but It Is suspected that double this amount will be
discovered as the demand for gas Is Increased and as further and more advanced
seismic techniques are applied.
In the Raja field, the Baturaja limestone "ranges from thin shaly
limestone sections to Intervals of 170 ft of extremely porous limestone"
(Basunl, 1978); perhaps this 170 ft Is a good average net pay thickness for
the carbonate buildups of the basin.
The average porosity of the Baturaja carbonate In the Raja field Is 20
percent (Basunl, 1978), and this Is taken as the average for the basin. Water
saturation Is 20 percent In the Raja field, and this Is likewise assumed to be
the average for the basin.
3. Middle MIocene-Pllocene Sandstones
In the absence of available data and considering the small amount of
production, the net pay of the middle Miocene-Pliocene sandstones Is probably
relatively thin, perhaps averaging 75 ft.

38
 1049E

CO

P. DEWA

KUANG

EXPLANATION
4°S -
Schematic basement depth

Outcrop of basement
,-WOO
ik-i-) Calcareous build-ups
CONTOUR INTERVAL: 1000 METERS MENGGALA

Figure 19.--Map showing distribution of calcareous buildups of the Baturaja

Formation, South Sumatra. After Basuki and Pane (1976).
 Seals
The principal reservoirs, I.e., the early Miocene sandstones, are
effectively sealed by the middle Miocene marine (TelIsa or Gumal) shales. The
shallower much less prolific sandstones are not sealed so well.
Source Section
The source section Is principally the lower Miocene deltaic dark shale of
the Talang Akar Formation. It Is discussed In the following section.
Petroleum Generation and Migration
Richness of Source
There are no data concerning the richness of source. However, It appears
that at least the dark deltaic coal-bearIng shales associated with main
petroleum reservoirs, the Talang Akar sandstones, are sufficiently organically
rich to be a source rock on the basis of the following:
1. The dark, organic appearance of the shales.
2. ON Is produced from sandstone lenses completely enclosed by the shale.
3. The oil Is waxy and of a high pour-point, which Is usually ascribed to a
terrigenous, I.e., lacustrine, source.
4. Total organic carbon readings In the IIthologlcally similar, coal-bearing
Talang Akar shales In the basin to the east (Northwest Java basin) are high,
Indicating a rich source.
5. The overlying open-marine TelIsa or Gumal shale appears to be a poor
environment for organic preservation and probably Is not an appreciable
source.
6. A general Indicator of the richness (and volume) of source (as well as
seal) Is the amount of petroleum fill. It Is estimated from oil-field maps
that average petroleum fill Is about 40 percent of the closure area.
Depth and Volume of Source Rock
The average thermal gradient Is about 2.15°F/100 ft and the subsidence
rate about 420 ft per million years; this places the average top of the
thermally mature sediments at approximately 6,500 ft and the top of the over-
mature at 12,000 ft. These depths Indicate 1) that the apparently richly
organic lower Miocene (Talang Akar) shales are thermally mature because they
are generally bracketed by these depths (fig. 18); 2) that the gas of the
lower Miocene (Baturaja) reefs Is probably generated blogenetlcally from
Immature sediments, or less likely, In the mature petroleum window rather than
from the thermally over-mature section; 3) that oil accumulations In the upper
Miocene-Pliocene sandstones require at least 1,000 ft of vertical migration,
and 4) that the observed "source beds" of earlier Investigators fit nicely
within these thermal limits (fig. 18). It Is doubtful, however, that much of
the strata within this mature zone, the open-marine TelIsa Formation, Is

40
organically rich enough to produce oil. The volume of source sediment Is
estimated to be 22,500 ml .
011 versus Gas
About 1.7 Tcf of gas have been produced In South Sumatra (HarfadI, 1980);
much additional gas has been vented and much used for reservoir repressurlng.
Original gas reserves amount to 4 Tcf according to HarladI, 1980. Oil reserves
are estimated at 1.7 billion barrels. It appears that the Talang Akar
sandstones contain about equal amounts of oil and gas; the Baturaja reefs
contain mostly gas, perhaps about 30 percent oil; and the minor remaining
untested middle Miocene-Pliocene sandstones with less effective sealing are
perhaps 70 percent oil. The gas of the Baturaja and younger formation Is
generally shallow (<3000 ft) occurring on platforms around the perimeter of
the basin, and although no analyses are available, this gas may be mostly
blogenlc In origin.
Migration Timing versus Trap Formation
Assuming a uniform thermal gradient and rate of subsidence through the
Tertiary, generation and migration would commence when the subsiding,
organically-rich early Miocene Talang Akar shales reached a depth of 6,500 ft,
which would be about In the middle Miocene. At that time, the principal
reservoirs, the Talang Akar, and In most places, the Baturaja Formations, were
In-place, but much of the Miocene-Pliocene sandstones were yet to be
deposited. Drape closures were available for trapping but the reservoirs of
the later Miocene-Pliocene drag folds depended on considerable vertical
migration of relatively late-generated oil. The migration timing appears
especially favorable for the Talang Akar Formation, although there was a
period In the early Miocene when the reservoirs may have deteriorated prior to
the occupancy of petroleum.
Plays
The South Sumatra basin appears to have three principal plays; all extend
over the entire basin. They are considered In detail In the play analyses.
1. Lower Miocene (Talang Akar) Sandstones
Oil and gas accumulations In lower Miocene deltaic sandstones trapped In
anticlines of drape or drag-fold origin.
2. Lower Miocene (Baturaja) Reefs
Petroleum, mainly gas, accumulation In lower Miocene (Baturaja) carbonate
reefs and banks.
3. Middle Miocene-Pliocene Sandstones
Petroleum accumulations In middle Miocene to Pliocene sandstones In
anticlines formed mainly by drag folding or drapes.

41
 Northwest Java Basin
Location and Size
The Northwest Java basin occupies the western Java sea and the adjoining
onshore area of northwestern Java (fig. 1). It Is separated from the South
Sumatra basin by the Lampung high. It has some shallow continuity with East
Java basin to the east, the boundary between the basins being drawn at a
saddle near longitude 110°30 f E. The basin has a number of significantly
deeper early Miocene and older subbaslns, the Sunda, Arjuna, Jatlbarang,
CIputat, and Paslr Putlh (fig. 20). Of these, the Sunda and Arjuna subbaslns
are the largest and principal petroleum producers and are often regarded as
separate basins. The basin, as has existed since late middle Miocene, has an
appreciable thickness (>3,000 ft) of Tertlary,age rocks (fig. 21) over an area
of some 20,600 ml with a volume of 25,600 ml .
Exploration and Production History
Although exploration of the onshore portion of the basin began In 1900,
little was discovered until modern techniques were applied when post-World War
II exploration began In 1967; the first onshore wildcat discovered the
Jatlbarang field In 1969. Offshore drilling commenced In 1968; In 1969 was
the first offshore oil discovery PSI-E1 (EF field) followed shortly by the
discovery of the B field, the largest In the basin. Until the beginning of
1983, 318 offshore wildcats had been drilled; 98 of these were designated
discoveries, giving a success rate of 31 percent. The latest major discovery
(In 1983) was BIma on the east edge of Sunda subbasln (fig. 20) which went on
production In 1986 with recoverable reserves of some 150 MMBO. Drilling
activity and the success rate have risen In late years, but It Is probable
that the new field sizes are diminishing. It Is apparently economical to
Install a small offshore platform or tripod to exploit reserves of as little
as 1 million barrels of oil (Hardjadlwlnangan, 1982), although 3 million
barrels may be taken as an average. This type of development would explain
the high success ratio obtained In the last few years. Reportedly, seismic
data are excellent and, by this date, of fairly dense coverage. Accordingly,
the assumption Is made that around 70 percent of the offshore traps have been
drilled, presumably the larger, closer to facilities, and otherwise more
economical.
Onshore, largely the Jatlbarang subbasln, the seismic data are not as
good, and only 60 percent of the potential onshore traps are assumed to have
been tested. Estimates on reserves are hampered by lack of data and by the
evident number of yet unappralsed or developed fields.
It Is estimated that the original oil reserves, as of the end of 1983,
amount to around 2.75 BBO (EIA, 1984). Indicated original gas reserves as of
1979 are about 2.1 Tcf (HarladI, 1980; Patmosuklsmo, 1980).
Structure
General Tectonics
The Northwest Java basin Is one of a number of back-arc (or Inner-arc)
basins formed between the volcanic arc of Indonesia (I.e., the volcanic
Barlsan Mountains of Sumatra and the Southern Java Mountains of Java) to the

42
 v y. y _y_ Thin Sediments-Basin Edge
Rim of Subbasins
0 MRN Oil or Gas Fields
YANI
Q r\ KARMILA

FARIDAT^ZELD J 6UA

CENTRAL
PLATFORM

SERIBU

PLATFORM

k _JIMUR
BARAT
JATIBARANG

JATIBARANG
JAVA
AJW
TROUGH
SUBBASIN

106° 107' 108* 109°

Figure 20. -Index map of Northwest Java basin showing distribution of subbasins, principal oil
and gas fields, and location of geologic cross sections.
 FORMATION

CISU8UH
CLAYSTONE

PAR1GI LIMESTONE

PRE-PARIGI LST.

MID-MAIN GARB.
"MAIN*""""-"""

MASSIVE

BATU RAJA
LIMESTONE

TALANG AKAR

JATIBARANG
VOLCANICS

BASEMENT

Figure 21. Stratigraphic chart, Northwest Java basin

From Burbury (1977).

44
south and west, and the craton area of Malaysia to the north and east (fig.
3).
Most of the basin Is a shelf, sloping from the craton towards the south.
A hinge line parallel and Just south of the north coast of Java separates the
shelf fades from a deeper baslnal area (Bogor trough, fig. 20) of rapidly
deposited shales and volcanic sediments to the south.
This generally east-trending basin Is transected by a number of north-
trending half-grabens (faulted on the east side) and grabens: the Sunda,
Arjuna, Jatlbarang, CIputat, and Paslr Putlh subbaslns (figs. 20, 22, and 23).
These In turn, are broken Into smaller, closure-producing horsts and grabens.
It Is these subbaslns which preserved organic material and, because of their
depth and therefore heat, are the kitchens of petroleum generation.
Structural Traps
Sedimentary deposition largely filled the subbaslns by the end of the
Paleogene, reducing the relief of the Paleogene fault-block and drape
features. Compaction, however, extended the effects of these features Into
early Miocene sedimentary drapes, but by late middle Miocene these effects
were largely subdued. The effectiveness of Paleogene structural traps Is
therefore largely restricted to the Paleogene subbaslns or half-grabens. «
These subbaslns, shown In figures 20, 22, 23, and 24, have an area 7,000 ml
(5.46 MMA) or about one-third the total basin area (Sunda - 2.8 MMA, Arjuna -
1.2 MMA, Jatlbarang - .74 MMA, and smaller onshore basins - .72 MMA).
No precise Information Is available concerning the amount of subbaslnal
area affected by the Paleogene fault-block and drape closures. In the
vicinity of the Krishna oil field, the closures are Judged to make up about 9
percent of the background area (I.e., after subtracting out the Krishna
structure Itself). In the adjoining South Sumatra basin where the geology Is
similar, the closures affecting 01Igocene-lower Miocene sandstones are deemed
to make up 5.5 percent of the play area. In the East Java Sea basin,
adjoining to the east, Tertiary drapes are estimated to occupy 7 percent of
the play area. On the basis of these analogies, It Is estimated that 6
percent of the Paleogene play area, I.e., the subbaslnal areas (5.5 MMA), Is
under structural closure, an area of some 330,000 acres.
The younger Neogene shallower drape closures are not confined to the deep
subbaslns. As effective petroleum traps, however, they are limited by
sufficient reservoir sandstones In the northeastern part of the Northwest Java
basin, I.e., the area approximately north of the Java shoreline and east of
the Sunda subbasln, an area of some 1.6 MMA (the Arjuna basin, 1.2 MMA and Its
periphery, 0.4 MMA). No Information Is available concerning the Neogene trap
area. By analogy to the traps of the 01Igocene-lower Miocene (Talang Akar)
sandstones, which are also drapes over essentially the same features and are
presumably of parallel structures; these Neogene drapes are deemed to make up
6 percent of the play area or 100,000 acres.
Besides the structural traps, there are two plays Involving carbonate
traps, lower Miocene (Baturaja) carbonates and middle Miocene carbonates,
whose areas and distribution will be discussed under Reservoirs.
Stratigraphy
The sediments of the Northwest Java basin are of Tertiary age and are
summarized In the stratlgraphlc column of figure 21 and cross sections of
figures 22 through 25. The stratigraphy, as displayed, Is generalized for the

45
 SE
NW A'
A
SUN DA SH£L f SUN DA BASIH WEST JAVA BASIH
(AROJUNA SUB-BASIN)
-2 U-l E-l JATISARANfl '44
*

- sooo

-10,000

OH
Gas

Figure 22.--NW-SE geologic cross section, A-A , Northwest Java basin. From World Oil 1973 in
Petroconsultants (1980).
 B
N
Kitty
Diana Cinta Banuwati Hera Fifi

feet
TJISUBUH -... " (CONT'L) '

.'Sunda Shelf.'.".'

AIR BENAKAT

5,000'--
Clnta .'. .

I AKAR
'.''. '. \''.'\-\- (LAGOONAL)
-;.N. Flank Seribu
" " Platform

lo.ooo -.- ......... .. / ^T. AKAR SHELL

10 20
-J L mmt30mls.
0 10 20 30 40 SOKms.

Banuwati Deep -^ ^«__ ,","]",".

LEGEND

Figure 23.--South-north geologic cross-section, B-B , Sunda-subbasin Northwest Java basin.

After Todd and Pulunggona (1971).
 C1
c
NORTH SOUTH

W- 1 B-3 U-1 U-2 HH-1

* * #
Sea Level

-2000' -

-4000' -

-P.
oo
-6000' -
BATU RAJA

\^x
JALANG AKAR

-8000' -

-10000' L
Approximate top of thermally mature sedments taken at Ro = 0.7% or T.A.I. £ 2.7

Figure 24. South-north geologic cross-section, C-C 1 , Arjuna subbasin, Northwest

Java basin. Modified from Fletcher and Bay (1975).
D D'
E

JATIBARAMG
VOLCANIC

Figure 25. West-east geologic cross-section, D-D , onshore Northwest Java basin.
From Sajanto and Sumantri (1977).
favorable shelf part of the basin, north of a hinge line which Is Just south
of the present Java coast (fig. 20). South of the hinge line the rapidly-
deposited, largely shale sedimentation Is dominated by pyroclastlc material,
diluting the organic material and precluding the favorable reservoir
development of the shelf.
Initial Paleogene sedimentation was coarse and volcanic (Talang Akar
grits and Jatlbarang volcanlcs) sediments filling the bottoms of the north-
trending grabens and half-grabens (figs. 22 and 23). This was followed by the
Talang Akar (01Igocene-lower Miocene) delta progradlng southward from the
Sunda craton area carrying quartz sandstones and rich organic material which
filled, or almost filled, the graben subbaslns coalescing the subbaslns Into
the Northwest Java basin entity. A quiescent period followed where carbonates
and shales (Baturaja Limestone) prevailed across the whole basin forming reefs
near the top of the section. The carbonate regime was succeeded by a lower to
middle Miocene low-energy sequence of shelf shales, sandstones, and carbonates
(upper Clbulakan Member or Air Benakat Formation). The sandstone reservoirs,
as well as carbonate reservoirs, of this unit are especially abundant In the
Arjuna subbasln. Towards the top, the upper Clbulakan gradually became more
calcareous, until, In the upper middle Miocene, carbonates (Parlgl Limestone)
again covered the eastern (Arjuna) part of the basin. The Parlgl Limestone Is
overlain by the CIsubah Claystone.
Reservoirs
There are five principal reservoir groups within the Northwest Java
basin. The distribution of each of these reservoirs Is somewhat unique to the
others, and each Is affected by somewhat different traps. They are discussed
from oldest to youngest.
1. Eocene-01 Igocene fractured volcanlcs (Jatlbarang Volcanlcs)
This reservoir Is essentially limited to one subbasln, the Jatlbarang
subbasln, with an area of some 740,000 acres. The reservoir Is fractured
Paleogene tuffs and other volcanlcs, and Its volume as well as Its porosity
and permeability are difficult to estimate. The average gross thickness of
fractured volcanlcs above the oil-water contact In the Jatlbarang field Is 800
ft. According to Todd and Pulunggono (1971), the "average cumulative
reservoir thickness Is 600 feet." Sembodo (1973) Illustrates 120 net ft as an
example. Controlled by fracture permeability, the effective reservoir
thickness Is very Irregular; an average thickness of 350 ft and a porosity of
22 percent Is estimated.
2. 01 Igocene-1ower Miocene deltaic sandstones (Talang Akar Formation
This reservoir Is limited to the area of the Paleogene subbaslns, an area
of some 5.5 million acres. The average cumulative reservoir thickness of the
Talang Akar sandstones for the basin Is estimated to be 110 ft and the average
porosity, 25 percent (Todd and Pulunggono, 1971).
3. Lower Miocene Reefs (Baturaja Formation)
The reefa I reservoirs appear to be more abundant In the Sunda subbasln
(where oil reserves are estimated to be 540 million barrels versus 40 million
barrels for the rest of the reservoirs), but they do extend over the Arjuna
and northern Jatlbarang subbaslns and peripheral areas. An area of some 6,000
ml (3.84 million acres), Including 5,000 ml subbaslnal and 1,000 ml of
peripheral area Is estimated.

50
 Little data are available as to how much of the early Miocene carbonates
are In the form of porous trap, I.e., reefs, banks, and structural closures of
porous zones. A partial map of the Krlsna field reef complex (fig. 26)
Indicates about 18 percent of the mapped area Is porous trap (the Intertldal-
subtldal fades of fig. 26). Away from this field the percent of porosity
would be much lower, perhaps an average would be around 10 percent. A
regional Isopach map of the Baturaja Formation, eastern Northwest Java basin
(fig. 27) suggests that about 15 percent of the Arjuna basin area Is reef (and
Infers no reefs on the onshore portions of the basin). On this basis, It Is
estimated that 12 percent of the entire play area (I.e., .461 million acres)
Is porous trap area. The average net pay thickness Is 66 ft at the FF field,
reportedly 125 ft at the Arlmba (X) field, 75 ft at the Zelda field, and 40 to
100 ft at the Krishna field. Todd and Pulunggono (1971) report 175 ft
"average cumulative reservoirs thickness" for the first wildcats of the basin.
It appears that about 100 ft would be a good average net effective reservoir
thickness for the remaining prospects of the basin.
4. Lower-Middle Miocene sandstones (Upper Clbulakan Formation)
By Miocene time the subbaslns were largely filled and the Intervening
highlands covered so that the sand came primarily from the Sunda shelf to the
north, thinning southwards so that appreciable sand thickness ended approxi-
mately at Java's north shore and apparently also thinning westwards Into the
Sunda subbasfn; In effect, largely limiting viable reservoirs to the Arjuna
subbasln vicinity. On this basis, the area of lower-middle Miocene sandstone
deposition Is estimated to be about 1.6 million acres.
According to Todd and Pulunggono (1971), the average cumulative reservoir
thickness of these lower-middle Miocene sandstones Is 250 ft. An average
porosity of 26 percent and a water saturation of 40 percent were found at
Arjuna B field, and this Is assumed to be an average for the basin.
5. Middle Miocene Carbonates (Parlgl Limestone and Upper Clbulakan Formation)
The distribution of the reef fades of the Middle Miocene carbonates Is
not so closely controlled by the Paleogene structure as that of the under-
lying Baturaja Limestone. The "Mid Main" reefs (fig. 21) are restricted by
the southeastern Serlbu Platform (the M and P fields of fig. 20). The Pre-
Parfgl reefs occur also In this area plus on the highs of the southern Arjuna
Basin. The Parfgl Limestone Is the least affected by the Paleogene structure
and extends over the basin. The reef fades, however, does not appear to
extend west of the M and P fields nor east of Arlmba, nor Is It we 11 developed
In the CIputat subbasln nor In the northern Arjuna subbasln (fig. 20). It has
an estimated play area of 3.2 million acres.
The buildups of the Serlbu Platform, the Arjuna subbasln, and the
Jatlbarang subbasln have been actively drilled. The considerable reef
development of the Central Platform (map, Burbury, 1977) apparently has not
been drilled, perhaps because of shaNewness causing low gas pressure and
concentration, poor seal, and requiring more platforms per trap. As Indicated
by published maps (Burbury, 1977), there are about 690,000 acres of carbonate
trap area (Including the Central Platform). Some of this trap area may prove
Invalid and additional area may be mapped; however, 690,000 acres probably
approximates the amount of trap area In the play. The average cumulative pay
for the middle Miocene reefs appears to range from 30 ft (Todd and Pulunggano,
1971) to 277 ft (fig. 17 of Burbury, 1977). Taking Into consideration the
varying and unpredictable porosity, 120 ft Is estimated.

51
 / PREVAILING WINDS

FORE-REEF/OPEN MARINE

\ , I REEF-CORE

INTERTIDAL-SUBTIDAL

INTERTIDAL- SUPRATIDAL

BASEMENT

o PLATFORM / SURFACE LOCATION

BOTTOM HOLE LOCATION

x /, _ _ _
J; T77-V_ ___ __ .

f- _ _

iffTjX rTTz-
n . » LJ i »Ai \ 7

Figure 26.--Map showing details of lower Baturaja paleoqeography, Sunda

subbasin, Northwest Java basin. After Ardila (1982)

52
 5°00'

\ ARDJUNA -100*
\ \SUB BASIN,
'HICK x \;
(» 'M
^ v>o

5°30'

O1 6°00'
CO

Contour interval 100 feet

0 10 20 Milts
6°30' I i 'i i 1 i 'i '
0 25 Km

EASTERN
N.W. JAVA BASIN
ISOPACH
BATU RAJA FORMATION
i________________i
106° 30' 107°00' 107C 30' 108°00' 108°30'

Figure 27.--Isopach map of Baturaju Formation eastern Northwest Java basin.

From Burbury (1977).
Seals
Except for perhaps the shallowest of the Upper Clbulakan reefs, lack of
seals does not appear to be a problem. In spite of a generally shaly section,
however, primary vertical migration does occur, as evidenced by petroleum
occurrence In middle Miocene reservoirs, thousands of feet above the thermally
mature Paleogene source rock.
Source Section
The source rock appears to be largely limited to the Paleogene part of
the section, I.e., the Talang Akar and Jatlbarang volcanlcs. They are
discussed In detail below.
Petroleum Generation and Migration
Richness of Source
The organic richness of the Neogene sediments, I.e., the sediments above
the Talang Akar Formation, Is generally poor (FI etcher and Bay, 1975). The
Talang Akar sediments on the other hand are organically rich, particularly In
the deeper subbaslns. These deltaic sediments are rich In terrigenous, woody
plant material; a I gal-rich coals are common and reputed to be the principal
source of the West Java oil (type III kerogen). Total organic carbon ranges
from 0.5 to 20 percent. Outside of these deeper subbaslns of fine-grained
sediments, there Is only Talang Akar grits or marine shale fades, and the
source rock potential Is low, thus essentially limiting appreciable petroleum
generation to the vicinity of deep grabens. This richness of source, and also
effectiveness of the trap, Is attested to by the 70 percent fill In the main
reservoir (Miocene sandstone) of the B structure.
Depth and Volume of Source Rock
FI etcher and Bay (1975) report thermal alteration Index (TAD readings
for a number of wells. If one assumes that the onset of substantial
hydrocarbon generation begins at a maturation level of vltrlnlte reflectance
(Ro) of 0.7 percent, which Is approximately equivalent to TAI of 2.75, the top
of the mature zone varies Irregularly between 4,000 and 6,000 ft, probably
averaging about 5,000 ft. At this depth, the mature sediments are limited
approximately to the 01Igocene Baturaja and Talang Akar Formations (of the
Lower Clbulakan) and, more Importantly, are limited to the deeper subbaslns.
Coincidental Iy, both organic richness and thermal maturity limit the
principal source rocks to the deeper subbaslns. Minor amounts of organic
material, however, probably exist In the Upper Cibulacun Formation which
extends, above the subbaslns, throughout the northwest Java Basin at a
relatively shallow depth (<3000 ft). The gas In this upper section Is likely
of blogenic origin.
The volume of source rock In these subbaslnal areas Is approximately
10,500 ml.
011 versus Gas
The oil reserves of Northwest Java are about 2.75 BBO, and gas Is around
2 Tcf. All reservoirs contain oil and gas, but the middle Miocene, relatively

54
shallow (Parlgl Formation) reefs are almost exclusively gas, as are the
Baturaja reefs In the eastern Adjuna subbasln; this gas Is probably of
blogenlc origin. It Is estimated that the overall oil-gas mix Is about 70
percent oil and 30 percent gas, ranging from 75 percent oil In the 01Igocene
(Takang Akar Formation) to 15 percent In the middle Miocene carbonates (Parlgl
and Baturaja Formation).
Migration Timing versus Trap Formation
Assuming a uniform thermal gradient and subsidence rate through the
Tertiary, petroleum generation would begin In the subbaslns when the source
beds, I.e., the Talang Akar shale, subsided to a depth of about 5,000 ft,
which would have been about In the middle Miocene. At that time, the draped
Talang Akar sandstones, as well as the Baturaja reefs, would be largely In
place, and at least partially sealed, ready to receive the migrating
petroleum. Some reservoir deterioration may have occurred during the
01Igocene and early Miocene. The Parlgi Limestone and other Miocene reefs
were deposited somewhat later and probably missed the early migrating
petroleum, but were available for blogenlc gas.
Plays
Five plays are closely linked to the reservoir groups and are considered
In detail In the play analyses.
1. Fractured Paleogene volcanlcs (.74 MMA)
2. 01Igocene-lower Miocene deltaic sandstones (5.5 MMA)
3. Lower Miocene reefs (3.84 MMA)
4. Lower-Middle Miocene draped sandstones (1.6 MMA)
5. Middle Miocene carbonates (3.2 MMA)
East Java Sea Basin
Location and Size
The East Java Sea basin Is largely offshore and lies between Kalimantan
(Borneo) to the north and the axial range (volcanic arc) of eastern Java and
BalI to the south. It extends eastward from a saddle at about Long.
110°30 f E., the Karlmunjawa Arch, on the west to South Makassar Sea on the
east (figs. 1 and 28). Its northern side Is a shelf which continues north
Into Kalimantan. The northern boundary Is placed at what Is believed to be
the northernmost IImlt of primary petroleum migration from the deeper basin
source areas to the south (fig. 28). On this basis, the basin has an area
approximately 43,000 ml and a sedimentary fill of 77,000 ml .

55
4°

h-
0 50 100 Km <
or
0 50 Mi f-
co
Postulated up-dip edge primary petroleum migration

5°

X>- 53A. PAGERUNGEN^

HINGE LINE

VOLCANIC
ARc

\2 { 13' I 14° I 15° 16'

Figure 28.--Sketch map of East Java basin showing depth to basement.. After Kenyon (1977) and
Hamilton (1979).
Exploration and Production History
The onshore Madura subbasln portion of this basin In northeast Java has
produced 170 million barrels of oil from 27 small, shallow fields during the
last 80 years. All Important discoveries were made prior to 1925, and
presently only five minor fields are still operating; peak production was
reached In 1940 when 40,000 barrels per day were produced.
Most modern exploration, beginning In 1967, has been offshore; some 60
wildcats have been drilled. Some discoveries, about ten oil and seven
uncommercial gas, have been announced, but no production has yet been
established. Attempts were made to produce one field, Poleng (fig. 28);
production began In 1975 and ended In 1978 when the field was shut-in. Its
cumulative production Is 1.8 million barrels, and ultimate recovery Is
estimated at 4 million barrels. Subsequently In 1985, the nearby Madura field
was put on stream from presumably the same horizon (Kujung Unit 1) (fig. 29)
with recoverable reserves of 22.1 MMBO and some gas; Initial production of
15,000 BOPD declined to 3,500 BOPD In less than a year. Two recent
significant discoveries are: L-46, between the East Java Shelf and the Ball
basin (fig. 28), which tested 1,000 BOPD from Eocene sandstones possibly over
a drape feature, and Pagerungan gas field near Kangean Island (fig. 28), which
tested 27 MMCFGPD 248 BCPD and has estimated reserves over 3 TCP plus
condensate.
Although some 60 wildcats have been drilled In the offshore, the
exploration of the province Is considered to be only In an Immature stage,
perhaps 30 percent tested. Many of the wells tested traps too far updlp on
the shallow shelf to have been accessible to migrating hydrocarbon. Also,
because of the many small carbonate traps of unpredictable reservoir
properties, many wells will be required to establish the petroleum potential
of the carbonate play.
Structure
General Tectonics
This basin Is a classic back-arc basin lying between the craton to the
north and the volcanic arc to the south (the Java Axial Range). The area of
the basin Is largely a foreland shelf dipping gently southward with an Eocene
to recent hinge line between It and the deeper, baslnal area to the south, the
Madura subbasln and Its eastern extension, the Ball basin (figs. 28 and 30).
The hinge line approximates the northern coast of Java and extends eastward
along the north coasts of Madura and Kangean Islands. The shelf area Is
covered by a relatively thin stratlgraphlc section, averaging less than 6,000
ft (2 km), whereas the baslnal area contains probably more than 30,000 ft
(5 km) of sediments, predominantly thick, plastic shales. The compress Ive
forces, presumably created by the northward subductlon of the India-Australia
Plate beneath the Indonesia Island Arc have created numerous east-west folds
In the more plastic baslnal fill, but not In the thinly covered more rigid
shelf.
The shelf Is crossed by a series of northeast-trending ridges and basins
or half-grabens, controlled by down-to-the-northwest faults of largely
Paleogene age with continued movements Into the Miocene (fig, 28). The origin
of this structure may be marginal rifting of the Sunda Continental Block. The
faults parallel the Cretaceous continental edge as Indicated by the contact

57
 Ul
u> F'ORMATION Petroleum
LJ ojS
O
UJ« Shows
zt MEMBER LITHOLOGY
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RECENT ;^2s=-j-
~^HB_~
SANDSTONES, LIMESTONES.
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6 ^ IT.
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THICK LIMESTONE, OFTEN REEFAL
UNIT W^ AND HIGHLY POROUS -RARELY
EARLY £
DOLOMITIZED OCCASIONAL CHERT
I
S. o AND SHALE INTERBEDS
z
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UNIT INTERBEDDEO FINE GRAINED
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UPPER ^
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l-y*

T 1 '
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IN LQWER PART OF SECTION

sssj
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UJ

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SHALES

AND
AND
LENSES, LIMESTONE
CARBONATE
CLAYSTONES WITH
STRINGERS
BUILD-UPS
SAND

^P*/^y PREDOMINANTLY METAMORPHlCS,

PFIE - TERTIARY K\v>: WITH SOME IGNEOUS ROCKS

Figure 29.--Stratigraphic chart, East Java basin. From Kenyon (1977)

58
 A'
A

SOUTH NORTH

MADURA STRAIT MADURA IS. EAST JAVA SEA

(POLENG) JS-4
MS"'I KONANG JS-20 JS'2 JS-I JS-7

en

BASIN DEEP

Figure 30.--South-north geologic cross-section, A-A 1 , East Java basin After

Koesoemadinato and Pulunggano (1971).
between the granitoid continental crust and the accreted Cretaceous melange,
which underlies the East Java basin approximately corresponding with the
southeast side of the Karlmunjawa Arch (fig. 28).
The plays are controlled to a considerable extent by the tectonics; they
are: 1) shelf carbonate reefs localized by the northeast-trending fault-
originated ridges and by the east-trending hinge, 2) shelf drapes localized by
the northeast-trending ridges, and 3) folded sandstones of the baslnal area.
Structural Traps
Shelf Drape Features. From examination of an unpublished map of the
shelf area Just north of Madura Island, It appears that the drape traps over
basement highs, ridges, and hinge lines make up about 5 percent of the area.
The examined part of the shelf seems to have more structure (and better cover)
than other parts of the play area; so the average percentage of trap area In
the whole shelf play may be only half that of the sample area, or 2.5 percent.
On this basis, there are about 425,000 acres of trap (2.5 percent of 17
million acres of play area; see Plays). Reefs localized by this structure are
discussed under Reservoirs.
Baslnal Folds. Onshore, Eastern Java and Madura Island have small,
shallow structurally complicated fields (active or abandoned) of some 44,000
acres of closure (Soetanlrl and others, 1973). This amounts to less than 1
percent of the 7 million acres of onshore play.
Most of the fields are of such a small size, complicated, and dlaplrlc,
that their offshore development probably would not be economically feasible.
There are, however, some larger folds east of and on trend with Madura Island,
I.e., along and Immediately baslnward of the shelf edge. Here In a limited
zone of about 2.5 million acres are closures which perhaps make up 5 percent
of the zone or about 125,000 acres, most of which Is untested. Considering
these larger offshore, shelf-edge folds along with the few small closures on
land, perhaps there are 150,000 acres of untested traps In this play.
Stratigraphy
The rocks are of two environments; over most of the basin the
stratigraphy Is predominantly shelfal, made up largely of carbonate and shale
with some sandstones, whereas In the southern third of the area (south of the
hinge line), the rocks are largely baslnal, I.e., thick, nerltlc to bathyal
strata, mostly shale with some carbonate and sandstone (figs. 29 and 30).
The stratigraphy of the baslnal area progresses rapidly from the shelfal
fades to the practically all-shale section of the Madura Strait Well MS-1 (35
km south of the hinge line, fig. 30). Reservoirs of the baslnal area are thin
and sparse.
The sedimentation of the shelfal area (fig. 29) began with an Eocene
transgression from the east over an Irregular Mesozolc surface. This was
followed by a period of general quiescence, which lasted, with some minor
Interruptions, through the Tertiary to the present. The sediments are charac-
terized by thick, widespread carbonate units and accompanying shale. More
arenaceous deposition was confined to three zones: 1) the Initial eastern
Eocene transgression, 2) short periods of deposition of OlIgocene sandstone

60
derived from the west, and 3) regressive fine-grained sandstone deposition In
the middle to late Miocene.
Reservoirs
Principal potential reservoirs of the East Java shelf stratlgraphlc
section (fig. 29) appear to be:
1) Eocene-lower OlIgocene transgresslve sandstones
2) Eocene carbonate reefs
3) Lower 01Igocene "CD Limestone" bank carbonate
4) Upper 01Igocene Unit II, Kunjung Formation carbonate reefs and banks
5) Lower Miocene Unit I, Kunjung Formation carbonate reefs and banks
A sixth potential reservoir zone Is the middle Miocene elastics of the
baslnal, off-shelf fades.
All these reservoirs have been tested, and have yielded some hydro-
carbon, but only Unit I of the Kunjung Formation has commercial amounts. The
lower Miocene carbonate reefs and banks appear to be the prime objective
reservoirs (I.e., Unit I, Kunjung Formation), followed by the Eocene carbonate
reefs. In the following discussion, the Eocene-lower 01Igocene transgresslve
sandstones are considered together; the objective carbonate reservoirs are
grouped as one; and the middle Miocene elastics of the baslnal area are
considered as one objective.
Transgresslve Sandstones
Little data are available; these Eocene to lower 01Igocene sandstones are
assumed to extend over the entire shelfal area of some 17 million acres.
Effective pay would probably have to be at least 50 ft thick to constitute an
economic accumulation. An average accumulative effective thickness of 100 ft
Is assumed.
Miocene Carbonate Reservoirs
The reservoirs are In reefs or carbonate buildups confined to the
carbonate shelf of some 5 million acres. By count of reefs In one sector of
the shelf north of Madura Island (unpublished map), It appears that a great
number of small reefs and bank buildups make up about 7 percent of the
carbonate shelf area. Reefs and the buildups appear to be unusually numerous
In this sample area, however, so that the percentage trap of the entire play
would be somewhat lower. Five percent would seem to be a good average, giving
a carbonate trap area of 250,000 acres.
The net pay of Poleng field Is 225 ft (SoeparjadI and others, 1975); JS-
1-1, another announced early discovery, had 20 ft of net pay. An average pay
for a productive accumulation Is probably about 200 ft. The porosity varies,
and Its predictability appears to be a major exploration problem. The average
porosity may be low; 18 percent Is assumed.
Miocene Baslnal Sandstones
These sandstones are limited to the baslnal area where they are
Interbedded In a largely shale section. Great net sandstone thicknesses are
reported from 639 to 440 ft In the onshore and 500 ft In MS-1. These figures

61
appear very high considering the small amount of production obtained. It Is
suspected that the net effective pay thickness Is 200 ft or less.
Seals
The average porosity and the permeability of the stratlgraphlc section
generally Is poor. Seals made up of shales and low-permeablIIty carbonates
abound. Lack of seal does not appear to be a significant problem In this
basin, but considerable oil-stained section, especially In the Eocene
wildcats, Indicates leaking traps.
Source Section
The depth of the thermally mature sediments Is about 7,000 ft. This
IImlts the source rock to the 01Igocene and earller.
Petroleum Generation and Migration
Richness of Source
The organic content of rocks In the East Java basin generally Is meager.
The richest organic carbon values are In the lower "OK M Formation (middle
Miocene) (fig. 31), which range up to 7 percent with a median of 1.75 percent.
This unit, however, appears to be too shallow over most of the basin to be
thermally mature. Units II and 111 of the Kajung Formation (lower Mlocene-
OlIgocene) have organic carbon contents above 0.5 percent (the accepted lower
limit for designating source rock), but It Is somewhat meager with median
values of .55 and .95. Undoubtely, there Is more source rock In Eocene and
01Igocene shale, of unknown organic content, of the eastern part of the basin
where oil-stained Eocene carbonates have been penetrated In several wells and
where 1,000 BOPD have been tested from Eocene sandstones L-46. The petroleum
fill ranges from 100 percent at Poleng down to 6 percent at 53A-1, Indicating
sufficient source, but perhaps leaking traps.
Depth and Volume of Source Rock
The East Java basin with a thermal gradient of 2.2°F/100 ft (Kenyon and
Beddoes, 1977) Is considerably cooler than the adjoining Northwest Java basin
with a thermal gradient of 3.6°F/100 ft. This may be related to Its position
over Cretaceous melange rather than granitic craton (fig. 29). It does
Indicate that mature source rock must be considerably deeper within the basin
and therefore of less volume, possibly explaining the poorer exploration
results In the East Java Sea basin versus the Northwest Java basin.
Thermal Alteration Index (TAD values from an unknown number of wells
scattered over the basin, (Russel and others, 1976) determine the top of the
mature zone of the East Java basin to average around 7,000 ft (when TAI >
"2+") (fig. 32). On this basis, the volume of source rock on the shelf Is
approximately 6,000 ml , and the prospective area Is limited to the graben
areas In the southern third of the shelf (26,000 ml ); I.e., where the
sediments are over 7,000 ft (2 km) deep, plus allowance for perhaps 25 miles

62
 HSTOCRAU OF OR6ANC CARBON VALUES FOR TOE
,-,. ,.,, LOWER *OK", KUDJUNG ONfT I, KUOJUNG UNfTir,
KUOJUNG UNTT JTC, AND *CO" FORMATIONS FROM
xrcn gFi_FCfED VARIOUS JA\A SEA WELLS
of

fL* asa
ftCDuu M 0.4»

VXIt
I

M
CMBON
1

MCDU. N OAS

(MtT
s

it Jen
MCDM 1 O*»
VNJT
XC

ICOUN &S9
j
lOXOOCAMC
co- CAMOM

g. UCJDL4UUU4JOS4 TJ T4 1.0 « «
Percent organic carbon

Figure 31.--Histograms of organic carbon values for the formations

from selected various east Java sea wells. From Russel et al (1976)

'*» 3 3+
» « I
14- 2- 2!o2f 4-
FORMATION STMBOLS
O LOWER*0«"
O KUOJUNO UNIT I -
KUtWUNO UMIT283
A"co"
O

t
I 5 8»
«*8
* U

10

Figure 32.--Chart showing relationship of TAI values, formation,

and depth. From Russel et al (1976).
63
of lip-dip migration; this approximate limit Is shown by a dotted line In
Figure 28.
011 versus Gas
Gas and oil shows have been encountered In many of the 50 wildcats
drilled, but no relative amounts have been recorded. The Poleng field
reportedly has 102 ft of net oil pay overlain by 153 ft of net gas pay
(SoeparjadI and others, 1975). Assuming a tabular shape, this means that oil
takes up about 40 percent of the trap volume, and In the absence of other
data, this Is assumed to be the average for the shelf. The baslnal area may
be somewhat more gassy and perhaps oil Is only 30 percent of the petroleum
mix.
Migration Timing versus Trap Formation
Assuming the thermal gradient and subsidence were constant during the
Tertiary, petroleum generation and migration began when the sediments reached
a thickness of 7,000 ft (2,000 m), which would be about the end of the
01Igocene (top of Unit II) (figs. 29 and 31) In the transverse grabens and
shelf edge (hinge line zone). However, a major part of the up-dlp shelf
subsidence has been slower so that large parts of the sedimentary volume did
not become thermally mature (I.e., reaching 7,000 m depth) until more
recently. Consequently, reservoirs In those areas particularly the objective
lower Miocene Kujlng Unit I, may have been damaged by dlagenesls before being
available to primary petroleum migration from the deeper source-rock areas.
Plays
The untested traps of the East Java Sea appear to be In three principal
plays listed below. Details are given In Individual play-analysis for each of
these plays.
1. Shelf Reefs
Petroleum accumulations occur In Tertiary carbonate reefs and banks on
the foreland shelf of the East Java Sea basin. Most of the prospective reefs
are lower Miocene carbonates, but some may range from Eocene to late Miocene
In age. The area of the foreland shelf Is some 17 million acres, but the
carbonate platform upon which the reefs grew, and considered the play area, Is
about 30 percent of the shelf, or about 5 million acres.
2. Shelf Drapes
Hydrocarbon accumulations occur In sandstones or calcarenltes which are
draped over faulted and tilted basement blocks. Part of the trap may be
closures against those block faults which have continued to act Intermittently
through the Tertiary. The reservoirs are largely confined to Eocene-lower
01Igocene transgresslve sandstones but may Include younger sandstones draped
over carbonate buildups. The area of play Is the foreland shelf of the East
Java Sea basin, which is 17 million acres.
3. Baslnal Folds
Petroleum accumulation occurs In Neogene folds Involving the sediments of
the baslnal area, I.e. the Madura and Ball subbaslns. Reservoirs are
sandstones (or calcarenltes) near the shelf edge. The play Is limited to the

64
deep baslnal area of the East Java Sea basin. The area Is about 10.7 million
acres (fig. 28), but the zone of the most prospective, undrllled traps Is
largely limited to an offshore zone baslnward of the hinge, an area of
approximately 2.5 million acres.
Bar Ito Basin
Location and Size
The Barlto basin Is near the southeast corner of Kalimantan (Borneo)
(figs. 1 and fig. 33). It Is bounded on the north by a saddle between It and
Kutel basin; on the south It merges onto the shelfal portion of the Java Sea
(the boundary Is taken to be about at the coast line). On the east It Is
bounded by the Meratus Range and on the west by the southwestern (Sunda)
platform of Kalimantan at about latitude 114°. It has an area approximately
19,000 ml and a sedimentary fill 43,000 ml .
Exploration and Production History
Exploration began In 1930 and the first oil discovery was made at Tanjung
In 1937. Tanjung and minor satellite fields, Warukln Salatan and Taplan
TImur, are now producing oil from the Eocene, Tarakan Formation. Tanjung did
not begin production until the early sixties; cumulative production as of the
end of 1979 was 93.3 million barrels (Includes the other neighboring fields)
and Is declining rapidly; original reserves of 134 million barrels are
reported. In late 1983, a gas discovery was made at Karendan In a carbonate
buildup at the top of the Beral Formation at the north end of the Barlto basin
where It joins the Kutel basin (fig. 33). In late 1986, an oil discovery,
Bagok-1, of some 1,000 BOD was made In the Warukln Formation.
Structure
General Tectonics
In the early Tertiary, the Barlto basin region was part of a regionally
extensive, stable shelf, which extended over northern Java, the Java Sea,
southern Kalimantan (Borneo), and western Sulawesi (Celebes). The shelf was
underlain by continental crust, Cretaceous granite-Intruded craton In the
west, with accreted Cretaceous melange east of a line running northeastward
from western Java to the Meratus Mountains and northwards along the present
east boundary of the Barlto basin (fig. 33). This extensive shelf persisted
through OlIgocene and early Miocene when It was covered by the thick shelfal
limestone (Beral Limestone). As Indicated by the stratigraphy, a local
Paleogene trough, the Meratus Graben, existed along the present trend of the
Meratus Mountains on the eastern boundary of the Barlto basin (figs. 33 and
34).
The Barlto basin did not form as a separate entity until the end of
middle Miocene with the rising of the Meratus Mountains, the subsidence of the
Barlto River drainage area, and the uplift of the shield area to the west. In
the Pliocene-Pleistocene, the Meratus Mountains apparently were thrusted to

65
 118°

cr>
cr>

Figure 33.--Structure contour map of Barito basin showing depth to basement. After Hamilton (1979)
 WEST EAST
A'
A
Present Meratus Range
Kahayan River Tanjung field Pamukan Bay

fc 5-°°°-<

t
10,000 -

15.000

50 100 MILES
I
I I
50 100 KILOMETERS

Figure 34. West-east restored stratigraphic cross-section A-A Barito

basin. From Rose and Hartono (1979).
some extent over the Barfto basfn. It was at this time that the Tanjung and
other antic Ifnal closures of the basin were formed.
Structural Traps
The Tanjung and adjoining closures are north-trending anticlines with
steep or thrusted flanks to the west; they are limited to the northeastern
part of the basin, an area of some 2.35 million acres. The remaining basin to
the west and south, except for some pre-Tertlary topography, appears to be
relatively featureless. It Is estimated that at the most, the area of trap In
this small play area Is equivalent to that of two Tanjung fields or 15,000
acres (assuming 50 percent fill).
A second structural trap type In the basin Is believed to be drapes of
Paleogene sandstones over pre-Tertlary knobs. One unpublished map In the
northern part of the basin Indicates that these drapes make up about 0.85
percent of the map area; extrapolated over the entire basin, the trap area Is
about 100,000 acres.
Stratigraphy
As In many other basins of Indonesia, the sediments are Eocene to Recent
In age and represent a single general sedimentary cycle. Transgression took
place In the Eocene, standstill, or quiescence, In the OlIgocene through early
Miocene, and regression In the middle Miocene to recent (fig. 35).
The Eocene transgresslve formation, the Tanjung Formation, overlies an
uneven pre-Tertlary surface. This relatively coarse transgresslve marine to
deltaic to continental formation has a maximum thickness of 7,000 ft and thins
southwestward. It contains the main petroleum reservoirs of the basin. The
quiescent OlIgocene-early Miocene period Is represented by a thick shelfal
carbonate with marls and shale, the Beral Formation; at this time the area of
the Meratus Range was deep and In that area the formation Is represented by
marls and shales.
The regressive phase Is represented by marine, deltaic and fluvial
elastics, primarily the Warukln Formation, which was shed from the rising
Meratus Range on the east and the Sunda shield areas on the west. It has some
reservoirs; one small probably secondary petroleum accumulation, which may
have leaked from the primary Paleogene reservoirs, and a larger accumulation
Indicated by the 1986 discovery (Bagok-1) of some 1,000 BOD.
Reservoirs
The principal potential reservoirs are:
1 Sandstones within the Eocene transgresslve formation
The reservoirs are sandstones In the Tanjung Formation, which Is a basal
transgresslve unit. The reservoirs are a mixture of deltaic, paralIc, and
nerltlc, rapidly I ens Ing sandstones. No average pay thicknesses are available
from the literature, but the aggregate maximum thickness Is estimated to be
about 500 ft. Reportedly, there are three principal Eocene sandstones at
Tanjung, making some 140 ft In all. An overall average reservoir thickness of
150 ft Is estimated for the basin.
2. OlIgocene to lower Miocene reefs
In the absence of maps or other concrete Information, It Is assumed that
the reef size and distribution In the Beral Limestone Is analogous to that In

68
Figure 35. Stratigraphic' chart, Barito basin. From
Petroconsultants (1976).

69
the equivalent carbonate section, that Is, the Kujung Formation of the East
Java Sea. There, It was estimated that reef a I fades make up 30 percent of
the play area (12.2 MMA) and that 5 percent of the reef a I fades may be trap.
Using these analogies, the area of reefal fades In the Barlto basin Is 3.66
million acres and the untested trap area 0.183 million acres of which very
little has been tested.
At Tanta, an adjoining fold to Tanjung, producing zones of 250 ft and at
Upper Kapuus, 131 ft, of IImestone, "sometimes very porous11, have been found
In the Beral Formation. In the adjoining East Java Sea, an average thickness
of reservoirs was estimated to be 125 ft. It Is assumed therefore that
average reservoir thickness Is around 130 ft.
3. Sandstones within the middle Miocene and younger regressive elastics
These regressive sandstone reservoirs are reportedly of fair quality but
generally lack a seal. However, the 1,000 BOD was tested from these
reservoirs, WarukJn Formation by the Bagok discovery well of 1986. No net
reservoir thickness Is available, although a gross thickness of 150 ft Is
reported at Tanjung. The Miocene sandstones are not extensive reservoirs over
the basin.
Seals
Hydrocarbon seals appear to be the lower Miocene (Beral) marls and the
middle Miocene (Warukln) shales. These argillaceous beds are discontinuous
and may not form good seals In the northern Barlto basin where the section
becomes more sandy.
Source Section
The occurrence of hydrocarbon In Eocene reservoirs plus the maturation
depth limits Indicate that the probable source section comprises the shales of
the Eocene transgress Ive Tanjung Formation (see below).
Petroleum Generation and Migration
Richness of Source
No specific Information Is available as to the richness of source,
although SJregar and Sunaryo (1980) state "the source rock that provided the
oil for the accumulation In the Tanjung reservoirs has been Identified within
the Tanjung Formation as the shales and marls that were deposited In paralIc
to nerltlc environments . . . these source rocks attained a thickness of more
than 800 m (2,600 ft)."
Depth and Volume of Source Rock
Based on an average thermal gradient of 1.87°F/100 ft and an average
subsidence rate of 236 ft per million years, the top of the thermally mature
sediments Is at a depth of about 8,000 ft or 2,400 m. This limits the
thermally mature rock to mainly the Eocene transgress Ive beds, and perhaps the
lowest part of the carbonate shale sequence, and confirms the observation of

70
SIregar and Sunaryo (1980) that the Eocene shales of this unit are the 3
principal source rock. The volume of this source Is approximately 20,000 ml .
011 versus Gas
The Tanjung field has a small gas cap which occupies about 10 percent of
the trap volume. In 1982, gas was found In the wildcat Kerendan 1, at the
north edge of the basin, presumably In a reef at the top of the Beral
Limestone, Indicating the presence of considerable gas In the basin (or the
adjoining Kutel basin). Oil Is assumed to make up about 50 percent of the
basin's oil-gas mix.
Migration Timing versus Trap Formation
The major subsidence began late at the end of the middle Miocene after
the deposition of the shelfal carbonate In the lower Miocene. It would appear
that In late Miocene time the basin had sufficiently subsided so that the
organic shales of the Eocene transgress Ive series reached thermal maturity and
that hydrocarbons began to generate and migrate. At this time the anticlinal
structures (e.g., Tanjung) had Just started to form, while the carbonate reefs
had formed already In early Miocene (e.g., Kerendan Reef), and burled pre-
Tertlary topography and lower-Miocene stratigraphic traps would have formed In
the Eocene. It would appear that migration began prior to the formation of
the anticlines, which may have therefore failed to catch some of the early
petroleum. On the other hand, migration was somewhat late for the reefs and
drape structures, allowing some reservoir deterioration, especially In the
carbonates.
Plays
There are three principal plays In the basin. Details of the plays are
discussed In the play analyses.
1. Folded Tertiary Sandstones
The play's objectives are petroleum accumulations In Eocene to Miocene
sandstones Involved In middle Miocene to Pliocene folds. The transgresslve
Eocene sandstones are the primary objective, and the Miocene sandstones are
considered minor secondary objectives. The area Is limited to the 2.35
million acres In the northeastern quarter of the basin.
2. 01Igocene-MIocene Reefs
Petroleum accumulations may be In reefs and banks associated with the
01Igocene-lower Miocene carbonate formation (I.e., the Beral Formation).
Reefal fades have been Identified In wildcats, particularly BarIto-1, drilled
In the southwestern part of the basin, In the far northern part of the basin
on the ridge separating the Barlto and Kutel basins, at Tanjung field where a
thick section of "reef a I fades" Is reported, and In the outcrops on the
western side of the Meratus Mountains. The play extends over the entire basin
(12.2 million acres), but by analogy to the adjoining East Java Sea reefs, the
reef a I fades makes up 30 percent of the carbonate Indicating a more favorable
area of approximately 3.66 million acres.
3. Drape Sandstones
Petroleum accumulations are possibly In Paleogene sands draped over

71
basement knobs In the shelfa I area. The play would extend over the entire
basin 12.2 million acres.
Kutel Basin
Location and Size
The Kutel basin Is In the northern part of the southeast coast of
Kalimantan (Borneo). It Includes the Straits of Makassar and extends Inland
some 170 miles to the northwest (figs. 1 and 36). It has an area
50,000 ml «on land and extends offshore to a water depth of 3,300 ft (1,000 m)
(78,000 ml Including the deep water of of the Makassar Strait). The volume
of sediments Is about 210,000 ml ; Including the deep water (>3,300 ft) of the
Straits of Makassar, the basin volume would be 310,000 ml .
Petroleum Exploration and Production History
Oil was first discovered In 1897 In the Sanga Sanga oil field (fig. 37).
Other discoveries were made near BalIkpapan In 1898, Semberah In 1906, and
Samboja In 1908. These were relatively shallow fields producing from upper
Miocene-Pliocene sandstones and were discovered by surface geology. The next
major discovery was not until 1970 when the offshore Attaka oil field was
discovered. This was followed shortly by the major offshore discoveries of
Badak In 1971, Bakapal In 1972, Handll In 1974, and other smaller oil fields
with a combined 1983 oil (and condensate) reserves of 2.56 billion barrels of
oil. During the 1970s, gas and condensate were also discovered In large
quantities, especially at Badak and In on-trend Nllam and Tambora fields to
the south, and Bekapal further south. The Tanu field of the Attaka-BekapaI
trend (fig. 37) was established In the early 1980s. Gas production sufficient
to require a four-train LNG gas processing plant. Indicating minimum original
reserves of some 10 Tcf of gas has been established In the Kutel basin (10.374
Tcf Indicated by Hart ad!, 1980; Patmosuklsmo, 1980). Probably at least 15 Tcf
of gas reserves have been proven by this time.
Discoveries to date have been concentrated around the Mahakam delta area.
Large parts of the Inland basin, though probably less prospective, are very
sparsely explored. The modern discovery rate has been about 33 percent.
Structure
General Tectonics
At the beginning of the Tertiary, the whole region. Including the
southern half of Kalimantan (Borneo), the eastern Java Sea, most of Java, the
Makassar Straits, and western Sulawesi (Celebes) was an extensive continental
shelf. The shelf Is granite-Intruded continental crust In the west and
accreted melange crust to the east. Including most of the Kutel basin, the
Straits of Makassar, western SulesI, and the eastern Java Sea. Rifting of the
accreted melange shelf In the Kutel basin area apparently began In early
Paleogene when the Initial Makassar Straits as well as the Kutel basin and the
adjoining Meratus graben were formed.
The Kutel basin Is bounded to the south and north by two significant but
burled transverse fault zones, which were most active In the Paleogene and had
significant dip as well as strike-slip movements (figs. 36 and 38). The

72
 1 14

KALIMANTAN
(BORNEO)

BARITO SHELF

000 m Isobath
Isopach contour
Isopach contour in
>l 000 m water-depth
-A 1 Structural section (Fig.29)

Contour interval I km
Approximate scale I : 3,000.000
SULAW
(CELEB
NOSTER SHELF
KUTEI BASIN
TERTIARY ISOPACH

Figure 36.--Structure contour map, Kutei basin, showing depth to basement. After Hamilton (1979).
 KUTEI BASIN
FIELD LOCATION MAP
117°00' 117°30' 118*00'

*.KEhlNDINGAN
\
MELANIN

cow

1L V Samarinda
cow -

Oil field

Oil well

Gas well

Abandoned weH

H^ Gas field

- T*** 2 1 Se«ump7l Mandu l^Sepatu Kuda 1 Suspended well

O WeH location
i 11 » Pipeline

Figure 37.--Index map of Kutei basin showing field locations and

significant wildcats.

74
 SOUTH NORTH

D D'
PLAYS 3 AND 2
PALEOGENE -* PLAY 1 PLAY 2
REEFS PALEOGENE
DELTAIC SANDSTONE
DRAPES REEFS

SAMBOJA ATTAKA SANGATTA ~5 MANGKALIHAT

N FIELD FIELD EAST
FIELD
Pamukan A dang 3 YAKIN HANDIL BADAK BangkuHramg
Bay Bay i2 FIELD FIELD FIELD
SANTAN Bay I

10,000 -«--7i,.-y
Ul

20,000 -

30,000
Play 4, Neogene reefs, extends 0 50 100 MILES
I
along entire section. f- \
0 50 100 KILOMETERS

Figure 38.--South-north restored stratigraphic section, D-D 1 , Kutei basin.

From Rose and Hartono (1978). Location figure 41.
Pater Noster fault, which has a large down-to-the-north component, separates
the Kutel basin from the Pater Noster and Bar I to shelves to the south. The
Mangkallhat fault zone similarity forms the north boundary, having a strong
down-to-the-south component. Figure 38 shows the approximate position of
these features and their effect on the Kutel basin stratigraphy.
Subsidence between these transverse zones continued through the late
Paleogene and Neogene with thick sediments, largely derived from the west,
progradlng eastward. These strata were folded Into a number of north to
northeast-trending anticlines, which show crestal thinning of late Miocene and
younger beds. This Indicates that compression Is contemporaneous with uplift
and folding of the Meratus Range In later Miocene time. These events appear
to coincide with the Miocene to recent westward movement and subduct Ion of the
Pacific Plate under Sulawesi.
Although these folds apparently were Initiated by compression, they are
strongly affected by the great thickness of rather Incompetent, shale-
dominated sedimentary fill. A central north-trending zone of folds or
antlclJnorlum extends In width approximately from the shore line Inland to the
Kutel Lakes or northwest swing of the Mahakam River (figs. 36 and 39). The
folds are characterized by steeply dipping axial beds, sinuous axes, and other
aspects of dlaplrlsm. To the east of the antlclInorlum (I.e., offshore), the
folds become less steep but are also affected by dlaplrlsm. To the west, I.e.
the Inner Kutel, the area Is low and the folds are rather abruptly subdued,
probably reflecting thinner sediments over a shelf (fig. 39). Overmature
sediments within drilling depths Indicate uplift, probably In the Neogene.
Of special Interest Is the apparent lack of large scale growth faulting,
such as occurs In the Mississippi and Niger deltas.
Subsidence appears to have accelerated during the Pliocene-Pleistocene,
the Makassar Strait area dropping so that young nerltlc sediments are In 7,500
ft of water. Subsidence evidently took place between north-trending fault
zones, which occur approximately along the 1,000 m Isobaths (excepting the
Mahakam delta area) on either side of the deep-water area of the Makassar
Strait.
Structural Traps
For assessment purposes, the north-northeast-trending structure of the
Kutel basin Is divided Into three zones, which conform approximately to
separate plays: the Inner Kutel of draped or folded Paleogene sandstones, the
foldbelt of Miocene-Pliocene deltaic sandstones, and the outer Kutel basin,
approximately the Miocene-Pliocene reefs and deep water Indicated In figures
39, 40, and 41.
Inner Kutel. Most of the Inner Kutel (13 million acres) Is a low marshy
ground with few outcrops and Is an area of poor seismic results. Even so, on
the basis of the seismic results, plus gravity survey, some broad, poorly
defined (largely untested) anomalies or leads totalling some 280,000 acres
have been mapped (unpublished). It Is estimated that after final mapping
about two-thirds of the anomalies, or 187,000 acres, may be drill able trap
area.
Fold Belt. The play area (17.5 million acres) Is traversed by a large
number of parallel northeast-trending anticlinal folds (fig. 41). Many of the
folds have been tested, but from the unpublished lead map, untested prospects

76
 (I)
Ptrangat-tnt.
A'
Bitu Pinggil ant. P«laring-ant.
B»tudlnding-»nt. Binuabaru-ant. Pulu Jupi-int. Sanga Sanga-ant. (2)
Ktnohan Stmajang Stbutu-int.
Kampung
' "-. , " B.llkp.p.n ! Baru 8h*r*-ll(i*
, : , *«» . -A HANOIL BEKAPAI DIAN
Ptmaluan
r». >.-...>:-8"t"!'"
5 ,'' \ s . 4 '..' »*\ Group
* *» ^ ',' \ * **»\\ >\ r.\3«'i\ ^ .. S- I I DIAN- I
_*__ \____»
.K . \ t < __> __*_ « i j___ ^ ^* _*

Kutil Lakii District Stmirlndt Antlcllnorlum

Stt d«tall« of mimbtrtd unit* - (tratlgriphlc column, figurt 40

from ( I) Van B»mm«len, I 949
0 10 20 30 40 50 Km
l____i____i____i____i____i (2) Lolret, Mugniot, 1982

Figure 39.--West-east composite geologic cross-section A-A , Kutei basin.

 DIAGRAMMATIC STRATIGRAPHIC SUCCESSION
SOUTHEAST KUTAI BASIN
EAST KALIMANTAN-INDONESIA

ONSHORE OFFSHORE
(WEST) (EAST) UJ UJ
< OQ cr
AGE GROUP 113
O 2 u^

PLEIST.
MAHAKAM
TO Attaka Fm. -
GROUP
RECENT

PLIOCENE

LATE
MIOCENE Sepinggan Fm
KAMPUNG
Tanjung Batu Fm.
BARU
GROUP
MIDDLE
MIOCENE
?Tt2 or
younger

MIDDLE BALIKPAPAN Mentawir Fm _ Gelingseh Fm

GROUP
MIOCENE

1 i Co Market

Pulau Balang Fm.^x^Maruat Pulau Balang Fm.

EARLY BEBULU
« « VMM* ^MWJL. -K^ i^^C______MM

MIOCENE GROUP
i:
Te5

N4
EARLY
: ' . : : Pamakian Fm
OLIGO
CENE
EXPLANATION
Sandstone I ] U^^J Lignite

Site L^---j | i ' i | Limestone

Shale L- --J Co Seismic marker

Figure 40.--Diagrammatic strati graphic chart, southeast Kutei basin. Modified

from Marks et al. (1982).

78
 \ \MANGKALIHAT SHELF'/N
KUTE! BASIN PLAYS
I" h F) MIO-PLIOCENE DELTAIC SANDS

DRAPED OR FOLDED PALEOGENE SANDS

PALEOGENE REEFS

4) MIO-PLIOCENE REEFS
DEEP-WATER, SANDS

OIL FIELDS

/ Sanga'Sanga
' ' /
'/ Handif
/
Samboja ' ';
y f y
Bekapa

D/
BARITO SHELF

PATERNOS
SHELF

3° h

1 15' \ 16' 117° 1 18°

Figure 41.--Map showing distribution of plays, Kutei basin.

79
and leads are estimated to have a total area of about 400,000 acres, of which,
when finally mapped, perhaps two-thirds, or about 270,000, acres may be
established as potential traps.
Deep Water. Seismic survey shows the existence of traps In the deeper
waters of the Makassar Straits (11.5 million acres). They appear to be
largely older drapes and more recent structure traps associated with the
faulting along the continental shelf. Some of the traps are very large, up to
50,000 acres In area. On the basis of a partial, unpublished map, the area of
prospects and leads Is estimated to make up 8 percent of the play area, but
possibly only one-half the area or 4 percent would become established
closures. No tests have been drilled.
Stratigraphy
The rocks of the Kutel basin range In age from middle Eocene to recent.
Essentially they represent a transgresslve fades until early Ol Igocene, a
quiescent, standstill fades between early 01 Igocene and early Miocene, and a
regressive fades from early Miocene to Recent. Figure 40 shows the
standstill and regressive part of the stratlgraphlc column.
The transgresslve fades Is relatively thin and very widespread,
extending beyond the Kutel basin In a regional sheet covering all of
southeastern Kalimantan (Borneo), the Makassar Straits, western Sulawesi
(Celebes), and the eastern Java Sea area. Where seen around the perimeter of
the Kutel basin, the transgresslve series Is generally coarse elastics. In
the upper Mahakam River, middle Eocene coarse sandstones grade upward Into
shales. These beds may be considered potential hydrocarbon reservoirs around
the edges of the Kutel basin. Rifting began during this generally
transgresslve period, and finer grained deep-water Paleogene sediments may be
expected In the graben and deeper baslnal areas. Local Paleogene deltas,
especially from the west and southwestern side of the Kutel basin, built up
during this early period of basin formation.
In the OlIgocene to early Miocene, most of Indonesia was In a quiescent
period with extensive formation of carbonate and shales. Carbonates were
formed on the Bar I to and Pater Noster shelves to the south and the MangkalI hat
shelf to the north, while relatively thick bathyal to outer nerltlc shales and
marls were being deposited In the major and central area of the Kutel basin
(fig. 38).
Regression began In the late Paleogene with uplift of the basin rim,
particularly on the north and west, the so-called Kuclng High (area between
the Kutel and Sarawak basins). Lower and middle Miocene deltaic and
continental deposits, with some volcanlcs, covered the western Kutel basin.
Delta systems prograded southeastwards filling the Kutel basin so that the
late Miocene shore IIne was somewhat seaward of where It Is now. PIlocene
deposition Is well beyond the present shoreline and covers the continental
shelf and beyond. Adding to the southeastern progradlng sediments were upper
Miocene sediments derived from the rising Meratus Range, filling the Paslr
subbasln (figs. 36 and 41). Offshore of the delta and along the continental
shelf edge, a line of offshore Pliocene-Pleistocene reefs formed (Play 4, fig.
41).

80
 Reservoirs
In summary, the principal reservoirs of the Kutel basin are:
1 Paleogene transgresslve elastics. I.e. basal f and perhaps locally f deltaic
sandstones. These would be more abundant, and within drilling depth, on the
basin flanks and on the Inner Kutel shelf (Play 2, fig. 41). The associated
traps would be drapes over basement highs. Although there are oil seeps, no
discovery has been made In these reservoirs. No reservoir data have been
released, but those who have access to the data estimate an average net
reservoir thickness of 170 ft for wells In this play. Good Eocene sandstone
reservoirs of unreported thickness are believed to have been encountered on
the south flank of the basin. The Tanjung field, which Is only separated from
this play area by the later-forming, Miocene Meratus Mountain structure, has
an estimated net thickness of 140 ft of Eocene sandstones. On this basis, a
140-foot average effective pay Is assumed for the play.
2. Upper OlIgocene-lower Miocene carbonates. Reefs are developed on the north
and south flanks, I.e. on the edges of the Pater Noster and Barlto shelves In
the south (a significant 1981 gas discovery was made In this play) and the
MangkalIhat shelf to the north (Play 3, fig. 41). Unpublished maps of a
similar If not equivalent carbonate fades In the shelf a I East Java Sea
Indicate that about 5 percent of that area Is In a reefa I trap. Most of the
play In the Kutel basin also appears to be In a reef a I fades, but the reefs
seem less developed than In the east Java Sea area, perhaps only half as much
or about 2.5 percent of the play area (130,000 acres). A negligible amount of
trap appears to be tested. In the absence of any data, the average thickness
of carbonate pay Is assumed to be approximately that of the Beral reefs of the
east Java Sea, or about 200 ft.
3. Miocene-Pliocene folded deltaic sandstones of the ancestral Mahakam delta.
These contain all of the petroleum production of the Kutel basin (Play 1, fig.
41). The reservoir sandstones are distributary channel fills, offshore bars,
delta plains, and delta front (fig. 42), all of which are limited In extent
and vary considerably In thickness. The average cumulative thickness of the
hydrocarbon column at Handll appears to be about 624 ft, 164 ft of oil and 460
ft of gas on the crest (Magmer and Ben, 1975). At Badak the discovery well
penetrated more than 1,000 ft of "net gas sandstone "and about 120 ft of oil
sandstone, or 1,190 ft In a 11. This averages to about 900 ft of net
sandstone, but the two fields appear to have the best and thickest reservoirs,
as they are probably situated optimally on the delta front where maximum sand
reservoir thickness occurs. An overall estimate for the average reservoir
thickness of the play area, which would Include much delta plain area, Is
around 300 ft. Oil Is recovered at various depths between 1,500 and 10,300 ft
from reservoirs where porosity ranges from 14 to 35 percent, but probably
averages around 25 percent. Water saturation Is high, ranging from 20 to 50
percent at Bekapal (Materel and others, 1976), but probably averages 35
percent.
4. MIocene-PIlocene reefs. MIocene-PIlocene reefs are developed around the
outer perimeter of the Mahakam delta and along the edge of the Makassar Strait
continental shelf (Play 4, fig. 41 and fig. 46). At least two gas discoveries
have been reported In these reefs. From unpublished maps, the area of
untested reefa I traps Is estimated to be about 100,000 acres, or 7 percent of
the play area. Observations from some well logs Indicate that these carbonate

81
 T.O.C.
'0 % WEIGHT
ORG CLAY TIDAL INTEROIST
. 40 to
COAL
ORG CLAY

DISTRIBUTARY
XS BEDDED SAND

">w_ . 40 to
TIDAL FLATS

O
cr
BARS
MARINE MUDDY SAND

££ MASSIVE CLAY p ROOELTA

Figure 42.--Section showing organic matter in a sedimentary cyclothem,

Kutei basin. After Oudin and Picard (1982).

82
reservoirs may have an effective net pay of about 110 ft. No reservoir
parameters are available.
5. Deep-water sandstones. No reservoir data are available, but It appears
that reservoirs may be relatively thin Inasmuch as the ancestral Mahakan delta
sandstones do not appear to extend Into the play area. It appears that for
some part of the Tertiary, subsidence was matched by Infill ensuring a
continued nerltlc reservoir environment, but In other areas subsidence was
more rapid and only turbldlte reservoirs may be expected. It Is estimated
that there may be an average of at least 50 ft of reservoir.
Seals
As the Kutel basin Is predominantly shale, seals should be generally
good. The 100 percent petroleum fill of the Hand 11 field Indicates that seal
may not be a problem. Possibly a seal problem exists on the edges of the
basin, where carbonates have continued through the Neogene (MankahlI at), or
where generally more permeable shallow marine sediments exist.
Source Section
The depth to the thermally mature sediments appears to average about
11,500 ft In the central part of the basin (see below). This places the oil
window largely below, but Including, the lower part of the deltaic beds. It
also Includes a good part of the Paleogene section. On the flanks of the
basin, the mature source rocks are shallower, about 9,500 ft, and Include
marine (middle shelf and open marine) beds equivalent to the Miocene deltaic
sediments. In the western or Inner Kutel basin, overmature source rock may be
very shallow, even at the surface.
Petroleum Generation and Migration
Richness of Source
The Miocene deltaic "organic" shales have an organic content of 7 to 8
percent and regular Interbedded shales about 2.5 percent. The prodelta
massive clays have an average organic content of 2.2 percent. The average
organic carbon throughout the whole deltaic column Is 3.5 percent (Oudln and
PIcard, 1982) (fig. 42). No data are available concerning the organic
richness of the Paleogene beds, but gas and oil seeps Indicate these rocks may
also be of source richness. The high paraffin content of the oil suggests a
terrestrial source, Indicating the deltaic beds are an Important part of the
source.
Depth and Volume of Mature Sediments
The average thermal gradient Is moderate, about 1.6°F/100 ft; given the
rate of subsidence In the outer Kutel basin (1,000 ft per million years), this
places the top of the mature zone, on an average, at about 11,500 ft (3,500
m). This depth Is confirmed with the few vltrlnlte reflectance data
available, which puts the variable top of the mature zone between 9,500 and
11,500 ft If the R value of .7 percent Is considered the top, or at 7,500 to
10,800 ft If the R° value of .6 percent Is considered the top of the mature
zone (Oudln and PIcard, 1982). Apparently, this surface, the top of the

83
mature zone, Is higher on structural highs. The top of the overmature zone,
on the average, appears to be about 17,000 ft In the outer Kutel basin. In
the Inner Kutel basin recent drilling has encountered overmature strata within
drilling depth, Indicating that the Inner or western part of the basin was
hotter, or more probably, uplifted from greater depths In the Neogene. On
this basis, about 100,000 ml of sediment have been thermally matured or over-
matured.
The fact that at least one trap, Hand!I, Is apparently filled to the
spill point Indicates adequate source Is present In the basin. Lesser amounts
of fill, e.g., 37 percent at Attaka and 3.8 percent at Bekapal, may be
attributed to leakage. The average fill Is estimated at 40 percent.
0!I versus Gas
The relative quantity and distribution of oil versus gas In the eastern
or outer Kutel basin appears to be controlled by the effects of overpressured
shales. The bulk of sediments within the deep outer Kutel basin are massive
shales, which are overpressured below a depth which varies but averages about
10,000 ft. When these overpressured shales become thermally mature and begin
to generate and migrate petroleum, theoretically only the smaller petroleum
molecules, C.-Cfi (I.e. gas), can pass through the overpressured shales by
molecular diffusion (Leythaeuser and others, 1982). The larger molecules pass
very slowly or not at all through the overpressured shales and remain until
continued subsidence and consequent overmaturatlon cause them to crack to
methane.
The effect of the distribution of overpressured shale In respect to
source rock on gas versus oil accumulation Is Illustrated In figure 43.
Where part of the mature zone (top of zone taken to be at the 0.6 percent
vltrlnlte reflectance level) Is above the overpressure zone (top at the
"transition zone"), the migration of larger petroleum molecules Is less
Inhibited, and oil finds Its way from the normally pressured mature source
rocks above the overpressured zone Into reservoirs. However, where the mature
zone Is below or at the same depth as the top of the overpressured shale, only
gas can migrate. As shown In figure 43, Handll field (largely an oil
producer) Is underlain by a 1,500-ft (500 M) section of normally pressured
mature source rock, while Badak field (largely a gas producer) Is underlain
largely by overpressured source rock.
It appears that most of the higher structures, that Is those having more
mature rocks above the overpressure level and therefore more oil-prone, have
been tested. For the last 7 or 8 years, exploration for gas has been actively
pursued with many deep 12,000 to 14,000-foot wildcats on the Badak-Nflo-HandiI
as well as the Bekapal-Tunu-Attaka trend. It Is estimated that gas Is the
dominant undiscovered petroleum fraction of the outer Kutel basin and that
future petroleum production will be only 20 percent or less of oil. The Inner
Kutel basin has overmature shale within drilling depth and Is therefore gas
prone, the larger oil and gas molecules having been cracked to methane. The
gas-oil mix In this region Is estimated to contain only 10 percent oil.
Migration Timing Versus Trap Formation
Assuming the average thermal gradient (of around 1.6°F/100 ft) and the
rate of subsidence of the depocenter (1,000 ft per million years) remained
approximately constant during the Tertiary In the eastern or outer Kutel
basin, generation and migration would have begun when the source rock reached

84
 N
BADAK
HANDIL KELAMBU 1 TAMBORA 1 PANYILATAN 2

CO
01

EXPLANATION

-JK3 y/fffy Transition zone (top of

overpressured shale)
0.6 Isoreflectance p::.v/!.\-J Hydrocarbon generation

Figure 43.--South-north section showing spatial relations of thermal maturity

to overpressured shale, Kutei basin. After Oudin and Picard (1982)
a depth of around 11,000 ft. Geophysical evidence suggests the basement Is at
least 30,000 ft deep, Indicating that the deepest (i.e., just above basement)
possible oil source beds reached a depth for oil generation (I.e. 11,000 ft)
some 19 million years ago In early Miocene time. This petroleum would be
trapped principally In the Paleogene drapes and reefs (Plays 2 and 3), since
the main reservoirs of the basin (I.e., the middle and upper Miocene deltaic
sandstones) were yet to be deposited and covered.
As the outer Kutel basin continued to subside, progressively younger beds
passed through the oil window whose top, presently at least, Is at a depth of
about 11,000 ft. This depth excludes much of the deltaic shales which are too
shallow to be sufficiently heated and puts the source of the oil presently
being generated largely In the lower delta and prodelta sequence. The timing
appears favorable, since oil was already migrating when young deltaic
sandstones became available In traps (I.e., folds, which formed In the late
Miocene reaching maximum effectiveness In the Pliocene-Pleistocene); however
some early Miocene-generated petroleum probably escaped. The deeper offshore
Pliocene-Pleistocene shale-enclosed reefs should also be available for
petroleum (perhaps the gas fraction).
On the flanks of the basin, subsidence Is slower and the sedimentary
cover, particularly the Neogene, thinner; some of the shelfa I area may not be
deep enough to allow a significant portion of the sedimentary section to
thermally mature, but a vast sufficiently deep area remains. The traps In the
shelfal area would likely be drapes over basement highs and, therefore,
available to entrap early petroleum as It migrates with minimum loss or
reservoir deterioration. Shelf carbonates of both the south and north flanks
developed In the Paleogene. The shelf on which the reefs were built may never
have been deep enough to allow a sufficiently thick thermally mature section,
but those reefs along the rather sharp shelf edge would be In position to
receive hydrocarbons migrating from the deeper baslnal area (fig. 38). The
western, or Inner Kutel basin, which has overmature sediments within drilling
depths, may have had oil accumulations which have since been degenerated
largely to gas and shallower accumulations eroded away by uplift on the order
of 15,000 ft.
Plays
There are a number of plays In this large complicated basin; the major
ones are: 1) Folded Neogene deltaic sandstones, 2) Paleogene drapes, 3)
Paleogene reefs along the south and north perimeters, 4) Neogene reefs along
the Miocene-Pliocene outer eastern shelf edges, and 5) deep-water sandstones
(fig. 41). Only the Miocene-Pliocene folds have produced petroleum, although
shows have been encountered In the other plays. Details of the plays are
outlined In the play analyses.
1. Neogene Delta Folds
The objective of the play Is petroleum accumulations In folded Miocene
and Pliocene deltaic sandstones. All the petroleum production of the basin Is
from these sandstones, which are trapped In two largely offshore anticlinal
trends (figs. 39 and 44) and an onshore trend, the Samarinda antlclInorlum
(fig. 39). The delta deposits which make up the play are shown In figure 45.
They Include the Mahakam ancestral delta area. The play area Is some 27,300
ml or 17.5 million acres (fig. 41).

86
 Change
of marker

Figure 44. Structural contour map showing deltaic sandstone play structure
based on regional seismic mapping, Kutei basin. After Matharel,
Klein, and Oki (1976).

87
 N
PEGAH BEKAPA TANJUNG BAYOR MARANGKAYU ATTAKA
1 2

00
00

Delta Plain
km
Delta Front 3
Inner Shelf 2
Prodelta 1
Middle to Outer Shelf 0
0 5 10 15 20 knt

Figure 45.-South-north Jtratlgraphlc section along Bekapai-Attaka trend showing delta

facies, Kutei basin. After Matharel , Klein and Oki (1976).
2. Paleogene Drape
The objective of the play Is petroleum accumulations In Paleogene sand-
tones draped over basement topographic highs, but Includes accumulation of the
already reservolred petroleum redistributed by later, renewed fault block
movement. This play Is largely In the western (Paleogene) shelfa I area, or
Inner Kutel, of the Kutel basin, I.e., the area Including and west of the
Kutel Lakes (figs. 36, 39, Play 2 of fig. 41), but also Includes the north and
particularly the south flank«(fIgs. 38 and 41). This Paleogene shelf has an
area approximately 20,240 ml or 13.0 million acres.
3. Late 01Igocene-Early Miocene Reefs
The objective of the play Is late 01Igocene to early Miocene reefs and
buildups, which occur In carbonate and shale shelf deposits to the south, the
Barlto and Pater Noster shelves, and to the north, Mangkallhat shelf (fig. 38
and play 3, fig. 41). The carbonates, equivalent to the Beral Limestone of
the East Java basin, are thicker and of a more reefal fades toward the shelf
edges, I.e., facing the Kutel basin. Because of the sparse data and the
apparent geologic similarity of the north and south boundary zones, they have
been grouped as a single play. The area of play can only be broadly estimated
at 4.2 million acres for the south margin and 1 million acres for the north
border, or 5.2 million acres In all.
4. Miocene-Pliocene Shelf Edge Reefs
The objective of this play Is probable gas accumulations In Isolated
shale-enclosed reefs extending approximately along the present outer
continental eastern shelf of the Kutel basin (Play 4, fig. 41, DIan-1 of fig.
39, and In Section B of fig. 46); also scattered shallow reefs are found In
the middle of the shelf between the delta and the continental shelf edge.
Assumlng?a strip about 12 miles wide and 175 miles long, the area of play Is
2,275 ml , or 1.45 million acres.
5. Deep Water Sandstones
The objective of this play are sandstones In the deep-water portion of
the basin, I.e., beyond the 600-ft water depth at the edge of the continental
shelf. Seismic Investigation there reveals a thick sedimentary section (fig.
46). The presence of deep sea-bottom reefs Indicates that a relatively recent
subsidence has depressed nerltlc sediments to depths of over 7,500 ft.
Eighteen thousand square miles, or 11.5 million acres, are In the deep water,
I.e., deeper than 1,000 m In the Makassar Straits.
Tarakan Basin
Location and Size
The Tarakan basin Is largely offshore (about 75 percent) on the west side
of the Celebes Sea (figs. 1 and 47). Its onshore portion Is on the northern
east coast of Kalimantan (Borneo). It Is bounded on the north by the Semporna
Peninsula, an extension of the Sulu Archipelago, at the Indonesian-Ma I aysian
boundary. Its southern flank Is the Mangkallhat Peninsula, which separates It
from the Kutel basin to the south. It has an area about 16,250 ml and an
approximate sedimentary volume of 30,000 ml .

89
 c'

Figure 46.--East-west geologic sections, transverse to the western margin of the Makassar
Strait, Kutei basin. From Katili (1977).
 120°

Figure 47.--Structure contour map of Tarakan basin showing depth to basement.

After Hamilton (1978).

91
Exploration and Production History
ON was discovered on Tarakan Island In 1906. Drilling from 1922 to 1930
on Bunyu Island resulted In the establishment of the Bunyu oil field (fig.
48). The original reserves of Tarakan Island are approximately 200 million
barrels and of Bunyu Island about 100 million barrels. Serious exploration
outside these Islands did not begin until 1969. Since then, 12 offshore wells
have been drilled, only one of which has been termed a discovery, the Serban-
1, a gas welI (fig. 48).
On the Kalimantan mainland, Sembakung oil field was discovered (fig. 48)
and put on production In 1977. This was followed by Bangkudulus, Sesayap, and
the satellite Sembakung fields during the early eighties. At present, only
Sembakung appears to be on production, producing 5,647 BOPD during 1982, after
having reached 7,328 BOPD In 1978. In 1984 all the mainland production was
relinquished to the government (Pertamlna) by Arco, the operator.Estimated
original reserves of Tarakan basin as of 1979 are 469 million barrels of oil
(EIA, 1984) plus 0.47 Tcf of gas (HarladI, 1980, Patmosuklsmo, 1980).
Structure
General Tectonics
The Tarakan basin appears to be largely a shelf or foreland (fig. 47). In
respect to the Semporna-SuIu Archipelago volcanic arc, It appears to be an
Inner-arc (back-arc) basin. There may also be effects of the Paleogene
spreading forces, which opened the Kutel basin to the south. The axis of the
depocenter trends north-northwest as do two of Its major structural trends.
I.e., Tarakan and Bunyu Islands. This basin Is underlain by accreted melange
crust, as Is the Kutel basin to the south, and Is relatively warm, having an
average thermal gradient of 2.35°F/100 ft. The basin was subjected to
compression In middle to late Miocene, possibly related to northward
subductlon beneath the then south-facing Sulu arc. Western uplift at the
beginning of the Pliocene resulted In an eastward-dipping unconformity surface
(fig. 49). After subsidence, mild compression resulted In Pliocene-
Pleistocene folds, e.g., Tarakan and Bunyu Islands, which have been mapped on
shallow horizons, and many of which have been tested. Owing to an apparent
difficulty In obtaining reliable deep seismic data, the structure below the
Pliocene unconformity, particularly In the offshore areas. Is obscure. There
are some Indications of deep shale plugs and carbonate reefs on seismic
sections.
Structural Traps
Structural traps are divided Into two groups, those below the Pliocene
unconformity and those above It.
1) Structures below the unconformity are analogous to the Miocene-
Pliocene folds of the Kutel basin (play area of 17.5 million acres), which has
an estimated untested trap area of 270,000 acres. Applying this analogy to
the smaller (8 million acres) Tarakan basin play, the estimated untested trap
area Is 123,000 acres.
2) The shallow, simple anticlinal traps affecting strata above the
Pliocene unconformity have been mapped onshore and offshore, and all closures.

92
 I 17°. I I 8°.
J I

MALAYSIA

4° - TIDUNG DELTAS
(TABUL AND MELIAT FMS)
0-
%S«mbakung

BUNYU ISLAND

Bunyu FUld

TARAKAN ISLAND
Tarakan Fi«l4«

PLIO-PLIOCENE CELEBES
DELTAS /
CTARAKAN-BUNYU FMS)
3°J

Kerang
besar

TARAKAN BASIN
FIELDS AND WILDCATS-FACIES OUTLINE

Figure 48. Index map of Tarakan basin showing facies outlines and significant
fields and wildcats. Modified from Samuel (1980).

93
 CELEBES BASIN

TARAKAN BASIN GEOLOGY

Rantau Pandjang
| S. Barau
N.E. BORNEO S.
9 8 6543

EXPLANATION
SAUMBATU
Alluvium |". -\
TANDJUNG
Tarakan and Bunyu Fms
Anyam and Mondaf Fms
Tabul F<xmatkxi«
Melait Fm r=\ 6
Na'mtupu Fm 7
Pateogene ('.'.1 8
Pretertian/ £539
Young volcanics 10
Structure axis "*-^» \ 1
PBocene " - . 12
uniconformrly

0 10 20 30 40 50 KILOMETERS
i " L-1 '

Figure 49. Geologic map of the Tarakan basin showing in particular the trace of the
Pliocene unconformity in map and section view. From Beemelen (1949).

94
at this level, of any appreciable size apparently have been drilled. Only
wildcats on Tarakan and Bunyu Island have found oil. These two Islands are
northwest-trending anticlinal highs, the most prominent In the basin; a number
of separate fields or accumulations have been created by faulting
perpendicular to the fold axes. Little significant untested trap area remains
at this level, possibly 20,000 acres.
Stratigraphy
The earliest sedimentation was In the Eocene when nerltlc to terrestrial
coarser elastics thousands of meters thick were deposited (Bemmelen, 1949).
This was followed by deposition of marls and limestone, which extended through
the OlIgocene and Into the early and middle Miocene. 01Igocene carbonates are
largely platform carbonates widely distributed over the basin. Miocene
carbonates and shales, variously designated either the Nafntupo, Latlh, or
"Calcareous Series" Formations (fig. 50) In the north and the Tabalar
Formation of platform carbonate In the Maura Shelf (fig. 48), extend over the
basin. This marine sequence Is overlain by a number of overlapping and
InterfIngerIng Miocene deltas, the Berau, Melalt, and Tabul Formations. Many
formation names further obscure complicated stratigraphy (see Achmad and
Samuel, 1984.) These deltaic formations were cut In the Pliocene by a
profound unconformity, which In turn was followed by further Pliocene-
Pleistocene deltas, locally the Tarakan and Bunyu Formations.
Reservoirs
There are three principal zones of reservoirs: 1) Reefs and carbonate
banks In the 01Igocene to Miocene marl and carbonate series (the Nafntupo,
Latlh, Domarlng, "Calcareous Series" and Tabalar Formations); 2) Miocene
deltaic sandstones of the Berau, Melalt, and Tabul Formations; and 3)
Pliocene-Pleistocene deltaic sandstones (Tarakan and Bunyu Formations).
1. Reefs and Carbonate Banks
Reefs have been a drilling objective onshore In the Mangkallhat Peninsula
and adjoining carbonate platform offshore. One offshore wildcat, Karangbesar-
1 Just north of the Mangkalfhat Peninsula, penetrated the Tabalar Limestone
(lower Miocene) In a near-reef fades (fig. 48). One of the most northerly
offshore wildcats, OB-A2, bottomed In open marine fades consisting of a reef
and a reef-bank (fig. 48). Reefs are reportedly Indicated In some regional
seismic sections, though the data are poor. The size and distribution of the
reefs are unknown; they appear to be more developed In the south adjoining the
Mangkallhat Peninsula where there appears to be a carbonate platform (Maura
Shelf, fig. 48). Carbonate banks and calcarenlte beds are also potential
reservoirs. By analogy to the geologically similar carbonate shelf reef play
of the East Java basin, one would expect carbonate reef and bank traps to make
up 5 percent of the reef a I fades, which would cover about 30 percent of the
play area, leaving an untested trap area of 156,000 acres. These reefs are
analogous to other reef plays such as the OlIgocene-MIocene reef play of the
Kutel basin and the equivalent shelf-reef play of the East Java basin, which
have an estimated average pay thickness of about 200 ft. However, the more
baslnal 01Igocene-MIocene section of the Tarakan basin appears to be largely
argillaceous and, therefore. It probably contains less porous carbonates. The
Tarakan reefs are estimated to have only one-half the average pay of the
analogous plays, or 100 ft.

95
 "N" FLORAL
LETTER ONSHORE AREA TARAKAN ISLAND BUNYU ISLAND
AGES
STAGE ZONES ZONES (ARCO ) (TESOROJ (PERTAM1NAJ
N 23 HC H C
PLEISTOCENE Phylloclidui
lUiJlJiillLLI
BUN YU ' ~ .~ B UMYU ~ ~
N 2? BEDS -~
N ?) LATE Pcoocarpus ? _ ... .. . _ * -'- _~ - ' " -D-
imbricilus o «
o «
PllOCt
NE <* - JARAKAN _ -
N ?0 MIDDLE ~ TARAKAN ~
Th Stf nochiena <o BED S -
EARLY
~' f /M. ' '
N 19 Uunfohi
x-"^ #
Q
^~ N 1 8
I st Limestone ^-», M-tO coal marker
*
N 17 c
LAT£
T9 u; s CLAY SERIES - *
x-""1 N 16 1 "2 '"_ TABUL _.'!'
T-T ^.^ £j- -0-
N IS
Z « E 2 nd Limestone T£ o
ij tO ... '
J S
N U *O !v -'t
1 o 2
_~_ f ° V'- _"_~.
v
1 UJ
^ ^
rfa.3 N 13 C £ u: 1 r/ Clay stone MELIAT FM.
z (J
K ^==^x - -
Tf N 12 MIDDLE -
o -7 -
N 11 o
cr> _ . _ _ . _ t t
N »
.. _ fi/V
3. Tf i Clayitone ^ BT
Tf.1 <r
N 9 C "i we Hi wtf//s
Flor&chuetzia
^ ""
N »

N 7 It vi poll |s
T« T« 5 N 6 EARLY

N 5

N 4

Figure 50.--Generalized Neogene stratigraphic chart, Tarakan basin.

From Samuel (1980).
2. Miocene Deltaic Sandstones
No data are available concerning pay thickness of Miocene deltaic
sandstones. The gross producing Interval of the only presently producing
field, Sembakung, Is reportedly 1,200 ft. Discovery wildcat Bangkudulls had a
test Interval of 300 ft In 4 zones (perhaps 150 ft net?); discovery wildcat
Sembakung East, 700 ft; and offshore discovery wildcat Serban, only 40 ft.
The analogous play In the adjoining basin, Kutel, has an average pay thickness
of 275 ft. From the relatively low production so far obtained, It Is surmised
that, among other factors, the reservoirs are less developed than those of the
Kutel basin, being perhaps about one-half as thick, or about 140 ft. Porosity
at the Sembakung field ranges from 20 to 26 percent.
3. PIlo-Plelstocene Deltaic Sandstones
The Pliocene-Pleistocene (Tarakan and Bunyu) Formations are predominantly
delta sandstone, and effective pay thickness Is not a limiting factor; the
principal Tarakan field, Pamuslan, reportedly has up to 700 ft of net
sandstone In 12 pays. For evaluation purposes, 300 ft Is assumed.
Porosity In these sandstones appears good, I.e., 20 to 38 percent. The
principal limiting factor Is that water saturation Is extemely high In
Tarakan, about 95 percent; the oil recovery factor Is about 50 percent. These
unusual reservoir conditions are assumed to prevail throughout the play. Even
allowing for some Improvement In well completions, the oil recovery would be
very low, or about 100 barrels per acre-foot.
Seals
Seals In the Miocene and later deltaic sandstones are only fair and It Is
probable that hydrocarbons have escaped at the time of the base-Pliocene
unconformity.
Source Section
The source rock appears to be well below the Pliocene unconformity and
largely In the OlIgocene to lower Miocene marls and carbonates (see below).
Petroleum Generation and Migration
Richness of Source
No organic richness data are available from the thermally mature
01Igocene to lower Miocene marl and carbonate formations, but the middle
Miocene Me I a It Formation has 2 percent organic carbon content, the same as the
Kutel basin pro-delta beds (Samuel, 1980). The Tabu I Formation, a proximal
delta formation, averages 10 percent organic carbon content, largely
reflecting coal presence. The Pliocene-Pleistocene Tarakan and Bunyu
Formations are the richest of all In organic carbon (23 percent) again
reflecting high coal content; however, these younger formations are too
shallow to generate hydrocarbons.

97
 Depth and Volume of Mature Sediments
Depth to the top of the thermally mature sediments, as defined by
vltrlnlte reflectance of .7 percent, appears to vary, as anomalously shallow
values are reported. Sembakung-1 contained no mature rocks down to 10,000 ft,
and the strata fn Mengatal-1 on Tarakan Island were deemed to be approaching
maturity at 9,000 ft (Samuel, 1980). Data from a second well on Tarakan
Island, Barat-1, however, placed the top of the mature rock at 7,500 ft, and
determinations at Bunyu suggest 7,000 ft (Samuel, 1980). The average thermal
gradient Is relatively high (about 2.35°F/100 ft). Because the basin Is
tectonlcally and thermally similar to the Kutel basin where the top of the
mature zone Is estimated at an average depth of 10,000 ft, the average depth
of thermally mature rock In the Tarakan basin Is assumed also to be about
10,000 ft. On the basis of this similarity to the Kutel basin, the top of the
overmature rock (gas-window) Is a± 17,000 ft. The volume of mature and
overmature rock Is about 5,000 ml .
011 versus Gas
Both gas and oil are found In Tarakan basin. Oil has been selectively
produced but gas has not. It Is believed, however, that the best potential
lies with gas, especially In the offshore areas. Below the middle Miocene to
recent deltaic formations, and largely within the thermally mature zone (below
10,000 ft), Is a thick marine section of shales, marls, and carbonate.
Although evidence of overpressurfng Is barely mentioned In the literature, It
Is believed that this thick, predominantly argillaceous sequence Is
overpressured. As In the better documented case of the Kutel basin, this
overpressured sequence should produce only the lighter hydrocarbons, C,-C6 ;
the larger oil molecules remaining locked In the shales and marls until
further subsidence and maturation degrades them to methane. It Is estimated
that the central, deeper part of the basin (the reefa I play) Is largely gas-
prone and only about 20 percent of the hydrocarbon may be oil. In the onshore
and continental shelf area, deltaic sandstones would provide conduits to bleed
off overpressure and allow primary oil migration, so that the petroleum mix Is
largely oil, I.e., an estimated 60 to 70 percent.
Migration Timing versus Trap Formation
It Is estimated that the depth of the basin averages about 17,000 ft In
Its central part. Assuming the hydrocarbon generation began when the basin
subsided to a depth of 10,000 ft (the estimated present depth to the thermally
mature zone), migration would commence about middle Miocene, prior to late
Miocene folding and to the base of Pliocene unconformity. Under these
circumstances, the timing of migration In regard to pre-unconformlty traps,
I.e., middle and upper Miocene folds or reefs, would be optimum. The post-
unconformity closures are late; much oil must have escaped from the system
during the base-Pliocene erosion. The oil of the Pliocene-Pleistocene folds
of the Tarakan and Bunyu Islands apparently represents a small surviving
remnant of a larger hydrocarbon migration.
Plays
The petroleum prospects of the Tarakan basin are divided Into three
principal plays: 1) Carbonate reefs and banks In Tertiary shale and carbonate

98
sequence, 2) Late Miocene folds (pre-base Pliocene unconformity), and 3)
Pliocene-Pleistocene folds (post base-Pliocene unconformity).
1. Carbonate Reefs and Banks
The objective of the play Is In reefs or banks (and possibly some
sandstones) In the largely shale and carbonate sequences of early Miocene age
(fig. 50). This play underlies the whole basin at varying depths below the
middle Miocene to recent deltas that encroach and overlap It from the west and
north. The play extends onto the MangkalIhat Peninsula and shelf, which
separates the Tarakan from the Kutel basin and Is probably more prospective In
the southern basin (the so-called Maura Shelf area) (fig. 48); but, In
general, the play area coincides with that of the entire basin having an area
of 10.4 ml 11 Ion acres.
2. Late Miocene Folds
Petroleum accumulations, primarily In Miocene deltaic sandstones and
probably calcarenltes, are entrapped In late Miocene folds. Onshore, the
folds of this play are detectable at relatively shallow depths, but offshore,
they are obscured by an overlying east-dipping regional unconformity. The
play underlies most of the basin, possibly excluding part of the Maura-
MangkalIhat platform and Including the Tldung, Berau, and Tarakan deltas (fig.
48). The play area Is estimated to Include 75 percent of the total basin, or
approximately 7.8 million acres.
3. Pliocene-Pleistocene Folds
Shallow petroleum accumulations occur In relatively gentle folds of
Pliocene-Pleistocene deltaic sandstones overlying a regional, profound
unconformity. The area of the play Is largely the offshore portion of the
Tarakan basin, approximately two-thirds of the entire basin, or about 6.9
thousand acres.
West Natuna Basin
Location and Size
The West Natuna basin Is on the continental shelf of the westernmost
South China Sea (figs. 1 and 51). It adjoins on the west the larger and
deeper Malay basin, which trends southeastward from the Gulf of Thailand. The
boundaries between these two similar, but structurally distinct, basins Is
coincidentally approximately the Indonesian-Ma I aysian boundary. The West
Natuna basin Is further bounded on the east by the Natuna Arch and on the
south by the Sunda Shelf. The northern boundary arbitrarily Is taken at the
VIet Nam-indoneslan boundary (disputed). It has an,area of approximately
34,000 ml and a sedimentary fill of some 45,000 ml .
Exploration and Production History
Exploration of the region started In 1968 and has been generally active
ever since.
Although petroleum exploration has been very rewarding In the similar
adjoining Malay basin, exploration In the Indonesian waters has been only
moderately successful to date. After two noncommercial "discoveries," A1-1X
(gas) and Terubuk 2 (oil) on the Malayslan boundary, the first substantive
success was the Udang oil discovery of 1974 on an OlIgocene drape closure on

99
 100 200 300 400 KM.
h '
200 Ml.
KHORAT-
CONSON
PLATFORM
AST NATUNA/
SARAWAK BASIN

o
o

NATUNA
ISLAND

Figure 5l.--lsopach map of West and East Natuna basins, southeast Asia. From Eyles and May (1984).
the southern edge of the basin with estimated reserves of some 50 million
barrels of oil (fig. 52). In 1978, wildcat KG-IX, followed by KH-1X In 1980,
discovered oil In drag fold structures In the central part of the basin (KH-IX
went on-stream In 1986, estimated reserves are 30 MMBO). A second oil and gas
discovery In a central fold was discovered In 1982, Anoa-1 (granted
commercI a 11ty In 1983, estimated reserves are 30 MMBO), and seven additional
gas and oil discoveries were made through 1984. The basin oil reserves are
estimated to be 402 million barrels (EIA, 1984). Gas reserves are unknown.
As of the end of 1984, some 65 wildcats were drilled of which 11 have
been announced as discoveries giving a wildcat success rate of 17 percent.
The significant exploration Is estimated to be about 40 percent complete.
Structure
Genera I TectonIcs
The West Natuna basin Is a northeast-trending fault-controlled basin
(figs. 51, 53, and 54). It Is on the northwestern edge of the granite-
Intruded craton area of the Sunda Continental Block, a border of accreted
Mesozolc melange extending along the east side of the basin, I.e., the Natuna
arch (fig. 51). This arch, separating the West and East Natuna basins,
appears to be an old feature, perhaps related to the Mesozolc and early
Tertiary north-striking subduct Ion zones, traces of which are just west and
just east of Natuna Island, respectively.
The basin began to take Its present form In early OlIgocene when
continental crust attenuation (perhaps associated with the beginning of
seafloor spreading of the South China Sea to the northeast) caused subsidence
and tenslonal faulting with the formation of northeast-trending half grabens
(fig. 53). This structure provides fault and drape closures as well as deep,
silled grabens for preserving organic matter.
In the early Miocene, northeast-trending faults, some along the old
01Igocene normal-fault zones of weakness, became active (fig. 54). These
faults appear to be primarily wrench faults of largely dextral movement.
Abrupt and random changes In thickness across faults, anticlines becoming
syncllnes (or half-grabens) at greater depth, and apparent throw reversals
along strike and with depth support this Interpretation (figs. 55 and 57-2).
Drag folds associated with these faults are Important petroleum closures,
particularly In the Malay basin to the west.
By late Miocene, tectonic activity had diminished, and the area was
subject to peneplanatlon followed by subsidence. Subsequent gentle warping
followed along previous structural trends (fig. 55).
Structural Traps
The petroleum-containing closures appear to be of two types:
1) Drag folds associated with Miocene wrenches In the central parts of
the basin. Figure 56 shows an example of such a Miocene drag fold; cross
sections are shown In figure 57. Most of the large oil fields of the Malay
basin to the west appear to be on similar drag structures. An examination of
an unpublished map of a limited area of the northwestern part of the area
Indicates that 5 percent of the play area Is under drag-fold closure. This Is
supported by analogy to other basins; where drag folds associated with
wrenching are the dominant structural style (Central Sumatra and Los Angeles),

101
O
ro

4,356'Totaldepth in feet.

Figure 52.--Well location map, West Natune basin. From Petroconsultants (1982).
 100°E 105°E 110°E 115°E
15°N

10°N

o
CO

5°N

0°N

Figure 53.--Map showing early tectonic elements, West and East Natuaa basins. Modified from
Wirojudo and Wongsosantiko (1983).
 INDOCHINA /
1 + + + + + + + + + + +/4.

CONTINENTAL
CRUST

NORMAL FAULT
REVERSE FAULT

.'SUNDA SHELF \\\\\+

Figure 54.--Map showing early-middle Miocene tectonic elements, West and East Natuna basins. From Wirojudo and
Wongsosantiko (1983).
Figjre 55.--Seismic sections (A, B, and C) showing structural styles in West Natuna basin (A) and East Natuna basin
(B and C). From Wirojudo and Wongsosantiko (1983).
Figure 56.--Seismic structure map showing depth of top Oligocene strata on a typical drag fold, West Natuna.
From Wirojudo and Wongsosantiko (1983).
NW SE
PARANG 9 10 20

5OOO'- -5OOO

IO.OOO IO.OOO

CUMICUMI-1 IKAN MAS-1 GABUS 4-1 LUMBALUMBA-1

PROJECTED PROJECTED PROJECTED PROJECTED
_1 J__________*____________\

5000- 5000

IOfOOO -IO.OOO

15.0OO .OOO

BOUNDARY HIGH UDANG-2 0 IO 2O

HIU PROJECTED
JL 4

5000- -5000

IO.OOO- -IO.OOO

I57OOO -I5.0OO

Figure 57.--NW-SE geologic cross-sections, West Natuna basin. After White and Wing
(1978) and Eubank and Makki (1981).

107
the trap area would appear to be about 5.5 percent of the play area. It Is
estimated, therefore, that dragfold traps make up approximately 5 percent of
this play area (7 million acres, see Plays) of which an estimated 40 percent
has been tested.
2) Drapes over 01Igocene fault blocks are prominent on the basin
perimeter. A map of the Udang field Is shown In figure 58; a cross section at
Udang-2 Is shown on figure 57. The Udang basin-edge trend extends westward
Into Malaysia where It Is also petroleum bearing. A measurement of drape
closures In an unpublished map of a limited area In the west-central part of
the basin Indicates that 7 percent of the area was under this type of closure.
This Is somewhat analogous to the drape closures of East Java Sea where the
closure area comes out to be about 5 percent of the total play area (15
million acres, see Plays). On this basis, over one million acres of drape
closure Is estimated In the play, of which an estimated 40 percent has been
tested.
Stratigraphy
The sedimentary fill of the West Natuna basin Is made up of Tertiary
strata summarized In the stratigraphic column after Armltage and VIottI, 1977
(fig. 59).
The early clastic fill, the "undIfferentfated complex" or the Terubuk
Formation, Is overlain by the 01Igocene Keras and Gabus Formations, which
occupy the grabens and half-grabens caused by the early 01Igocene rifting.
These sediments are essentially continental and deltaic elastics and are up to
15,000 ft thick (WIroJudo and Wonsosentlko, 1983).
Overlying the OlIgocene section are the Miocene Barat and Arang
Formations. They consist of sandstone and shale with some coal and are of
deltaic or paralIc origin. These strata are relatively thin, averaging 3,000
to 4,000 ft In thickness.
Overlying by profound unconformity are upper Miocene through Pleistocene
open-marine sandstones and shales, the Muda Formation. They are usually less
than 4,000 ft thick but range up to 10,000 ft In the western part of the basin
adjoining the Malaya basin.
Reservoirs
There appear to be two principal reservoir zones In the Tertiary section:
1. The sandstones of the OlIgocene Gabus Formation appear In drape structures
(e.g. Udang and satellite fields, which are to date the principal petroleum
producers of the basin, and In some drag folds, e.g. the KH and KG fields).
The average net pay of the 01Igocene sandstones In the Udang field Is
reportedly 86 ft and In the KH field, 40 to 190 ft. In the absence of other
data, 86 ft Is taken to be the average pay of the drape play.
2. The Miocene Arang Formation sandstones are Involved In the drag folds of
the central part of the basin. They are the main oil and gas producers of the
prolific Malaya basin fields to the west. Three hundred and seventy-five ft
of pay (315 ft gas and 60 ft oil) were tested at Anoa-1. However, Anoa-1 Is
located on the extreme west side of the play area where the Arang Formation Is
of maximum thickness. The Arang Formation thins eastward and Is thin or
missing on the higher amplitude folds. For the drag-fold play of the central

108
O !

15KM

Figure 58.--Structure map showing depth to top of Oliogocene strata, Udang Field, West Natuna basin.
From Wirojudo and Wongsosantiko (1983). Contour interval not indicated; dashed contour
probably oil-water contact. '
 PLANK- PAtY-
MALAYSIA INDONESIA TONIC NOLOG AGE
GROUP FORMATION AFTER PUPILLI. 1973 ZONATION ZONATION
N 23*
RECENT
N 22* PLEISTOCENE

PILONG FM N 21* t-u

LATE 2
u_
N 20 t_)
O

N 19* EARLY
0^

/
MUOA FM
N 18
VTf^'
< ~
-rffff '' N 17

N 16
rvj

il
LATE

, 1 <-> 0
CO
N 15 cc cc
O '-'-'

i.jj i N 14 ^ s
BEKOK FM. N 13* j
TAPIS FM 2
N 12* MIDDLE
PULAI FM
ZD N 11 t_)
CD
2
SELIGI FM N 10 FLLEVIO*RSCHPUEOLITZIA
<! ARANG FM
C3
s
O N. 9
2
N 8
cr
i LEDANG FM N 7

N 6 EARLY

8ARAT FM N 5

N 4

TELUKBUTUN FM
<
2
Z3 TFLROIRLSOCHBUAETZAI " u»_l
z.
l GA8US FM
<t CLJ
2 SEMALA FM (_>
CD
e:

SAMBAS FM KERAS SH MBR CD

TERUBUK FM.
UNOIFFERENT1ATED COMPLEX"
,~*_x ^» " _^ x-x-

" BASEMENT " CRET OF^ OLDER

'BIOUNITS PRESENT IN AQ/PULAI AREA

Figure 59.--Stratigraphic chart, West Natuna basin. From Armitage and Viotti
(1977).

no
basin where an unknown amount of the Miocene sandstones have been eroded, the
01Igocene and Miocene sandstones have been lumped and are assumed together to
have a combined thickness of 200 ft.
Seals
The section Is a sequence of sandstone alternating with relatively thick
shales. The shales can be considered fairly good seals. Leakage may have
occurred In late Miocene time when the area was extensively eroded and faults
to the surface prevailed. There has been essentially no faulting since late
Miocene, and only small amounts of leakage probably occurred after that time.
Source Section
The 01Igocene graben-flll of up to 15,000 ft of coastal-fluvial plain and
deltaic sediments are the source rock of the basin (see Petroleum Generation
and Migration).
Petroleum Generation and Migration
Richness of Source
According to WIrajudo and Wongsosantlko (1983), geochemlcal data suggest
that the 01Igocene graben-flll continental elastics are "good" source rock for
gas and "fair" to "good" source rock for oil, at least locally. Cossey and
others (1982) report the late 01Igocene (Barat Formation) has organic carbon
In the range of 0.5 to 2.0 percent. Pollock and others (1984) Indicate that
claystones of the Barat and underlying Upper Gabus Formations are the likely
source of oil, while the overlying section Is generally gas prone.
The richness of the source Is confirmed by the high percentage of
petroleum fill. The KH field appears to be 55 percent filled and the Udang
field 44 percent.
Depth and Volume of Mature Sediments
The average thermal gradient Is about 2.2°F/100 ft and average rate of
subsidence appears to average about 330 ft per million years. This puts the
average depth to the top of the mature zone (taken where R = 0.7 percent) at
8,000 ft (and overmature zone at 15,500 ft). This checks with the vltrlnlte
measurements at the KH field (Pollock and others, 1984). The 8,000-ft depth
Is about at the top of the OlIgocene. Mature Miocene source rock, however,
probably exists along the Ma I ays I an border where the rate of subsidence has
been greater. The volume of source rock Is estimated to be 20,000 ml . The
relative shallowness, of the West Natuna basin, and therefore less thermally
mature source rock, may be part of the explanation of why less hydrocarbon has
been found In the the West Natuna basin versus the adjoining much deeper Malay
basin.

Ill
 OiI versus Gas
Gas has been found In the West Natuna basin and In large quantities In
the adjoining deeper Malay basin, but no gas production has yet been developed
and no reserve figures are available. It would appear, however, that gas
takes up most of the trap volume. The Anoa-1 test found 315 ft of gas and 60
ft of of I* It Is estimated that oil Is about 30 percent of the petroleum mix
In the Miocene drag-fold play. For the OIIgocene drape play, 50 percent is
estimated for oil; the Udang field Is about two-thirds oil, but Indications
for future fields appear less.
Migration Timing versus Trap Formation
Assuming that the thermal gradient and subsidence rates were
approximately constant during the Tertiary, hydrocarbon generation and
migration would begin when the source sediments had subsided to the depth of
8,000 ft. This would have happened In the late 01Igocene when a considerable
portion of the OIfgocene graben fill, which Is up to 15,000 ft thick, had been
deposited. However maximum flood of oil generation and migration probably did
not commence until the Barat shales reached these depths In the late Miocene.
Drape closures would have first formed In the OIfgocene somewhat earlier
than hydrocarbon flood migration, and there may have been some time for
reservoir deterioration.
The Miocene drag fold and fault traps associated with Miocene wrenching
on the other hand would form considerably after migration began and,
therefore, miss some amount of migrating petroleum. Migration, however, would
have been going on while the traps were forming, thus preserving the
reservoirs to some extent from deterioration.
Limiting Factors
The limiting factors In this basin In comparison to the adjoining
prolific Malay basin are Its relative shallowness, allowing less volume of
source rock, and relative thinness and absence by erosion of some middle
Miocene (Arang Formation) reservoir section (the principal reservoir section
of the prolific Malaya basin).
Plays
1. Drapes
Potential petroleum accumulations are In 01Igocene (and to a less extent,
Miocene) sandstones draped over OIfgocene (and older) fault blocks. The area
of play appears limited to those areas around the perimeter of the basin where
the thin, less plastic section Inhibits the formation of high-amplitude, large
Miocene drag folds (which would tend to redistribute or destroy petroleum
earlier accumulated In drape features). It Is also In these peripheral areas
where OIfgocene sandstones are more prevalent. On this very general basis,
the play Is believed to be of highest potential In the zone around the basin
where the section Is less than approximately 10,000 ft thick fig. 51, giving
an area of about 23,000 ml or 15 million acres.
2. Miocene drag closure
Potential petroleum accumulations occur In Miocene drag-fold closures
presumably associated with wrench faults of unknown distribution Involving

112
01Igocene and Miocene reservoirs (although Miocene strata are largely missing
from the crestal areas of the larger folds). The area of the play Is
restricted to the deeper, central parts of the basin where there Is a thick
enough plastic section ±o permit major folding. The play area Is very
approximately 11,000 ml or 7 million acres.
East Natuna Basin
Location and Size
The East Natuna basin Is on the continental shelf of the southeastern
South China Sea and Is the Indonesian portion of the much larger Sarawak
basin, which occupies a large portion of the northern offshore of Borneo
(figs. 1, 51 and 60). As defined here, the boundary between the so-called
East Natuna basin of Indonesia and the Sarawak basin of Malaysia Is taken to
be at the International boundary. The northern boundary of the East Natuna
basin Is likewise arbitrarily placed at the IndonesIa-VIet Nam boundary (which
Is In dispute). The south and west edges of the basin comprise the shallow
pre-Tertlary basement of the Sunda Shelf and Its north-plunging extension, the
Natuna Arch. It has an,area some 27,000 ml and a sedimentary fill of
approximately 57,000 ml .
Exploration and Production History
The basin has been under fairly continuous, active exploration since the
first wildcat was drilled In 1970. As of the end of 1982, 34 wildcats have
been drilled resulting In two gas discoveries, AL-IX and AP-IX (fig. 60), a
noncommercial oil discovery, Bursa-1 (12 MMBO?), and three noncommercial gas
discoveries, Soklang-1, AV-IX, and Bantenal-1.
Depending on how the present noncommercial discoveries are eventually
rated, a discovery rate of as much as 15 percent may be considered.
Significant exploration Is estimated at 40 percent complete, 20 percent for
one play (lower Miocene sandstones) and 50 percent for the other (upper
Miocene carbonates).
The L-IX gas discovery Is enormous, with hydrocarbon gas reserves
estimated to be In the order of 60 Tcf. Along with the hydrocarbon gas Is
about 200 Tcf of carbon dioxide. The disposal problem of this huge volume of
carbon dioxide has been a problem affecting the production feasibility of the
L-IX accumulation as well as other potential accumulations In the southern
half of this province.
The large size of the L-IX trap appears to be anomalous to the area; no
other mapped closure area approaches It In size, and It Is evident that
remaining untested traps are much smaller.
An oil discovery, Dua-2X, In Vietnam only 20 ml north of the Indonesia-
Vietnam (disputed) boundary and within the same geologic province, tested
2,230 BOD and 17,600 MCFGD In 1974 (fig. 60). Two nearby Vietnam gas
discoveries were made In 1980.
Structure
General Tectonics
The East Natuna basin Is largely underlain by Mesozolc and Tertiary
melange accreted with the South China Sea oceanic crust subducted westward

113
 OUA-2X
108°£ 110°£
THAILAND 2
INDONESIA HMER R.
EAST NATUNA BASIN

Orupa IX 4.124'
INDEX MAP

Cipls 81 10.742'
AC-IX 9.809*
Bursa 1-X 12.548'
Cyprea IX 6.816'
% N
fiusa 1 11.238' Macan 1 11.090/

Komodo 11.838'
CARBONATE PLATFORM
AY-IX 12.296;
l-lx to 5X
AT-IX 5'864' i. . 2
5 J_I 1. 15.102'
Bantenal 1. 2. 14.200
. 10.601'
1. 2.470"
2. 3.376
9.512' 10.44

Panda 1 8.056J

AH-IX. 2X^2
1. 3.715-
2. 8.791'

Banaeng 1 10,010'
CLASTICS
NE Paus 1. 2 '^/A. I
' 2 ' 580' Antom 1 7.207-
2. 5.083'

'S Paus 1 Terj

-A- , 2. 6.975'
Tfianail 7.806

Oil well SE Tuna 8.498'

Suspended well
Gas shows
Location or drilling Sokangl 7.740

Gas we'll

Abandoned well
200 Isobath in meters
Concession boundary Subi-Besar Island
litleni.ilioiidl buiiiuljry

4.061* Total depth

Figure 60.--Index map of East Natuna basin showing facies, and wildcats. Modified
from Petroconsultants (1983).

114
beneath the Sunda continental block. An early Eocene (fore-arc?) ridge, the
Paus-Ranal Ridge (fig. 53) trending northwestward across the southern part of
the province, appears to be a remnant of that system.
Back-arc, northwest-southeast spreading and opening of the South China
Sea began In the 01Igocene and continued until middle Miocene. The
continental crust underlying a substantial part of the South China Sea,
Including the Sarawak basin and at least the eastern East Natuna basin, became
attenuated. The crustal attenuation, combined with the southward opening
movement, resulted In a general foundering or subsidence accompanied by
numerous tenslonal faults and dextral wrench movement In the vicinity of East
Natuna basin (fig. 54). Considerably more parallel, dextral wrench movement,
not shown In figure 54, Is presumed to be Just east of the province In
Malaysia. Maximum subsidence was In late Miocene after the spreading of the
South China Sea had ceased.
Two principal trends developed largely during the early 01Igocene and
early to middle Miocene periods: (1) a northeast-southwest trend which extends
southwestward from the axial spreading ridge of the South China Sea and has
considerable strike-slip movement (especially In the adjoining West Natuna
basin), and (2) a north-northwest to south-southeast trend of normal faults
with some dextral wrench movement In Indonesia (figs. 53 and 54). Associated
fault traps and folds are discussed under the pertinent plays. Subsidence
continued through the Pliocene and Pleistocene.
Structural Traps
The structural traps are drapes and fault closures associated with the
faults of 01Igocene to middle Miocene time. Apparently there are few drag
folds to accompany the evident, but unmapped, wrench faults. The A I-IX reef,
however, may be situated on a possible drag fold along a regional transverse
or wrench fault, approximately along the Indonesia-Malaysia border, associated
with the OlIgocene-MIocene opening of the South China Sea (figs. 54, 60, and
61).
From observation of unpublished maps, approximately 6 percent, or 1.0
million acres, of the play area Is estimated to be under drape or fault
closure. Possibly 20 percent of the closures are tested reducing the untested
trap to 800 thousand acres. Reefa I traps are discussed under Reservoirs.
Stratigraphy
The main units of the stratigraphy are displayed In the diagrammatic
stratlgraphlc section across the outer eastern edge near the AL-1X gas
accumulation (fig. 61).
About 6,000 ft of lower Miocene (latest 01Igocene to middle Miocene)
fluvial and deltaic sediments, the Arang Formations (with possible Gabus and
Barat Formations at depth) were deposited over the accreted, stable platform.
These shales and sandstones contain thin coal beds becoming less common
upward; the strata become marine near the top.
At the end of the Arang deposition (middle Miocene) (fig. 61), some
tenslonal faulting and tilting of fault blocks occurred prior to the formation
of a stable platform upon which shelf carbonates were deposited (fig. 62). By
the end the late Miocene, some 5,000 ft of shelf-type carbonates, the Terumbu
Limestone, covered the northern 60 percent of the basin (fig. 60). During
late Miocene, reefs and mounds grew on the topographic highs on the carbonate
platform (the large AL-1X accumulation Is Just on the east platform edge (fig.
61).

115
 L STRUCTURE
WEST L " 2X A, ,V
EAST
AP-1X (PROJECTED) AL ~ 1X

SEA LEVEL SEA LEVEL

TERUMBU
CARBONATE

10 Ml

DEPTHS: SHOWN IN FEET

Figure 61.-- West-east geologic section across east edge of carbonate platform, East Natuna basin
From Eyles and May (1984). Location on Figure 60.
 ^T-l>"^r
b . * MUDA FM.
:§-EIH: WELL SUMMARY (LATE PLIOCENE)

vo m =^4= AL - IX
^ o
r» <M WATER DEPTH 470 FT
* * i« \
ZONE t*1 m » DST #1 8603-8729' F GAS-COj 68%
i .-
L^-L-
t f\ n/w to ££
PERF. 10,370-10,400' F GAS. 3/4" CK
\ I..*
*\ * a- r^ / 16.2 MMCFPD - COi 67.6%
ZONE tt? * 1i^i__.
3
'T^ \
\PERF. 10,700-10,770 F GAS, 3/4" CK
* 14.0 MMCFPD - CO 7 67%
TERUMBU FM.
t3 J2 i-i - (UPPER MIOCENE-
«
<* EARLY PLIOCENE)
s ti -
ZONE t>n-

» i PERF. 13,450-13,480' F GAS, ? CK

'3.44 MMCFPD * 75 BWPD - COi 72%
i T n/w k u>
it ,PERF. 13,800-13,830' F GAS ? CK
'- ? MMCFPD - COi 82%
«

U.OOO' ARANG FM.

^ffJIfrl
(MIDDLE MIOCENE)
I^zZ-r-I
~ - -f-r-
TIGHT STREAK
15,000' REEF
1- T.O. 15,102'
RECRYSTALUZED
BANK

Figure 62.--Well summary, AL-1X wildcat, East Natuna basin.

After Sangree (1981).
 Deep regional subsidence In late Miocene and Pliocene resulted In thick
deep-water shales being deposited directly on Terumbu carbonates. This 8,000
to 20,000 ft of subsidence provided a thick seal, the Muda Formation shales,
to potential carbonate reservoirs and provided sufficient depth for maturation
of the underlying lower Miocene shales (figs. 61 and 62).
Reservoirs
The two principal sets of reservoirs essentially define the two plays of
the basin.
1. Early Miocene drapes and fault traps
No specific data are available concerning the sand reservoirs of the
lower Miocene (and 01Igocene?) formations. Reportedly, the average pay
thickness Is around 175 ft In the northern area under the Miocene Terumbu
carbonate platform. Further southward, however, the reservoirs become
gradually less developed. It Is estimated that the average net reservoir
thickness for the entire basin Is about 100 ft.
2. Miocene (Terumbu) carbonates
From study of unpublished maps of part of the play area, we estimate that
7 percent of the carbonate platform, I.e., the play area, Is reefa I trap of
which about half has been tested.
Although the best reservoirs are the reefs perched on the highs of the
carbonate platform, the shelfa I carbonates themselves have developed porosity.
For example, the AL-IX gas discovery found 5,250 ft of porosity of which only
about 2,000 ft are reef or reef complex. The reef (zone 1) averages 28.4
percent porosity; the reef complex (zone 2), 17.5 percent; and the shelf (zone
3), 14.5 percent (fig. 62). These thicknesses seem to far exceed those of the
other prospective reservoirs of the play, and the thick porosity zone In the
shelf appears to be unusual; for evaluation of undiscovered petroleum, an
average pay of 700 ft Is assumed, with an estimated average porosity of 22
percent.
In considering the volume of oil and gas In the reservoirs of this basin,
one must keep In mind that the chief occupant Is carbon dioxide gas, averaging
about 60 percent of the pore space.
Seals
The thick, largely shale Muda Formation provides a sufficient seal to
petroleum accumulations In the Terumbu reefs and shale of the Arang Formation
and should be sufficient for sealing sand reservoirs of the Arang and older
formations.
Source Section
The early to middle Miocene shales of the Arang and older formations
constitute the principal source rocks of the basin (see Generation and
Migration below).

118
Petroleum Generation and Migration
Richness of Source
No specific organic richness data are available, but according to
WIrajudo and Wongsosantlko (1983), geochemlcal analyses Indicate "fair to good
source rock potential for both oil and gas" In the lower Miocene Arang
Formation. Although primarily gas prone, the coaly beds are reported to
contain up to 25 percent waxy sapropels, which are known as oil source
kerogen. Sangree (1981) states that "the Arang Formation (lower Miocene) Is
considered the primary source of hydrocarbons for Miocene reservoirs In the
area, based on organic content and evidence of maturation of kerogen."
The source of the principal resource of the basin, carbon dioxide, Is not
known. There appears to be a direct correlation between the high thermal
gradients and the high percentage of carbon dioxide. It Is believed by some
that carbon dioxide Is derived from deeper Igneous sources (Sangree, 1981), or
thermally altered limestone at depth.
Depth and Volume of Source Rock
The average thermal gradient of the basin Is high, averaging about 2.5°F
per 100 ft but with a considerable part to the south over 3.0°F per 100 ft.
The rate of subsidence (Pliocene and Pleistocene) Is very high, around 1,800
ft per million years, placing the top of a rather thin oil-mature zone at
about 9,000 ft (2,700 m) and the top of the overmature (gas) zone at 10,000 ft
(3,000 m). At this depth, the lower Miocene shales are either mature or
overmature In all but the more shallow western side of the basin. WIrojudo
and Wongsosantlko (1983) confirm that "mature Miocene exists In the eastern
and southeastern part of the study area." Sangree Indicates, as quoted above,
that the Arang kerogen Is mature at AL-IX. In any event, there appears to be
sufficient mature and overmature source rock? a volume of 17,000 ml Is
estimated.
011 versus Gas
On the basis of occurrence, the basin appears to be gas prone. The
nonmarlne source and the relatively shallow overmature zone also Indicate
predominance of gas over oil (although the sapropelIc coal Indicates some oil
potential). At least one small noncommercial oil accumulation, Bursa, exists
In the area, and the Vietnam discovery, Dua-2X (20 miles to the north), tested
2,230 BOD.
No pressure data are available, but wildcat AH-2X encountered abnormally
high pressures below 4,500 ft. If these abnormal pressures are extensive, It
would mean that most of the Miocene reefs would be encased In overpressured
massive Muda shale, which would allow the primary migration of only the
smaller (I.e., gas) molecules Into the reefs. The underlying Arang and older
formations have much Interbedded sand so that the overpressure conditions may
not prevail, allowing the primary migration of the larger molecules of oil.
OH Is estimated to make up 5 percent of the oil-gas mix In the carbonate
reservoirs and about 20 percent oil for the oil-gas mix In the underlying
shale and sandstone series.

119
 Migration Time versus Trap Formation
It appears quite evident that generation and migration began In the
Pliocene when the basin very rapidly deepened so that the lower Miocene shale
became thermally mature, and In part overmature, In all but the most western
area. Additionally, the Pliocene shale would be In part mature.
Trap formation was In two periods: (1) early middle Miocene tenslonal
faulting and fault-block tilting caused closure affecting lower Miocene
sandstones (fig. 54 and 61), and (2) growth of reefs In late Miocene and early
Pliocene with possibly secondary porosity development as late as late Pliocene
(fig. 62). Both sets of reservoirs were formed before the main Pliocene
petroleum generation and migration. There would be time for reservoir
deterioration of the lower Miocene sandstones, and to a lesser extent the
upper Miocene carbonates. In general, It would appear that migration timing
for gas at least was fairly optimal, primary oil migration probably being
Inhibited by overpressured shale.
Limiting Factors
The overriding limiting factor appears to be the great volume of carbon
dioxide which largely occupies the reservoirs. Another limiting factor,
mostly affecting oil, Is the Inhibiting effect of overpressured shale on
primary migration.
Plays
The prospects of the basin fall Into essentially two plays.
1. Miocene drape or fault closures
Potential petroleum accumulations In 01Igocene to middle Miocene
sandstones are Involved In drape«or fault-closures. The play area encompasses
the entire basin about 27,000 ml or 17.3 million acres.
2. Late Miocene carbonate reservoirs
Potential petroleum accumulations are In upper Miocene (Terumbu
Formation) reefs and platform carbonate reservoirs In drapes or fault traps.
This play Is limited to the carbonate platform area which covers approximately
the northern 60 percent of the basin or about 10 million acres (fig. 60). The
base of the platform carbonate Is at a depth of about 5,000 ft, sloping gently
baslnward (eastward) to the Malayslan border. It Is limited to the south by a
diagonal, northeast-trending hinge line at about 5°30 ! N (fig. 60). A tall of
poorly developed carbonate thins southward along the Paus-Ranal Ridge
(fig. 60).
Salawatl-BIntunI Basin
Location and Size
The Salawatl-BIntunI basin Is on the Kepala Burung (Birds Head) Peninsula
In the western part of the Island of New Guinea (the Indonesian provlnce«of
Irlan Jaya) (figs. 1, 63, and 64)., It has an approximate area 56,000 ml and
a sedimentary volume of 105,000 ml . This basin Is often divided Into two
separate basins, I.e., the SalawatI and BIntunI basins. However, they are
here regarded only as subbaslns of the Salawatl-BIntunI basin, since the

120
 TECTONIC ELEMENTS
IRIAN JAYA
(INDONSIAN NEW GUINEA)

PACIFIC OCEAN
SALAWATI
SUBBASIN ..-.:

SALAWATI-BINTUNI ^ SYS7EHTT.
*- v.-.
^^^
WAR OP EN/ BASIN

CENTRAL RANGE
-^
~ Paleogene
_ x x
Line of Juras
aS

AKI'ME'UGAH
SUB BASIN

OCEANIC .' CONTINENTAL

CRUST ! CRUST

». Line of Jurassic continental rifting

Trace of present subduction zone
~"tr Trace of Paleogene subduction zone
Major wrench fault zone
Oceanic-Continental crust boundary
Sedimentary Basin perimeter

Figure 63.--Map showing tectonic elements of Irian Jaya

(Indonesian New Guinea). Modified after Hamilton (1979).
 BASEMEN
A1GEO
ERT1ARY VOLCANICS

SALAWATl
SUBBASIN

SALAWATl BINTUNI BASIN

DEPTH TO BASEMENT
CONTOUR INTERVAL 1 KILOMETER TARERA FAULT
SCALE 1:2,500,000

Figure 64. Structure contour map of the Salawati-Bintunl basins

showing the depth to basement and principal tectonic elements
After Hamilton (1979}.

122
saddle between the two Is more than 10,000 ft deep and some plays appear to
extend across the basin.
Exploration and Production History
The first wildcat was drilled In 1936 and It discovered the first oil,
Klamono field (fig. 65). Prior to 1962, 25 additional wells drilled In the
SalawatI subbasln resulted In the finding of two small noncommercial oil
accumulations (Klamumuk and Sele), but no further discoveries were made In
this phase of the exploration. In renewed exploration, the second discovery
was made at Kaslm In 1972. In all, some 145 wildcats have been drilled In the
SalawatI subbasln since then, resulting In 23 oil discoveries and 7 gas
discoveries for a success rate of about 20 percent. In the BIntunI subbasln
40 wildcats have resulted In four discoveries (Mogo, Was Ian, WIrlagar, and
Suga), giving a discovery rate of about 10 percent. Original reserves of 415
million barrels have been established In the SalawatI subbasln. Production Is
yet to be Initiated In the BIntunI subbasln.
Although the exploration of the SalawatI subbasln has been described as
Intensive, considering the apparent small size of most of the carbonate
buildups, appreciably more oil and gas fields probably will be found as the
seismic grid Is refined and techniques Improved; exploration Is Judged to be
In early maturity, I.e., about 70 percent complete. The BIntunI subbasln, on
the other hand, may be only 30 percent complete.
The production Is unusual because of the high permeability of the
fractured Klas reservoirs. As a consequence, Initial production rates are
high, e.g., up to 32 MBOD from a single well. For the same reason, decline
rates are high; e.g., Phillips production from a combined development of six
small accumulations on SalawatI Island was originally projected for 55 MBOD
(Pulling and Splnks, 1978) and produced 35.6 MBOD In 1978, 8.5 MBOD In 1979,
6.0 MBOD In 1980, 4.3 MBOD In 1981, and 3.4 MBOD In 1982. The decline Is
accelerated by the breakthrough or coning of water In the smaller fields. This
problem Is being alleviated to some extent by the application of gas lift.
For example, Kaslm (fig. 65) peaked at 15.3 MBOD, declined to 5.2 MBOD In
1981, and rose to 8.4 MBOD In 1982 after gas Injection.
Structure
General Tectonics
The tectonics of the New Guinea Island, Including Irlan Jaya and the
Kepala Burung Peninsula, are complicated and obscure but relevant to the
petroleum occurrence of the area (fig. 63). There are various Interpretations
of the regional tectonics; this study generally follows those of Hamilton
(1979).
As Inferred from Permo-CarbonIferous Interior-platform type sediments and
older north-trending structure, the New Guinea-Australia continental block was
part of a larger block extending to the north. The block was rifted apart In
mid-Jurassic, as Indicated by Trlasslc-Jurasslc typical terrestrial graben-
flll sediments. The resultant rifted continental margin trace extended east-
west through medial New Guinea, the Central Range, and along the Kapala
Burungs Peninsula's then north side (now the east side since the peninsula has
subsequently apparently rotated almost a quadrant clockwise) (fig. 63). Horst
and graben structure, developed during this rifting, affected the detailed
configuration of the Neogene basins, I.e., the pre-Tertlary ridges formed

123
 1 N I) K X MA

« It
81* 2.XX)
XOOO
0 ix Z.OOO
t i
G-l
J-n ),ooo
A 2X XOOO

Figure 65.--Index map showing location of fields and significant wildcats, Salawati basin.
From Petroconsultants (1981).
Cretaceous and Tertiary drapes and loci for Tertiary reef development (fig.
66),
A later Mesozolc (Late Jurassic) rifting separated the New Guinea-
Australian continental block from a more western continental block (India?).
The resultant north- trending rifted continental margin Is clearly evident
along the west margin of Australia, but In the region of the Kepala Burung
Peninsula, It Is obscured by the later Tertiary tectonics Involving the push
of the Sunda Arc to the east and the effects of the Pacific plate movement to
the west (fig. 63). However, this Mesozolc rift-tectonics framework and
attendant horsts and grabens may not have been entirely obliterated and It
appears that these fault patterns may have controlled to some extent the
distribution of Miocene subbaslns and reef distribution.
After the Jurassic continental margin rifting, the New Guinea-Australia
continental block was fairly stable through the Pa I eocene, the southern half
of New Guinea being essentially a marginal shelf sloping northward to the
block-edge (I.e., the rift zone through medial New Guinea).
The New Guinea-Australia continental block riding on a north-moving plate
during the Paleogene collided In the Miocene with a Paleogene Island arc under
which the north-moving plate was subducting. This collision caused the
uprising of the Central Range of New Guinea (Including the then west-trending,
now north-trending, east side of the Kapala Burung Peninsula). Along this
zone are crumpled and south-thrusted shelfa I sediments on the continental
(southern) side, and melange and Island-arc volcanic material on the oceanic
(northern) side.
With the arrival of the buoyant New Guinea-Australia continental block,
the northward subduct Ion choked and stopped. The continuing north-south
compression of the IIthosphere was then taken up along a newly-formed,
Neogene, southdlpplng subductlon zone. This subductlon zone Is still active,
offshore of, and dipping under, northern New Guinea, I.e., the New Guinea
Trench (fig. 63). Neogene activity on this southward subductlon has raised
the northern edge of New Guinea Into Intermittent ranges or outer-arc ridges,
concurrently forming an fore-arc Neogene basin to the south, the Waropen basin
(fig. 63). Renewed uplift of the medial or Central Range shed sediments to
fill both the Waropen basin to the north and the old north-sloping shelf or
foreland area, the Arafura basin, to the south (fig. 63).
There Is a strong westward, strike-slip component to the Neogene
southward subductlon forces, manifested by great west-trending slnlstral
wrenches along northern and central New Guinea, particularly In the western
part. Most of the recognized faults are In the so-called Sorong Fault zone,
which extends from north-central Irlan Jaya to the Celebes, and the Terara
Fault zone, which extends from south-central Irlan Jaya Into the Seram Trough
of the Banda Arc (figs. 63, 64, and 66). Large continental fragments have
been wrenched westward from the New Guinea-Australian continental block
smashing Into the Banda Arc area and the Celebes (Sulawesi). The Kepala
Burung Peninsula Itself Is considered by some to be such a detached
continental block transported from the east.

125
 130* 131

-<> <J Significant t«st», dry, oil, gas

Oil s««ps

Scale approx. 1:3,1 25,000

Dttail of Fields, W«lls and Trtnds

6- Figurss 68 and

MOGOI WASIAN
(OIL FIELDS)
WIRIAGAR
A :-J>

SALAWATI MIOCENE CARBONATE REEFS <> S.ONIN

BINTUNI MIOCENE CARBONATE REEFS (GAS SHOW)

X CARBONATE SHELF EDGE (LOCI OF REEFS)

MIOCENE CARBONATE DRAPES
DRAPES OVER INFERRED PRE - TERTIARY RIDGES
CRETACEOUS FAULTED AND DRAPED SANDSTONE
BINTUNI NEOCENE FOLDS (LENGGURI FOLD BELT)
ANTICLINAL AXIS (DIAGRAMMATIC)
SALAWATI PLIO-PLEISTOCENE DIAPERS - 4°
^ DIAPIRIC CLOSURE (DIAGRAMMATIC)
AREA OF NO OR THIN L.MIOCENE (KAIS FM) STRATA

Figure 66.--Map of Salawati basin showing area of plays, trends, and significant tests
Structural Traps
Structural traps are In three groups: 1) drapes and fault traps along a
northwest-trending, pre-Tertlary rift pattern of ridges, horsts or tilted
fault blocks (fig. 66), 2) late Tertiary north-northwest-trending relatively
tightly folded and thrusted anticlines of the Lengguru foldbelt, and 3)
dlaplrs In the western depocenter of the SalawatI subbasln.
The drape and faulted features follow northwest-trending burled rift
features apparently paralleling the pre-Tertlary (Jurassic?) rifted northern
margin of the Australia-New Guinea continental block (orglnally east-west, now
northwest-trending after the clockwise rotation of the Kepala Burung
Peninsula). This drape play probably extends over all of the BIntunI
subbasln, excluding the later compressfonal Lengguru Foldbelt but Including
the Misool-Onln-Kumawa Ridge (fig. 66). The play area Is approximately 18.6
million acres for the Cretaceous reservoirs (largely missing from the SalawatI
subbasln). The Tertiary reservoirs on the other hand are missing from the
Misool-Onln-Kumawa Ridge, giving a play area of 12 million acres. From
Information In published and unpublished structural maps of the area, drape
closures are estimated to make up about 5.5 percent of the drape play area.
This works out to be a million acres for the Cretaceous reservoirs and 660,000
acres for the draped reservoirs at Miocene level.
The relatively tightly folded and thrusted, north-northwest-trending
Lengguru Foldbelt (fig. 66) covers 6.14 million acres. By analogy to somewhat
similar foldbelts of Indonesia (e.g., Kutel basin folds with trap area making
up 3 percent of the play area and North Sumatra with traps making up 8
percent), traps are estimated to make up 5 percent of the play area or about
307,000 acres.
DIapIr folds Involving Pliocene sandstones and shales occur In the deeper
baslnal area of the SalawatI subbasfn (fig. 66). Information from an
unpublished map shows there are approximately 154 thousand acres of trap.
Stratigraphy
The stratigraphy of the Salawatl-BIntunI and of the Arafura basins Is
similar, but the pre-Tertlary formations are better exposed In the Arafura
basin. The general stratigraphy of these two basins (as exposed In the
Arafura basin) Is shown In figure 67.
Western Irlan Jaya sedimentation began when upper Carboniferous to
Permian, often highly carbonaceous, elastics of the Alfam Group were laid down
In a stable, probably Interior, platform. This was succeeded by the TI puma
Formation of graben-deposlted Trlassie terrestrial red and green shales and
sandstones, undoubtedly associated with the faulting, attenuation, and final
rifting along the north margin of the Australian-New Guinea continent.
The Kembelangan Group of Middle Jurassic to upper Cretaceous marine sand
stones and mudstones, derived from the New Guinea-Australian continent to the
south, were deposited on the broad north-sloping shelf which extended across
the present southern half of Irlan Jaya and occupied the BIntunI subbasln, but
was largely missing from the SalawatI subbasln of the Kapala Burung Peninsula.
With waning clastic deposition, a carbonate regime set In and persisted
over the shelf through the late Cretaceous to late Miocene, resulting In the
thick New Guinea Limestone Group covering a 11 of southern Irlan Jaya and the
Kapala Burung Peninsula. The youngest unit of this group, the Klas Formation,
contains the principal petroleum-bearing reservoirs of the SalawatI subbasln
(fig. 68).

127
ARLJ SUBBASIN AKIMEUGAH SUBBASIN I WUR SUBBASIN

OMBA-AIDUNA WISSEL LAKES AKIMEUGAH NORTHWEST RIVER STEENBOON RIVER OK BIRIM RIVER

No horizontal scale

Vertical scale
(KLM) (KLM) Klasaman Fm. in
Salawati-Bintuni Basin FEET METERS
O r-O
(Bu) (Bu) Buru Fm. in Arafura Basin
coarse elastics derived from
north (Central Range) (PLIO-
PLEISTOCENE)
(Bu) h-1000

(Bu)
5000
\ (Bu)
(KL) (KL) Klasatet Fm. shales, marls, ^2000
carbonates, derived from north
(MIOCENE)
(IW)
(Bu)
(AK) Iwur Fm. shales, marly>
Akimeugah Fm. shales, marls, carbonates from north (MIOCENE)
carbonates derived from north
(NG) NG) New Guinea (MIOCENE)
Limestone Group
(PALEOCENE- (NG)
MIOCENE)

(KB)

(KB) (KB) Kembelanpen Group, shelf elastics

derived from the south (Australia)
(MID.JUR-CRETACEOUS)

(KB)
(Tl) (BR) (BR) Carbonate facies of Tipuma Fm.

(Tl) Tipuma Fm. terrestrial elastics in fill

(Al) of grabens formed in Triassic-Jurassic
rifting (TRIASSlC-JURASSICl

(Al) (Al) Aifam Fm. largely clastic, non-marine

to marine. Probably interior platform
deposits (PERMO-CARBl

Figure 67.--West-east outcrop sections, Arafura basin, Irian Jaya; also applicable
to the Salawati-Bintuni basin. Sections from Wisser and Hermes (1962).

128
 KL AMONG
AJAMAROE^ 1
ASPHALT PLATEAU

- iooo'

ro

Figure 68.--West-east geologic cross-section A-A 1 , Salawati subbasin.

From Vincelette (1973). Location figure 65.
 During the Miocene, the carbonates were succeeded by shales and marls of
the Klasafet Formation, the transition apparently occurring earlier In the
deeper, more baslnal areas (fig* 68). In both the Salawatf and BIntunI
subbaslns, the Klasafet Formation occupies the basinal areas but Is thin or
missing on the perimeter of the basins. Figure 68 demonstrates this condition
for the Bintunf subbasin. Similar shale-carbonate subbaslns occur along the
strike of this Pa I eocene-Miocene carbonate shelf, i.e., the Aru, Aklmeugah,
and Iwur subbaslns of Arafura basin (figs. 63 and 67).
Unconformably overlying the Klasafet shales In the deeper subbaslns and
the New Guinea Limestone Group In the perimeter areas are Pliocene coarser
elastics, the Klasaman, Buru, and Steenkool Formations (figs. 66 and 68).
These elastics moved southward from the Central Range (and its extension, the
Lengguru foldbelt, presently along the east side of the Kepala Burung
Peninsula).
Reservoirs
Potential reservoir zones exist in three general zones: 1) Cretaceous
upper Kembelangan Group sandstones, 2) Miocene upper New Guinea Limestone
Group carbonate (Kais Formation), and some sandstone reservoirs, and 3)
Pliocene Klasaman-Steenkool sandtones. Of these reservoirs only the Kals
Formation has produced oil.
1. Kembelangan Group Sandstones
The Kembelangan Group Is a 6,000-ft thick sandstone and shale unit with
subordinate carbonate, which extends the length of southern New Gulnea-lrlan
Jaya; and in fact equivalent formations cover a great area of southern Papua,
New Guinea and the Australian offshore. The Kembelangan Formation thins
southward; and in the Kepala Burung Peninsula thins northwestward so that It
is generally missing from the Salawati subbasfn. According to Visser and
Hermes (1962), the sandstones as found in outcrop are "mlneralogical Iy mature,
consisting mainly of quartz, very subordinate feldspar and clay minerals.
Sorting is generally good." The Kembelangan outcrops reportedly become more
sandy toward Australia.
As encountered In the few wildcats, however, the reservoirs appear to be
fair to marginal, the best reservoirs appearing to be In the sandstones near
the upper part of the formation, as variously reported from the following
we I Is:
Kembelangan-1 - Although tight In the well, these upper sandstones grade
laterally Into well sorted, clean sandstones In adjacent outcrops. (There is
a lost circulation zone near the base of the Kembelangan Formation.)
PuragI-1 - The uppermost 165 ft of Kembelangan contains some 100 ft of
porous sandstone; a weak flow of brackish water was tested.
Sago-1 - Some 130 ft In the upper Kembelangan had porosities ranging from
3 to 24 percent.
TBF-1 - A "few tens of meters" of porosity ranging from 8 to 17 percent
are in thIs Interval.
TBE-1 - Some good porosities were measured from cores but with low
permeablIItles.
TBJ-1 - In a more calcareous fades, there was found a net thickness of
1,650 ft in carbonate, a porosity with values of 5 to 24 percent, and 100 ft
of porous sandstone with even "better porosity."
ASF-1 - Found a zone of 84 ft of net sandstone thickness of porosities of
8 to 17 percent, which when tested recovered 6,900 ft of gas cut mud.

130
 For evaluation purposes, we assume a basin-wide average thickness of 100
ft with a porosity of 15 percent for the Kembelangan sandstones.
2. Miocene Kalg Reservoirs
The Kals reservoirs are largely carbonates In the form of reefs, banks,
or porous zones In back-reef environments. Some sandstones are present at the
equivalent to the base of the Kals (the Sirga Formation).
The reefs and buildups are associated with the carbonate platform edges
In the SalawatI and BIntunI subbaslns (figs. 66, 68, 69, and 70). Only the
SalawatI carbonates have produced oil, and accordingly their reservoir
characteristics are better known. Maximum vertical bank buildup of the
SalawatI reefs Is about 1,600 ft. The net thickness of the porous zone varies
from 30 to 700 ft, and an average net pay of 165 ft for reefa I closures Is
estimated. The play area of the SalawatI reefs Is some 1.5 million acres (see
Plays). A published map (fig. 70) Indicates that carbonate reefs make up
about 6 percent of the play area, or about 90,000 acres.
The porosity of producing reservoirs varies up to 24 percent In the Wallo
and Klamono fields, but Is as low as 15 percent In Linda or 12 percent In
Sele, perhaps averaging about 20 percent. Apparently most of the porosity Is
secondary, vuggy and moldlc. Fractured zones have large permeabilities, e.g.,
a dolomite zone In Kaslm, Utara-1, tested over 32,000 barrels per day. The
oil recovery rate for the Klamono oil field Is 531 barrels per acre-foot
(Vincelette, 1973).
Of particular note should be the high permeability, which, together with
an active water drive, Introduces not only high Initial flow rates, and
consequently relatively steep decline rates, but also early breakthrough of
water, particularly In the smaller accumulations, requiring secondary recovery
procedures, mainly gas lift.
The reefs of the BIntunI subbasln would theoretically be developed along
the carbonate platform or shelf-edge (second play of fig. 66), an area of some
5 million acres (see Plays). Wlldcattlng to date has failed to find any
viable reef or porous carbonate buildup In this play. It has been postulated
that this absence Is because of an unstable, migrating shelf-edge or low wave
energy level (I.e., low topographic position). However, pinnacle reefs,
having small areas, could be missed In this area where, except for the
northern edge of the Bomberal Trough, the average seismic grid Is only 6 by 10
km. For assessment purposes, It Is estimated that some 3 percent of the reef-
edge play area may have reef traps (versus 6 percent for the SalawatI
subbasln).
The generally back-reef fades of the Kals Formation, which Is Involved
In the Miocene drape play, has some porosity; It ranges over a large part of
the Salawatl-BIntunI basin, south of the Kals outcrops, between the shelf-edge
area of the SalawatI subbasln and that of the BIntunI subbasln (play 3 of fig.
66) and covers an area of 12 million acres. Within this regional back-reef
fades, there are carbonate banks which appear to be localized along old
structuraI/topographic highs. Most of these porous zones appear to be In part
reefal. Porosities are Irregular and lower than the SalawatI reefs. At the
Was Ian and Magor oil fields, and In nearby wildcats, porosities are at most 14
percent, except where fracturing raised it to 22 percent at Kaibur.
Porosities are likewise low In central BIntunI except where there Is
fracturing. Porosities are higher, however, at BIntunI A-1, averaging 32
percent, and are presumably equally as good at WIrlagor. Twenty percent
porosity Is estimated for the back-reef fades play.

131
 B

NW WASIAN-I MUTURI-I GUSIMAWA MUKA ARGUNI-I IRIS KEMBELANGAN- I SE

BINTUNI BASIN COVER

STEENKOOL FORMATION CLASTICS (ST)

PLIO-PLEISTOCENE
- St
^> ^"~~- - =*
St ^l St
s ^
Klk ^^
/ IS
N KLF /
X
X KLASAFET SHALE MIOCENE
X / N
V KLF
/
N X /
X / PALEOCENE

N
CO NEW GUINEA LIM ESTONE GROUP (N). (K)
ro
KB KB
FT M KB
0 -r 0
KEMBELANGAN GROUP CKB) CRETACEOUS

KB
JURRASIC
- I 000

5000 -
EARLY MESOZOIC
TIPUMA FM CTI) Ti
- 2000 LATE PALEOZOIC

Vertical scale I :50,000

No horizontal scale

I 0,000 - - 3000

L 4000

Figure 69.--NW-SE stratigraphic sections, A-B, Bintuni subbasin. Sections from

Visser and Hermes (1962).
 Legend

Coral/algal reefs

Coral reefs

Platform limestonex Salawati Island

^3
Platform w/open marine influence

Basinal limestone and shale BASINAL LIMESTONE AND SHALE

Algal, foram, bryozoan banks.

"
OJ \»'jj(i' Carbonate mud buildups! - I_ L «g
OJ
^^ K Ji I > L r J

KAIS REEF PLATFORM

Figure 70.--Kais facies map, Salawati subbasin. From Pulling and Spinks (1978).
 Thickness data are not available, but an effective pay thickness of about
half that of the SalawatI reefs or about 83 ft appears reasonable.
3. Klasaman steenkool Sandstones
The PIlocene-KIasaman-SteenkooI rock group Is a 15,000-ft paral fc
sequence of sandstones and shale with some marine Interbeds. It overlies the
Klasafet shales In the baslnal areas, and older rocks on the basin periphery,
by an evident hiatus. Little reservoir data are available. Steenkool-1 (fig.
66) drilled In the northern BIntunI subbasln found "many well developed sands
of good reservoir characteristics" (Vlsser and Hermes, 1962). For assessment
purposes, It Is assumed that average net pay thickness Is at least 100 ft with
a porosity of 20 percent. These shallow reservoirs are not regarded to be of
much significance because they generally lack sufficient cover.
Seals
From oil stains below the present oil-water contacts, It appears that
considerable amounts of oil, probably at least half, have escaped present
reefal closures In the SalawatI subbasln. At Wallo, the largest field, there
appears to have been only 30 ft of oil stain below the oil-water contact, but
at Kaslm and Joya, It appears that at least half the oil has been flushed
away. At the relatively shallow Kalamano field nearer the edge of the basin,
the original oil column, as Indicated by staining, was 1,300 ft versus the
recent oil column of 440 ft; the even shallower Klamnuk had an Indicated oil
column of 600 ft versus the recent 200-ft hydrocarbon column (fig. 68).
Flushing Is also Indicated by the character of the oil, which ranges from
35° gravity oil at a depth of 2,100 ft at Sele In the central basin deep to
19° and 15° gravity oil with a high residual sulfur content at Klamono and
Klamumuk reefs near the basin edge (fig. 68). Outcropping reefs at the basin
edge contain only asphalt residue (fig. 68).
One of two controlling factors In the flushing of the SalawatI reefs
appears to be the thickness and Impermeability of the overburden, primarily
the Klasafet shales, which may not only provide seal but source for the
petroleum accumulations. In fact, the prospective area of the SalawatI and
BIntunI subbaslns Is best defined and limited by the Klasafet cover strata.
The overlying, more porous KIasaman-SteenkooI-Buru elastics rest directly on
the eroded New Guinea Limestone around the basin perimeter (figs. 67 and 69).
The second factor In flushing appears to be late Pliocene-Pleistocene
uplift accompanied by widespread normal faulting and fracturing, which allowed
fresh water Into the Kals Formation.
In the BIntunI subbasln where late Neogene subsidence was greater, a much
thicker cover of Klasafet or Steenkool marls, shales, and Klasaman sandstones
and shales may have Inhibited the considerable leakage such as affected the
SalawatI subbasln.
Source Section
The presence of source rock Is assured by the presence of oil and gas
seeps and shows from all through the section from the Kembelangan Group
(Cretaceous) at the south end of the BIntunI subbasln to the oil and gas shows
In the Kals reefs (Upper Miocene) of the SalawatI subbasln and to the
Steenkool Formation (Pliocene) of the western BIntunI subbasln (fig. 66).

134
Petroleum Generation and Migration
Richness of Source
The existence of sufficiently rich source rock In the Salawatl-BIntunI
basin Is evidenced by seeps and shows from Cretaceous (Kembelangan Group)
through to the middle Miocene, Kals Formation, but few definitive analyses are
aval(able.
Unlike the rest of Indonesia, there appears to be definite pre-Tertlary
source rock In Irlan Jaya. In offshore wildcat Kalltaml-IX, near the mouth of
Blntunl Bay, a pre-Tertlary thermally mature (vltrlnlte reflectivity of .75
percent) shale of unknown thickness with an organic content of 6 percent was
reportedly encountered at a anomalously shallow depth, 4,331 to 4,656 ft.
Good Kembelangan "source rock" was reported from Sago-1 (northern Blntunl
subbasln) also at a shallow depth, 3,202 to 3,402 ft. Vlsser and Hermes (1962)
report organic mudstones In the Kembelangan outcrops.
The source of the Kals carbonate reservoir accumulations appear to be the
enclosing and overlying Klasafet shales and marls and the down-dip platform
equivalent, the Klamogen marls and shales (fig. 68). According to Vlsser and
Hermes (1962), these Miocene shales are rich In organic matter and possibly
the source rock for much of the oil In the basin. Some believe the underlying
Ollgocene, gray pre-Kals shales, the SIrga Formation (fig. 68) are the
principal source rocks of the Kals reservoirs, but recent work suggests
Mesozolc source for the Kals oils. No definitive source richness data are
aval(able.
Depth and Volume of Source Rock
Although geologically similar In many ways, the Salawatl and Blntunl
subbaslns differ In that the Blntunl subbasln's Neogene subsidence was much
greater and deeper and Its thermal gradient Is lower, averaging 1.6°F/100 ft
versus the average thermal gradient for Salawatl subbasln of 3°F/100 ft.
The Salawatl subbasln's heat gradients combined with the Neogene
subsidence puts the average top of the mature petroleum generation zone at
about 6,800 ft and the volume of mature or overmature sediment at about 1.6
thousand cubic miles.
In the cooler more rapidly subsiding Blntunl subbasln, the mature
sediments calculate to be much deeper, about 13,500 ft (supported by wildcat
Terle-1 where vltrlnlte reflectance reportedly Indicated near thermal maturity
at 13,765 ft). In spite of this depth, a large volume of mature sediments,
approximately 21.6 cubic miles, may exist owing to the deep presence of the
thick Cretaceous Kembelangan Group sediments (which are thin or missing In the
Salawatl basin).
011 versus Gas
The oil versus gas content In the traps of the six different plays varies
widely. The estimated oil content ranges from the 30 percent In the
Cretaceous drapes of the deep Blntunl subbasln and the dlaplrs of the deep
southwestern part of the Salawatl subbasln to 90 percent In the poorly
covered, fractured Miocene reefs of the Salawatl subbasln and the folded and
fractured Neogene sandstones of the Lengguru foldbelt. As an average for the
whole basin, the accumulated petroleum Is estimated to be 60 percent oil.

135
 Migration Timing versus Trap Formation
In the Salawati subbasin there Is one principal play, the Neogene
carbonate reservoirs. Assuming that the same thermal gradient and the same
rate of subsidence continued through the Tertiary, substantial oil generation
would have begun In the Pliocene (about the beginning of the Klasaman
subsidence, fig. 68) when the source Tertiary shales would have subsided to
below 7,000 ft In the basin center. At this time the reefs were largely In
place and largely covered, and migration timing would be near optimum. That
oil accumulation was largely prior to reservoir deterioration Is suggested at
the Jaya and Kasim fields by secondary calcite filling of vuggy and moldlc
pores immediately beneath the oil-water contact, reducing the reservoir
porosity from 30 to 20 percent (Vincelette and Soeparjadi, 1976).
Assuming a constant thermal gradient and subsidence rate through the late
Mesozoic and Tertiary In the BIntuni subbasin, generation and migration would
have begun after the source rocks had subsided to about 13,500 ft in this
rapidly subsiding basin. Assuming the Kembelangan and New Guinea Limestone
Groups were near their combined maximum thickness of about 14,000 ft (9,000 ft
and 5,000 ft respectively), generation from Kembelangan shales In the deeper
parts of the basin would have begun sometime near the end of New Guinea Lime-
stone deposition (Miocene) and concurrent with the formation of the Miocene
carbonate reservoirs and after the Kembelangan (Cretaceous) sandstones
deposition.
The structure Involving the Kembelangan Group outside the steeply folded
Lengguru foldbelt appears to be of low relief with faults and low-amplitude
gentle warps or drapes. The drapes (and faults) have a northwest trend (fig.
66) suggesting that they follow earlier Mesozoic rifting patterns and are
therefore old closures predating the petroleum generation. Probably there was
some reactivation of old faults reaching a maximum at the same time as the
Lengguru folding. I.e., late Neogene.
The Kais reefs and reservoirs of the Bintunl subbasin, having presumably
formed after generation and migration of Kembelangan sourced-petroleum had
started, would be available soon after reservoir trap formation, an optimum
time for reservoir preservation, but would presumably fall to catch much of
the earl ier primary migration.
Assuming continued BIntuni subbasin subsidence at a constant rate,
generation and migration of the petroleum derived from Miocene shales and
marls began when they subsided to 13,500 ft, an event which has only happened
recently and In the deeper parts of the basin so that there has been little
time for these shales to contribute.
Steenkool reservoirs were deposited In the Pliocene and the structural
traps formed In the Pliocene-Pleistocene. These traps were available for
petroleum from the Klafelt (Miocene) shales, which only recently reached
petroleum generation maturity.
Plays
The apparent petroleum prospects of the Salawati-BIntunI may be divided
into six plays. In order of their apparent prospectivity: 1) Salawati Miocene
Carbonates, 2) Blntuni Miocene Carbonates, 3) Miocene Carbonate Drapes, 4)
Cretaceous Faulted and Draped Sandstones, 5) Bintuni Neogene Folds, and 6)
Salawati Pliocene Diaplrs. The play areas are defined below and described In
detail In the play analyses (fig. 66).

136
1. SalawatI Miocene carbonates
Potential petroleum accumulations are In Miocene carbonate buildups In
the SalawatI subbasln. The area! extent of the play Is limited by the Miocene
environment favorable for reef development and by the area of effective cover.
Both are related to the pattern of Mesozolc-Tertlary subsidence. No Isopach
of the sealing Miocene shales Is available, but It Is assumed to be parallel
to the Isopach of the overall basin fill, I.e., the sealing shales are thicker
and more effective In the deeper basinal areas. Tending to confirm this Is
the confinement of the oil accumulations and shows to where the basin Isopach
approaches a 4-km thickness. On the other hand, the deeper parts of the
subbasln in Miocene time would be unfavorable for high-energy carbonate
reservoir development; this deeper area approximates the SalawatI subbasin
Isopach thickness greater than 5 km. On this basis, the area of petroleum
accumulation In carbonates would be approximately limited to the area between
the 4 and 5 km isopachs of the basin fill (fig. 64) or some 1.5 million acres.
2. BIntunI Miocene carbonates
Potential petroleum accumulations are In Miocene carbonate buildups In
the BIntunI subbasln. As In the SalawatI subbasln, the area of play Is
limited by the effective cover. The area which was favorable for reef
development Is more difficult to estimate since the young, deep BIntunI
subbasln has a present configuration largely unrelated to the configuration of
the reef-forming period. The subbasln has an Irregular shape which probably
reflects the Mesozolc extenslonal fault pattern, which In part has a strong
east-west component, e.g., the Bomberai Trough (fig. 66). Part of the
carbonate reservoirs are Involved In the much faulted Lengguru foldbelt and
have probably leaked to such an extent that they can be excluded from the
play. The play Is probably concentrated along the edge of the carbonate shelf
edge (play 2, fig. 66), an estimated area of about 5 million acres.
3. Miocene Carbonate Drapes
Potential petroleum accumulations are In Miocene back-reef carbonate and
sandstone reservoirs draped over northwest-trending pre-Tertlary highs, the
structure paralleling to some extent the Cretaceous Drape Play (fig. 66). The
reservoirs are within the upper New Guinea Limestone Group, largely the Kals
Formation. Although the reservoirs may be in part reefal, they do not include
reefa I buildups extending Into the overlying shales as In plays 1 and 2, but
are Interbedded with less permeable Kals carbonates and shales. The play Is,
therefore, not so dependent on younger shale cover and extends over both
subbaslns for a total of some 12.0 million acres.
4. Cretaceous Faulted and Draped Sandstones
Potential oil and gas accumulations are In Cretaceous shelfal sediments
(the Kembelangan Group). The structures appear to be largely drapes or fault
closures associated with northwest-trending ridges, reflecting horst and
graben structure of the Mesozolc rifting (fig. 66). The area of play Is
restricted largely to the BintunI subbasln since the Kembelangan Group of
sandstones and shales thins northward and has little appreciable thickness In
the SalawatI subbasln. To the west, however, the Kembelangan or equivalent
strata may underlie the Onln-Kumawa ridge. Assuming that Kembelangan
sandstones underlie the entire BIntunI subbasln, Including the Onln-Kumawa
ridge as far west as the Seram Trough but excluding the foldbelt, the play
area amounts to 18.6 million acres.

137
5. BIntunI Neogene Folds
Potential petroleum accumulations are In Neogene anticlinal folds
Involving Tertiary and Mesozolc reservoirs In the Lengguru foldbelt of the
eastern BIntunI subbasln. The play area Is limited to the Lengguru foldbelt
and has an area of some 6.14 million acres (fig. 66).
6. SalawatI Pliocene DIapIrs
There appears to be some potential for petroleum accumulations In
Pliocene sands Involved In dlaplrlc anticlines In the deeper, baslnal part of
the SalawatI subbasln. The estimated area of play Is some 1.5 million acres
(fig. 66).
Arafura Basin
Location and Size
The Arafura basin of Tertiary and Mesozolc rocks extends along the
southern half of Irlan Jaya (figs. 1, 63, and 71). It Is bounded on the north
by the so-called Central Range and separated from the Salawatl-BIntunI basin
to the northwest by the Terara Fault zone. Southward, It merges Into the
Australian Shelf containing upper Precambrlan sediments. To separate the
Arafura basin from these nonprospectlve older shelf rocks, the southern basin
edge Is somewhat arbitrarily placed where the entire southward-thinning
sedimentary section becomes less than 3 km thick. This necessarily excludes a
thin wedge of Cretaceous sediments which extends southwestwards along the west
side of the New Guinea-Australian continental block (fig. 71). The Arafura
basin Is bounded on the west by the Banda Arc Trough, and to the east, It
continues on Into Papua New Guinea. It has an area 50,000 ml and an
approximate volume 120,000 ml within Irlan Jaya.
Exploration and Production History
Three wells were drilled In the southern part of Irlan Jaya prior to
1962. Of these, only Jaosakor-1 Is within the basin as here defined (fig.
71), the other being on the Australian Shelf. In 1970-74, Phillips Oil
Company drilled three offshore wildcats, ASA, ASB, and ASM, within the Arafura
basin. In the same period, Champ I a In Oil Company drilled three wells In the
extreme updlp (southern) part of Irlan Jaya waters on the Australian shelf
outside of what we are here considering the Arafura basin. In 1980 and 1981,
Amoseas (Standard ON of California and Texaco) drilled two onshore wells,
Kumbal Satu-1 and KuruwaI-1. In 1984, Koba-1 was drilled on the Aru hinge
area also outside of what we are considering the Arafura basin. All wildcats
were dry (fig. 71).
Structure
General Tectonics
Extensive Permo-carbonIferous sedimentary rocks (Alfam Formation) appear
to be of an Interior cratonlc mixed marine and terrestrial fades, whereas
more restricted Trlassie-Jurassic sediments appear to be terrestrial Infill of
rifts as seen along the south flank of the Central Range (fig. 66). Late
Jurassic, Cretaceous, and Paleogene sediments are of a marine shelf a I fades,
thickening northward. On the basis of these changes, plus truncation of a

133
 INTERVAL CONTOUR INTERVAL I KILOMETER

OCEANIC CRUST + ISLAND

PAt-EOGENE
^=3"!^
NORTH EDGE N^ GUINEA

CENTRAL RANGE THRUST

co

O Dry wildcat
Wrench zone
Subduction zone
Rift zone
xt Outcrop section
134° 136° 138° 140°

Figure 71.--Map showing tectonic elements and basement depth, Arafura basin. After Hamilton (1979).
major north-trending orogenlc feature of east New Guinea, Hamilton and others
suggest a mid-Jurassic east-west zone of rifting of a Permo-carbonfferous
continent along the present Central Range, which separated the present New
Guinea-Australia continent to the south from a northern segment (Sunda
Block?), which subsequently moved away.
In the late Paleogene-early Neogene, the New Guinea-Australia continental
block, moving northward on a subducting plate, collided with an Island arc
under which the plate was being underthrust along a north-dipping subductlon
zone. With the collision, the subductlon In this zone ceased.
Continued north-south compression of the Ifthosphere In the Neogene
caused further shortening to be renewed on a Neogene, south-dipping subductlon
zone north of the Paleogene Island arc, I.e., north and just offshore of the
present Irfan Jaya (figs. 63 and 71). At the same time, renewed uplift of the
Central Range (reaching a maximum In the PIlo-Plelstocene) caused sediments to
be shed Into the Arafura basin to the south and the Waropen basin to the
north.
The Arafura basin Is on the New Guinea-Australian continental block, Its
northern flank being the Central Range collision zone and the southern flank
being the gently northward dipping New Guinea-Australia shelf. The north edge
of the basin has been affected by a number of regional west-trending slnlstral
wrenches, which are particularly evident In the west; the major wrench Is the
Terara Fault zone (figs. 71 and 72). The western end of the basin Is a north-
trending, west-dipping, normal-faulted monocline Into the trench of the Banda
Arc (figs. 71 and 73). A low structural arch runs along the north-trending
hinge line of the monocline In line with Aru Island.
Structural Traps
There are four possibilities of structural traps.
1. Horsts and grabens provide fault closures and drapes associated with the
mid-Jurassic rifting. They also provide a framework for Tertiary sedimentation
Including reef localization.
2. Compression folds associated with the late Paleogene-early Neogene
continental-Is I and arc collision.
3. A number of large drag folds caused by slnlstral wrenches along the
western quarter of the northern basin boundary.
4. The normal faulted monocline Into the Banda Arc trench and the associated
faulted hfnge-lfne arch through Aru Island.
A fifth type of trap, not structural, would be Miocene reefs.
Concerning the first structural trap, there are no subsurface hard data
available Indicating the presence of horst or tilted fault blocks associated
with supposed east-trending mid-Jurassic rifting along the north edge of the
New Guinea-Australia continental block (the Central Range), although geo-
physical data on some cross-section lines of Vlsser and Hermes, 1962 (Tectonic
Sections 22 and 23) suggest block-faulting. Although drapes of Cretaceous
sandstones over these fault blocks would be a play with considerable
potential, In the absence of more data and because of the possibility that
this structure would be overprinted by later tectonics so that early
accumulations would be redistributed, this play Is grouped with other later
structural traps.
Concerning the compresslonaI folds of the continental-Is I and arc
collision zone (Central Range), there have been some small, tight, sometimes
thrusted, anticlines mapped In the outcrop belt. A potential gas and
condensate field, Jahu, has been discovered (1983) In similar structure on

140
 EXPLANATION
STRIKE AND DIP OF BEDS r-- ; UPPER QUATERNARY ALLUVIUM
Gentle Distinguished from unit QTc by lack of de-
formation
nTr I QUATERNARY AND PLIOCENE CLASTIC
Strike-slip Dotted UIC ! SEDIMENTS Of foreland basin
where concealed
FOLD AXIS-Showing plunge [V Td^ X | MI°CENE< ?> DIORfTE

MIOCENE TO PALEOCENE LIMESTONE Of

Kc i CRETACEOUS CLASTIC STRATA Of conti-

nental shelf. May include older rocks

jc.r fault-' ; :: " '' ' ' ' . '.-. ' ' ' '' ' ' ' » ' '''' '" " : '-^1 AV ;.''' ' .-'. ' . ' .' ' ' ' ' ' >*/

Figure 72.--Geologic sketch map of part of the Tersra fault zone and other features, southwest
New Guinea. After Hamilton (1979).
 KAI 8ESAR ARU TROUGH ARAFURA PLATFORM

W E

ro

Figure 73.--Aru trough cross section, Arafura basin. From Kartaadiputra (1982).
strike 100 miles to the east In Papua New Guinea. Presumably, additional more
open folds are found under the alluvium of the basin. The area of this play
Is an approximately 20-mlie-wide Tertiary and alluvium-covered strip along the
eastern three-fourths of the foothill and adjoining plains area with an
estimated play area some 10,000 ml (6.4 million acres). The amount of
effective closure would be small In this complex, faulted zone; examination of
Vlsser and Hermes 1 (1962) outcrop map Induces an estimate of 1 or 2 percent of
the play area or an approximate 96,000 acres.
The drag folds associated with prominent wrench faults (mainly the Terara
and associated fault zones) along the western part of the north boundary of
the basin, are large and prominent (figs. 71 and 72). They have not been
tested; although a wildcat, Kembelangan-1 (fig. 66) In the adjacent BIntunI
subbasln has tested an apparently similar structure, the Kembelangan Dome, but
with negative results. The drag folds play extends over an area some 8,000
ml (5.1 MMA). By analogy to the drag fold frequency of the wrench-faulted
Central Sumatra basin, the area of drag-fold closure Is estimated to be 5.5
percent of the play area or about 280,000 acres of trap closure. Because of
difficulty In distinguishing the drag and compression fold plays from the data
at hand, they have been combined Into a single play, "Anticlines," with a
combined area of 11.5 million acres.
The faulted, westward-dipping monocline Into the Banda Arc trench and
associated Aru Island arc trend Is crossed by a published section
(Kartaadlputra and others, fig. 73) and other unpublished geophysical profiles
which Indicate faulting with horst and tlIted-fauIt-block closures on the west
side of the so-called Arafura platform (Aru subbasln, fig. 71). Two offshore
wildcats (ASB and ASA) apparently have tested Mesozolc or Paleogene sandstones
In these structural closures, as well as the Miocene strata atop them, with no
success (a third wildcat, Koba, 100 miles on-strlke to the southwest was also
unsuccessful). It appears, from the unpublished seismic lines, that the traps
depend largely on somewhat weak fault closures which may not have been very
effective. The play area, within the basin as here defined, extends
approximately from a point 100 km west of mld-Aru Island northward to the
shore (the Terara Fault), approximately the Aru subbasln (fig. 71), an area of
about 3.5 million acres. It Is estimated from unpublished maps that the fault
closures make up 2 percent of the play area or 70,000 acres.
Stratigraphy
The stratigraphy of the Arafura and Salawati-BIntunI basins Is almost the
same; time-equivalent, IIthoIoglcaMy similar formations extend through both
basins (fig. 67).
As much as 40,000 ft of stratlgraphic section are exposed along the south
flank of Central Range (fig. 66). The sediments range In age from Paleozoic
to Pliocene. The Permian (Alfam Formation) Is probably the oldest entirely
unaltered sedimentary unit. This carbonate and clastic sequence has been
penetrated In several we Ms and seen In outcrop; In general, It appears to be
of an Interior platform fades. It has low organic content and poor to very
poor reservoirs.
The overlying Trlassie to mId-Jurassic strata are largely terrestrial
sediments (the TIpuma Formation), which appear to be laid down In a rifted,
attenuated-crust environment preceding the final separation of the Australian-
New Guinea block from a continental block to the north.
Mid-Jurassic to upper Cretaceous rocks are marine shelf sandstones and
shales (the Kembelangan Group), thinning southeastward onto the north-sloping

143
Australian Shelf. The plnchout line runs west-southwest from about KumbaI-1
(where It Is absent) to south of Aru Island where, as the wedge progressively
thins, the plnchout line swings southwestwards (fig. 71). These elastics are
derived from the Australian continent to the south.
From late Cretaceous through Miocene there was a tectonlcally quiescent
period, and the section was dominated by carbonates (New Guinea Limestone
Group) on the same shelf. The upper unit of this group, the Kals Formation,
Is often In a reef a I fades and Is considered a principal reservoir formation
of the basin.
Immediately overlying and In part equivalent to the Kals Formation Is a
section of marly shales with some carbonates, sourced from the north, which
form In local subbaslns where Miocene subsidence has been greater. In the
Arafura basin these shales are variously called the Klasefet, Aklmeugah, and
Iwur shales (fig. 67). They occur In three separate subbaslns from west to
east along the depoaxls of the basin, the Aru, Aklmeugah, and Iwur subbaslns
(fig. 71). Similar to the BIntunI and SalawatI subbaslns, these subbaslns of
reef-sealing shales define the areas of Miocene reef play. The Arafura
Miocene subbaslns, as here defined, have an area of 60 percent of the Arafura
basin or about 20 million acres.
Overlying the Cretaceous to Miocene carbonates and marly shales Is a
section of Pliocene-Pleistocene elastics derived from the Central Range In the
north (Buru Formation). They Immediately overlie the Klasafet, Aklmeagah, or
Iwur shales In the structurally lower subbaslnal areas, and the New Guinea
Limestone Group carbonates In the Intervening areas (fig. 66).
Reservoirs
Potential reservoirs exist In three general zones, the same as the
reservoir zones of the better known SalawatI-BIntunI basin. They are: 1) the
sandstones of the mid-Jurassic to Cretaceous Kembelangan Group, 2) carbonate
reservoirs (reefs and banks) of the Miocene upper New Guinea Limestone Group
(the Kals Formation), and 3) PIlo-Plelstocene sandstones (Buru Formation).
Kembelangan Reservoirs
Little specific Information Is available concerning Kembelangan reser-
voirs within the basin. The sandstones appear to be thin and sparse In the
lower part. Some potential reservoirs seem to exist In the middle part, but
the well sorted; clean sandstones (as seen In outcrop) appear to be mainly In
the upper part of the Kembelangan Group.
In Papua New Guinea, 100 miles east of the boundary, wildcat Juha-2
tested two zones resulting In a potential flow rate of 24 and 26 MMCFGD with
condensate flows of 1,680 and 1,900 BCPD respectively, Indicating good
reservoir sandstone (Katz and Herzer, 1985).
For evaluation purposes, an average effective pay of 200 ft with perhaps
20 percent porosity Is estimated for the Kembelangan sandstones of the Arafura
basin.
New Guinea Limestone Reservoirs
The carbonate reservoirs at the top of the New Guinea Limestone Group,
I.e., the Kals and basal Aklmeugah (and equivalent) Formations, have been
penetrated In ASA-IX and ASB-IX and found to have zones of porosity ranging
from 12 to 25 percent but with rather low permeability (5 md).
For the Salawatl-BIntunI basin (for which there are many more published
observations of reservoirs at an equivalent horizon), an average effective pay

144
of 165 ft and a porosity of 20 percent was estimated. For the Arafura basin,
where reefa I buildups are not so obvious, a lower average pay thickness, say
80 ft, In the Aru, Aklmeugah, and Iwur subbaslns Is expected. Porosity of 20
percent Is assumed.
The reef-trap area would be only half as prevalent as In the undoubtedly
more developed reef fades In the Salawatf subbasln, or about 3 percent of the
20-mI11 Ion-acre play area, I.e., 600,000 acres.
Bum Reservoirs
Reservoirs In the Pliocene Buru Formation are reportedly poor In the
Arafura basin; however, In the adjoining Salawatl-BIntunI basin where more
data are available, the geologically comparable Klasafet Formation Is
estimated to have an average effective pay of 100 ft with an average porosity
of 20 percent. In the absence of data, these assumed parameters also apply to
the Buru Formation of the Arafura basin.
Seals
The Cretaceous sandstones appear to be associated with an adequate
thickness of Interbedded shales to seal to some extent any potential petroleum
accumulation. Likewise, the Pliocene-Pleistocene sandstones are accompanied
by sufficient shales to ensure some sealing. The Miocene carbonates, however,
are probably only adequately sealed where they are covered by Miocene marly
shales (I.e., the Klasefet, Aklmeugah, or Iwur Formations). These shales are
developed and preserved In three or more subbaslns along the depoaxls of the
Arafura basin (fig. 71). Outside these local basins, the more clastic
Pliocene-Pleistocene rocks (Buru Formations) rest directly on the New Guinea
Limestone Group, providing only minimum and late seal.
Source Section
Source rock occurs In the Cretaceous (Kembelangan) shales and mudstones
and In Aklmeugah and Iwur marly shales and Is discussed In detail below.
Petroleum Generation and Migration
Richness of Source
Unpublished studies report on the basis of meager evidence that the pre-
Kembelangan Group (I.e., pre-upper Jurassic) strata, with minor exceptions,
are generally poor In organic content. The Kembelangan Group (upper Jurassic
to Paleocene) has fair to very good levels of organic richness In Its middle
and basal parts. The Miocene Aklmeagah Formation Is found to have fair levels
of organic carbon (TOC values of 0.5 to 1.32 percent).
Depth and Volume of Source Rock
Reportedly, wildcat ASM-IX (fig. 71) encountered rock of somewhat less
than thermal maturity (considered to be Ro = 0.7 percent) at 10,000 ft In the
Affam Formation (Permian). Thermal gradients from two other wildcats are
available, 1.65°F per 100 ft at Jaosakor-1 and 3.2°F per 100 ft at ASA-IX
(3.2°F per 100 ft seems anomalously high, perhaps owing to Its position on the
edge of the Aru Trough). Using 1.65°F per 100 ft together with an estimated
average PIlo-Plelstocene subsidence rate of 750 ft per million years, the top

145
of the mature zone Is Indicated to be around 11,000 ft. At this depth, the
thermally mature source rock Is limited to the pre-Tertlary and relatively
organic-rich Kembelangan Group In a narrow zone at the base of the foothills
of the Central Bange. The volume of mature source rock Is estimated to be
around 3,500 ml .
011 versus Gas
No data are available, but discovery wildcat, Juha-2, drilled some 100
miles on strike to the east In Papua New Guinea, produced from strata
equivalent to the upper Kembelangan Group gas and condensate flows of 24 and
26 MMCFGPD, accompanied by 1,680 and 1,900 BCD, respectively (Katz and Herzer,
1985). There Is a small oil seep Just outside the western end of the basin
(Kembelangan). The average petroleum mix of most of the basin Is estimated to
be 30 percent oil and 70 percent gas. In the more poorly sealed Aru hinge
area, the mix Is 50 percent oil.
Migration Timing versus Trap Formation
The thermal gradient Is assumed to have been fairly constant since the
Mesozolc, but the subsidence rate appears to have accelerated In the Pliocene-
Pleistocene thereby accelerating the heating of the source rock and Inducing
petroleum generation. The beginning of substantial generation probably did
not occur until the Pliocene.
The principal trap formation apparently occurred In three episodes: 1)
Jurassic rifting resulting In horsts and tilted fault blocks later draped by
Jurassic-Cretaceous sediments, 2) Carbonate reef and buildup formation In
middle to late Miocene, 3) compresslonal folding developed with continental-
Island arc collision In late Miocene-early Pliocene, and 4) drag folding along
wrench faults active during the Pliocene to present.
It would appear that the Mesozolc drape closures may have been early to
most effectively trap the predominantly Pliocene petroleum before reservoir
deterioration, but the compresslonal and drag folds formed at a near optimum
time to entrap any petroleum.
Plays
There appear to be two principal drilling objectives In the Arafura
basin: Cretaceous to Tertiary sandstones and Miocene carbonate reefs and
banks.
The Cretaceous sandstones are presumably (1) draped over fault-block
structures of Jurassic-Cretaceous age, (2) folded In Pliocene-Pleistocene
compresslonal anticlines, (3) folded In drag anticlines, and (4) fault-trapped
In the Pliocene-Pleistocene faulted Aru arch and hlngellne area. Each of
these trap types can be considered a separate play, but since the drapes are
only surmized (and In any case are likely to be altered by later tectonics)
and the drag folds In many cases cannot be distinguished from the
compresslonal folds, they have been lumped Into a single anticlinal trap play.
Therefore, only three plays are considered In the analysis.
1. Anticlines (Involving Cretaceous to Paleogene sandstones) (11.5 MMA)
2. Miocene Reefs (20.0 MMA)
3. Aru Hinge area (Involving Kembelangan sandstones) (3.5 MMA)

146
 Waropen Basin
Location and Size
The Waropen basin Is In northeastern Irlan Jaya. It extends eastward
from Cenderawaslh (Sarera) Bay to the Papua New Guinea border and southward
from the Pacific Ocean to the Central Range. ,lt has an area 24,000 ml and a
sedimentary volume of approximately 40,800 ml (figs. 1, 63, and 74).
The basin Is defined here to Include only the post-melange and post-
Island arc sediments, I.e., post-Auwewa (Olfgocene) Formation (fig. 75).
The basin has four structural lows or subbaslns (fig. 74). Although ft
Is not done here, some authors have designated the two deeper (4 km) subbasfns
as separate basins, the "Waropen basin" to the north of the Sorong Fault and
the "Wafpago basin" on the east shore of Cenderawasfh Bay.
Exploration and Production History
The Waropen basin was explored from 1935 to 1959 by a Shell group
culminating In the drilling of three wells, Mamberamo-1, Nfengo-1, and Gesa-2.
Mamberamo-1 was only a stratfgraphic test; NIengo-1 tested methane with no
higher hydrocarbons; and Gesa-2 also tested methane with no higher
hydrocarbons. Resumed exploration In the early seventies of the offshore,
along the east side of Cenderawaslh (Sarera) Bay, by a Tesoro-Arco group
resulted In six 1973 wildcats, A-1, E-1, H-1, 0-1, P-1, and R-1. R-1 tested
21.6 MMCFGD plus 402 BOPD. Production sharing contracts of the western part
of the basin are currently held by Shell and Phillips. Shell drilled three
dry wildcats In 1985. The exploration of this basin Is Immature; the success
rate to date Is nil.
Structure
General Tectonics
The Waropen basin as defined here Is made up of upper Miocene to Recent
sedimentary rocks overlying Island-arc and melange material resting on oceanic
crust. During the Paleogene, the oceanic plate which bore the Australian
continental block, subducted northward under an Island arc (now apparently
represented by the mountains along the north edge of Irlan Jaya). After
further subductfon, In the early Neogene, the continental block of Australia
collided with the Island arc and the melange material which had accumulated In
front (I.e., south) of It. This raised the continental edge, the Central
Range, and caused sediments to wash northward Into the structural low of the
Waropen basin between the Central Range and the accreted Island arc, I.e., the
northern ranges. Plate movement down the north-dipping subduct Ion zone ceased
with the arrival of the buoyant Australian continental crust. The regional
north-south compression was apparently then taken up In a new, reversed, I.e.,
south-dipping, subductfon zone. The trace of the new subductfon zone fs off
the north coast of Irfan Jaya, and ft dfps southward under Irlan Jaya,
Including the Waropen basin and Island arc now accreted to the New Guinea-
Australian continent (fig. 74).
This essentially north-south compression apparently has a strong, more
recent, sfnfstral component, the Pacific plate pushing westward. Recognizable
fragments of the Australian continental crust have been wrenched westward and
now form part of the Sulawesi (Celebes), Ceram, Buru, and smaller Islands of

147
0° -

CEDARAWAS1H

SUBDUCT/ON

NEW GUINEA - AUSTRALIA CONTINENTAL CRUST

134 138°

Figure 74.-- Map showing tectonic elements, isopach of Neogene sediments, wildcats and Outcrop
stratigraphic column locations (fig. 75) Waropen ba'sin, Irian Jaya. From Hamilton (1979)
 WEST JAPEN MUM MAMBERAMO-I MAMBERAMO CANYON TEER RIVER EAST

FEET-METERS
^A/W\A1 0 -r 0

E MEMBER
SUB - RECENT (coarse graywackies) - 1000

5000 -

MAMBERAMO FM.
PLEISTOCENE - 2000
Cundifferentiated D MEMBER
elastics) a: PLEISTOCENE
(claystone and siltstone) O

0 I 0,000 -' 3000

oo
MIO-PLIOCENE HOLLANDIA FM. C MEMBER
(dark graywackies)
(carbonates) m PLIOCENE
- 4000
<
AUWEWA FM.
(VOLCANICS) 15,000 -
OLIGOCENE
(SOME MIOCENE) WWVJ
- 5000
PALEOGENE ISLAND ARC MEMBER
and carbonates)
MATERIAL

CAUWEWA FM.)
- 6000
20,000 H
BASEMENT
MAKATS FM. MIOCENE
C graywackies sandstone)

) oil seep
Vertical scale 1:50,000

Figure 75.--Stratigraphic columns along north flank of Waropen basin; location of columns (fig. 74),
columns from Visser and Hermes (1962). Sections from Visser and Hermes (1962).
eastern Indonesia. Large west-trending slnlstral wrenches cut northern and
central Irlan Jaya (fig. 74).
The Waropen basin Is structurally complicated, but most of the potential
structural traps appear to fall Into three groups: 1) drag folds associated
with the largely unmapped but presumably numerous, west-trending wrenches that
are believed to transect the entire basin, 2) carbonate buildups and drapes of
Pliocene sand reservoirs over the rugged Paleogene Island-arc topography (fig.
74), and 3) dlaplrlc, seml-dlaplrlc, and other flow structures affecting the
thick Pliocene Mamberamo shales.
For assessment purposes It Is assumed that the wrench folds are the
primary trap structure and, In the absence of more data, these are lumped with
the dlaplrs, some or all of which may be Initially of drag-fold origin. On
this assumption, the basin would be structurally analogous to the Central
Sumatra Basin, which Is also much affected by wrench faulting and drag folding
and which Is deemed to have a structural trap area making up 5.5 percent of
the play area. By this analogy, there should be 845,000 acres under drag-fold
trap In this play, which Is assumed to cover the entire Waropen basin.
The drape reef structure play area would be limited to the burled part of
the Paleogene Island arc ridge (fig. 74). This dlscontlnous, fragmented ridge
trends east-southeast from Blak Island through the Mamberamo-1 and NIengo-1
wells and approximately along the north coast of Irlan Jaya; the sedimentary
thickness Is generally less than 6,000 ft (2 km) but more than 3,000 ft (1 km)
(fig. 74). An area of 2,500 ml or 1.6 million acres Is estimated.
Structures In this area would be burled topographic highs on the old volcanic
arc surface, perhaps altered by faulting, particularly slnlstral wrench
faults. From an unpublished map, It Is estimated that closed highs make up 18
percent of the area or 288,000 acres. These highs are the loci of reef
development and drape closures.
Stratigraphy
The Waropen basin, formed between an Island arc and a continental block
In the Miocene, Is underlain by melange, Island-arc volcanic material, and
oceanic crust. The fill Is Miocene to Recent largely clastic sediments
derived largely from the Central Range to the south, and to a lesser extent
from the Island arc to the north.
The fill Is largely In two units. The lower unit Is a Miocene marine
clastic formation (Makats Formation). This formation Is up to 6,000 ft thick
and made up primarily of graywackes or subgraywackes with some marl and
carbonate Intercalations. A combination of graded bedding and deep-water
fauna Indicates the strata may be mainly turbldltes. Detritus of slllclfled
claystone, abundant Mesozolc mlcrofosslls and metamorphlc rock, combined with
a low volcanic content suggests the formation Is derived from the Central
Range to the south rather than the volcanic arc to the north. The Makats Is
rather highly faulted compared to the overlying formations. Reportedly Tesoro-
Arco have found the Makats Formation to be so tectonfzed that It was
considered economic basement. It should be noted, however, that the only
appreciable oil seep (figs. 74 and 75) seems to derive from this formation.
It appears that although the Makats Formation would not have significant
reservoirs (owing to graywacke fades and to tectonlzatlon), It may have some
source capability.
Overlying the Makats Formation, probably unconformably, Is the second
unit, a Pliocene-Pleistocene formation, defined by Vlsser and Hermes, 1962,
I.e., the Mamberamo Formation, which variously overlies the Miocene elastics

150
of the Makats Formation, Island arc volcanlcs (the Auwewa Formation), and
oceanic crust. It Is primarily elastics with some Intercalations of limestone
(fig. 75). It has a full thickness of some 20,000 ft and Is In four members
where sedimentation was most complete: (B) a lowest member of marls and
carbonates with slltstones, (C) a graywacke and sandstone member, (D) a
claystone member with both abundant foramlnlfera and plant remains, and (E) an
upper member of graywackes. Probably the C member offers the best chance for
adequate reservoirs. Volcanic material Is essentially absent, and It Is
concluded that most of the sediment Is derived from the south rather than from
the volcanic arc to the north. The amount of sand In the section appears to
lessen northward.
Northward toward the higher part of the relict Paleogene Island arc, the
Mamberamo Formation elastics thin and are replaced with shoal carbonates, the
300-foot thick Hollandla Formation (fig. 75) Indicating that In the Pliocene
the area of the old arc was still a positive area.
Reservoirs
The Makats apparently has little appreciable reservoir, limiting
reservoir occurrence to the Pliocene Mamberamo Formation. The Mamberamo
Formation has some sandstones, but they are generally of a graywacke type and
therefore poor reservoirs. Since the sandstones would be largely derived from
the upraised Central Range to the south containing considerable melange and
oceanic crust, good quartz sandstone Is not abundant. The sandstones thin
northward; sandstone beds, which commonly reach 500 to 600 ft In gross
thickness In the E-1 and H-1 wildcats to the south, do not exceed 30 ft In the
northern R-1 well. Sandstones appear to be largely concentrated In the "C"
and "E" Members. The "C" Member of the E-1 well reportedly Is 30 percent
sandstone. One hundred ft appears to be a reasonable average net sandstone
pay. Porosities would be fair to poor; probably the average would have
porosities of about 20 percent.
The other reservoirs are In the Hollandla or equivalent Pliocene-
Pleistocene carbonates, which occur Intermittently on topographic highs along
the Paleocene Island arc ridge. Wildcat 0-1 found 735 ft of limestone with
three zones of porosity as Indicated by gas-cut water flow. On other highs,
R-1, NIengo-1, and Mamberambo-1, the limestone Is missing, but there are
Mamberamo draped sandstones. NIengo tested gas from a 110-foot thick
sandstone and R-1 tested from a 22-foot thick sandstone. There are
Insufficient available data to separate the highs having carbonate buildup
from those having only draped sandstones. It Is estimated that the average
reservoir over a high would have 80 ft of effective (sandstone or carbonate)
reservoir. A porosity of 20 percent Is assumed.
Seals
The Mamberamo Formation Is made up largely of low permeability shale as
measured In outcrops and as attested by overpressured shale found In at least
some of the wildcats drilled, e.g. Gesa, E-K?), and H-K?). Wildcat Gesa
found overpressure at 6,000 ft. E-1 and H-1, as well as Gesa, apparently
tested dlapfrs or flow-effected closures. The presence of overpressured shale
Is not only a seal but It strongly Inhibits primary migration to all hydro-
carbon but gas.

151
 Shell (Visser and Hermes, 1962) believed that extensive faulting
generally precluded adequate cover In many places, and this may be true, at
least In the perimeter of the basin.
The Pliocene reefs along the north rim of the basin partly outcrop or are
only thinly covered. A good part, probably half the reef play, falls outside
of and north of the 1-km Isopach of the Waropen basin (fig. 74).
Source Section
Whether or not there Is sufficient source rock to support considerable
amounts of petroleum Is a moot point. If there Is any, It would be In the
basal part of the Mamberamo or In the Makats Formation. See discussion below.
Petroleum Generation and Migration
Richness of Source
Marly shales near the base and dark gray shales with lignite streaks near
the top of the Mamberamo Formation could contain sufficient organic material,
but the Shell group (Visser and Hermes, 1962), who originally Investigated
this basin prior to 1962, concluded an "apparent poverty of source material"
after testing "geochemlcally w the shales penetrated by wildcat Gesa. Later
unpublished T.O.C. values largely between 0.5 and 1.0 percent Indicate rather
meager organic richness. Taking Into account the apparent rapid deposition
(500 or 600 ft per million years) In the deeper parts of the basin, organic
material may be too diluted, particularly for oil.
The only appreciable oil seep In the vicinity of the Teer River appears
to emanate from the Miocene Makats Formation. Although the Makats may be too
tectonlzed to trap appreciable amounts of petroleum, It may, under some
circumstances, be a source.
Depth and Volume of Source Rock
There are little data concerning thermal maturity of the basin sediments.
Vltrlnlte reflectance of samples from wells E-1 (7,508 ft) and H-1 (depth ?)
Indicates Immaturity.
Only one thermal gradient Is available; wildcat H-1 reportedly had a
thermal gradient of 1,34°F per 100 ft. This low value seems about right for
what Is essentially a fore-arc basin and Is assumed to be the average for the
entire basin. The Neogene fill has an average depth of 10,000 ft (3 km) (fig.
74), giving average subsidence of 400 ft per million years. With this
subsidence and thermal gradient, the average top of the thermally mature
sediment Is estimated to be at about 15,000 ft (4.5 km). This would allow
only little mature rock In the basin restricted to only the deepest part of
the sedimentary fill. However, the melange formation could generate some
petroleum. It appears that a small volume of thermally mature sediment Is the
principal limiting factor to the amount of petroleum resources In this basin.
On this basis, the average petroleum fill of any trap Is estimated to be only
20 percent.

152
 011 versus Gas
Most of the wildcats drilled to date have encountered some gas, but
reportedly, the gas was dry and no appreciable oil shows have been seen. Oil
seeps occur In the areas of outcropping Makats Formation.
The Mamberamo Formation Is largely shale, and the Indications suggest
that much of the shale Is overpressured. This condition Inhibits primary oil
migration, and It, together with wildcat shows, Indicates the basin to be gas
prone. For assessment purposes, It Is estimated that the oil and gas mix In
most of this basin Is 80 percent gas and 20 percent oil. The drapes and reefs
over the topographic highs of the burled Island arc surface to the north,
however, are not overpressured and more likely to leak and are, therefore,
deemed less gassy, I.e., 60 percent gas.
Migration Timing versus Trap Formation
Generation and migration of gas and oil would have started relatively
recently In this cool basin, which has barely subsided sufficiently so that
the lowest sediments have reached thermal maturity.
The principal structural traps, I.e., drag folds, are also relatively
young, having reached their effectiveness In the Pliocene when wrench faulting
became most pronounced. So the drag fold timing was favorable, forming traps
at about the same time migration began.
The older reefs and drape features over the Pa I eocene Island-arc
topography were formed In the Miocene, and the associated reservoirs may have
deteriorated to some extent before Pliocene or younger, necessarily long-
distance migration affected these shallow traps.
Plays
The two principal plays considered In detail In the analyses are:
1. Petroleum accumulating In Pliocene sandstones In drag folds
associated with east-west slnlstral wrench faults, which transect the entire
basin. DIapIr folds are, because of data-lack, Included In this play.
2. Petroleum accumulations In reefs or draped sandstones localized by
topographic highs on the burled Paleogene Island-arc surface. Play area Is
taken to be the shallow-basin area approximately along the northern coast.
PLAY ANALYSIS SUMMARIES
One-page summary play analysis for each basin or play follow In the same
order as the pertinent geology Is discussed In the text. Estimates of the
five principal geologic factors, which have been discussed and quantified In
the text, are summarized. Estimates are given In ranges to show the degree of
certainty. The ranges Include three values, a low number (95 percent
probability the quantity will exceed that value), a most likely quantity, and
a high number (5 percent probability the quant!ty will exceed that value).
For conciseness, only the rationale for arriving at the most likely (mode)
estimate Is discussed.
The product of the most likely values for each of the key factors
generally Indicates the quantity of undiscovered oil and gas resources. This
product Is shown at the base of the tabulations for each play. The overriding

153
I imltlng factor, or factors for each play, used as a Judgement check on the
estimates Is shown at the bottom of the remarks.
In addition to the principal basins and plays discussed In the text,
there are play analysis summaries for four marginal basins; South Makassar,
Sumatra, Outer Arc, Java Outer Arc, and Bone-Senkeng.
The summary play analyses served as guides to the consensus estimates of
the amount of undiscovered petroleum In the basins of Indonesia.

154
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN North Sumatra, No. 1 COUNTRY Indonesia PLAY Deep Reef No. 1
AREA OF BASIN (Mi 2 )337000 AREA OF PLAY (MMA) 0.55
VOLUME OF BASIN (Mi 3!97,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 2.1 BBO* 16.25 TCFG .755 BBNGL 14.25 TCFG
TECTONIC CLASSIFICATION OF BASIN: Back Arc

DEFINITION AND AREA OF PLAY: Gas accumulation in lower Miocene carbonate reefs and
banks on platforms developed over horst blocks. Play area is about .55 million acres
(area 1, fig. 6).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .03 .071 .10
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 3 12 12
C. AVERAGE EFFECTIVE PAY (feet) 100 350 500
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 0.1 5 10
E. OIL RECOVERY (BBLS/AF) 150 190 300
F. GAS RECOVERY (MCF/AF) 1,000 1,650 2,000
G. NGL RECOVERY (BBLS/MMCFG) 11 53 100
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .028 BB, GAS 4.674 TCF, NGL .248 BB, OE 1.055 BBOE

REMARKS
A. Reefs have grown on higher parts of a carbonate platform over an irregular
surface. Some reefs have coalesced forming reef complexes (e.g., Arun complex
of 42,000 acres). Thirteen percent of play area is estimated to be untested
closure, or about 71,000 acres.
B. Future success rate estimated to be about 20 percent. Gas fill at Arun Field
is 60 percent, which is assumed as average for play. On this basis, gas-contain^
ing closure is 12 percent of untested trap area.
C. Arun gas reservoir is 503 ft but is probably the thickest of the play. An
estimated average pay thickness for the play is about 350 ft.
D. No oil is produced at Arun, or from other tests of these reefs. Enveloped
as they are in overpressured shale, little oil would be expected.
E. Assuming the reservoir parameters of Arun are average for the play 16 percent
porosity, 17 percent water saturation, primary oil recovery would be 190 barrels
per acre-foot.
F. Gas recovery rate, enhanced by the effects of overpressure, reportedly averages
about 1,650,000 ft 3 per acre-foot at Arun, which is assumed to be average for
the play.
G. Gas-condensate ratio at Arun is 53 barrels per million cubic ft of gas, which
is assumed to be the average for the play.
Limiting Factor: Overpressured shales have inhibited primary oil migration into
the reef reservoirs.
Total resources of all plays in basin: .36?. R80, 9.0 TCFG, .412 BBNGL, 2.274 BBOE
* Includes NGL.

155
 PLAY ANALYSIS SUMMMARY OF UNDISCOVERED PETROLEUM

BASIN North Sumatra, No. 1 COUNTRY _____

Indonesia PLAY Neogene Sandstones, No. 2
AREA OF BASIN (Mi 2 ) 33,000 AREA OF PLAY (MMA) 5.6_____
VOLUME OF BASIN (Mi 3 ) 97,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 2.1 BBO 16.25 TCFG 1.1 BBO ? TCFG
TECTONIC CLASSIFICATION OF BASIN: Rack Arc
DEFINITION AND AREA OF PLAY:Petroleum accumulations in middle Miocene to lower
Pliocene sandstones folded in Neogene anticlines. Play area approximately coincides
with basinal part of basin, as opposed to shelf, and covers 5.6 million acres (area
5, fig.6).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .056 .116 .140

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 2.5 5.6 10.0
C. AVERAGE EFFECTIVE PAY (feet) 30 150 300
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 40 60 75
E. OIL RECOVERY (BBLS/AF) 100 190 350
F. GAS RECOVERY (MCF/AF) 1,600 840 075
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .111 GAS .327 TCF, NGL .004 BB, OE .170 BBOE

REMARKS
A Extrapolation from a nap of part of play (area "A", fig. 9) indicates that about
8.3 percent of area is under closure. Since the play is deemed 75 percent
explored, 2.1 percent of play area remains untested trap.
B. Wildcat success rate for one operator from 1967 to 1979 was 14 percent, which
is assumed to be average for play. The area! fill is estimated to average 40
percent, indicating about 5.6 percent of untested trap area to be productive.
C. Reservoir sandstones range through three formations, Miocene to Pliocene; maximum
gross thickness in principal reservoir formation, the Keutapang Formation, is
468 ft in 14 zones, averaging 10 to 20 ft thick. I estimate 150 ft as an
average net pay.
D. There are no data as to gas versus oil production because gas has been flared
since 1900. Gas/oil ratios vary. Estimated fill is 60 percent oil.
E. Based on an estimated low average porosity of IB to 20 percent (shaly reservoirs),
and assumed 25 percent water saturation, primary oil recovery is estimated to be
190 barrels per acre-foot.
F. Assuming the same reservoirs, an average depth of 7,000 ft, and a temperature
gradient of 2.5°F, gas recovery is estimated to be 840,000 ft-* per acre-foot.
G. World average figures.

Limiting Factors: Meager source richness (see text), shaly reservoirs, and
impeded oil migration by overpressured shale.
Total resources of all plays in basin: .362 BBO, 9.0 TCFG, .412 BBNGL, 2.274 BBOE

156
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN North Sumatra, No. 1 COUNTRY Indonesia PLAY Shallow Shelf Reefs,No. 3
AREA OF BASIN (Mi 2 )33,000 ~~ AREA OF PLAY (MMA) 2.7
VOLUME OF BASIN (Mi 3 ) 97,000 * PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 2.1 BBO 16.25 TCFG _.25 BBO 2 TCFG
TECTONIC CLASSIFICATION OF BASIN: Back Arc * Est. only no production
established
DEFINITION AND AREA OF PLAY: Oil and gas accumulations in Miocene carbonate build-
ups on the relatively shallow foreland shelf. Area of play appears limited to the
northern fourth of shelf or about 2.7 million acres (area 3, fig. 6).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .02 .047 1.200
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 6 18 25
C. AVERAGE EFFECTIVE PAY (feet) 100 200 700
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 20 25 50
E. OIL RECOVERY (BBLS/AF) 130 237 290
F. GAS RECOVERY (MCF/AF) 400 770 1,000
G. NGL RECOVERY (BBLS/MMCFG) 7 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .100 BB, GAS .977 TCF, NGL .011 BB, OE .274 BBOE

REMARKS
A. Extrapolation from published (McArthur and Helm, 1982) and unpublished maps
indicate that approximately 3.5 percent of the play is reefal trap area of
which about half has been tested.
B. From published cross sections (McArthur and Helm, 1982), the petroleum fill
appears to average about 80 percent. Wildcat success rate is high, 66 percent,
but i estimate this will decline to about one-third (22 percent), giving a
productive area of about 18 percent of the untested trap area.
C. Reportedly, petroleum columns vary up to 680 ft. Perhaps a good average would
be 200 ft, including the smaller reefs.
D. Four oil and four gas discoveries have been made. On basis of a published map
(McArthur and Helm, 1982), it is estimated that on an areal basis, oil is 25
percent of the oil-gas mix.
E. Porosities range from 7 to 31 percent (McArthur and Helm, 1982). They estimate
an average of 22 percent. Permeability is appreciably affected by fracturing
Assuming 25 percent water saturation, the primary oil recovery would average
237 barrels per acre-foot.
F. Assuming same reservoir, an average depth of 5,000 ft and a temperature gra-
dient of 2.5°F per 100 ft, about 770,000 ft 3 per acre-foot would be produced.
G. World-wide average.
Limiting Factor: Probably the small size and shallowness of the reefs may
preclude economic production, particularly of gas, in some cases.
Total resources for all plays in basin: .362 BBO, 9.0 TCFG, .412 8BNGL, 2.274 BBOE

157
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN North Sumatra, No. 1 COUNTRY Indonesia PLAY L. Miocene Shelf

AREA OF BASIN (Mi 2 )33,000 Sandstones No.
VOLUME OF BASIN (Mi 3 ) 97,000 AREA OF PLAY (MMA)O
ESTIMATE ORIGINAL RESERVES 2.1 BBO 16.25 TCFG PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Back Arc .. BBO, TCFG

DEFINITION AND AREA OF PLAY:Petroleum in lower Miocene sandstones and calcarenites

in drapes over north-trending basement knobs of shelf. Play extends over foreland
shelf exclusive of northern fourth where reefs dominate. Play has an area of some
8 million acres (area 4, fig. 6).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .050 .120 .200
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 4 6 12
C. AVERAGE EFFECTIVE PAY (feet) 50 150 600
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 20 55 80
E. OIL RECOVERY (BBLS/AF) 100 160 400
F. GAS RECOVERY (MCF/AF) 400 520 800
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .095 BB, GAS .253 TCF, NGL .003 BB, OE .140 BBOE

REMARKS

A. From unpublished maps of part of onshore area, it has been estimated that perhaps
2 percent of play area, or 160,000 acres, is under trap. Onshore exploration
has found six gas and oil accumulations of only marginal economic size. Onshore
and offshore perhaps 20 drapes, or about 40,000 acres of closure have been tested
leaving an untested trap area of 120,000 acres.
B. The discovery rate of one operator is 47 percent, but the discoveries are of
marginal economic size and the wells may include step-outs or appraisals. A
true future discovery rate might be 20 percent. Trap fill varies widely re-
flecting uneven carbonate cementation on one hand and flushing on the other; I
estimate an average of 30 percent, giving a productive area of 6 percent.
C. Pay thickness is very irregular depending on the amount of cementation or flushing
From unpublished data, the average effective pay is estimated to be about 150 ft.
D. Two of the small discoveries are reported as gas, four as gas and oil. I
estimate the trap area is about 55 percent oil.
E. Recovery tends to be low because of carbonate cementation. I estimate 15
percent average porosity and water saturation of 25 percent, indicating about
160 barrels per acre-foot.
F. Assuming same reservoirs, average depth of 5,000 ft, and a thermal gradient of
2.5°F per 100 ft, gas from an acre-foot of reservoir would be 520,000 ft .
G. World-wide average.
Limiting Factors: Uncertain reservoir quality, flushing, access of hydrocarbon to
reservoirs in primary migration.
Total resources of all plays in basin: .362 RBO, 9.0 TCFG, .412 BRNGL, 2.274 BROE

158
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN North Sumatra, No. 1 COUNTRY Indonesia PLAY Paleogene Basal Drapes
AREA OF BASIN (Mi 2 ) 37,200 ______ No. 5
VOLUME OF BASIN (Mi 3l97,200 AREA OF PLAY (MMA)576
ESTIMATE ORIGINAL RESERVES 27T BBO 16.25 TCFG PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Back Arc 0 BBO, 0 TCFG

DEFINITION AND AREA OF PLAY:Petroleum accumulations in Paleogene basal sandstones

draped over horst blocks in deeper, basinal part of North Sumatra basin, these
sands being missing from foreland shelf. Play area is approximately 5.6 million
acres (area 5, fig. 6).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .112 .308 .560
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 2.0 3.5 5.0
C. AVERAGE EFFECTIVE PAY (feet) 50 100 300
n. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 5 10 20
E. OIL RECOVERY (BBLS/AF) 50 130 300
F. GAS RECOVERY (MCF/AF) 800 1,170 1,300
G. NGL RECOVERY (BBLS/MMCFG) 11 53 100

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .014 BB, GAS 1.135 TCF, NGL .060 BB, OE .26 BBOE

REMARKS
From unpublished maps of part of play, I estimate that the untested trap area
is about 5.5 percent or .308 million acres.
Wildcat success to date is nil, but wildcats may have been largely positioned for
shallower primary targets. I assume wildcats targetted specifically on this
play would be more successful, perhaps 5 to 10 percent. Fill is estimated to be 50
percent (60 percent for equally deep Arun), indicating 3.5 percent of trap area
productive.
No data, but this would probably not be a limiting factor; I assume 100 ft.
The few slight shows encountered have been both oil and gas, but owing to the
play's deep basinal position either enveloped in overpressured shale (see text)
or within the zone of thermally overmature sediments, I estimate only 10
percent of petroleum is oil.
Where encountered, these reservoirs have been relatively poor, I estimate 12
percent average porosity and 25 percent water saturation.
F. Assuming same reservoirs as for oil, a temperature gradient of 3°F per 100 ft,
and a depth of over 10,000 ft in overpressured zone (7,100 psi in Arun), I
estimate 1,170,000 ft3 of gas would be produced per acre-foot.
G. I estimate the same gas-condensate ratio of Arun would prevail, i.e., 53
barrel/MMCFG.
Limiting Factors: Low porosity, and generally great depth and impedance of primary
oil migration by overpressured shale.
Total resources of all plays in basin: .362 BBO, 9.0 TCFG, .412 BBNGL, 2.274 BBOE

159
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN North Sumatra, No. 1 COUNTRY Indonesia PLAY Offshore Slope, No. 6
AREA OF BASIN (Mi 2 ) 37,200 AREA OF PLAY (MMA) 7.0
VOLUME OF BASIN (Mi 3"] 97,200 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 2.1 BBO 16.25 TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF BASIN: Back Arc
DEFINITION AND AREA OF PLAY: In the absence of any data, the play can only be
defined as possible petroleum accumulations in an appreciable volume of sediments,
which are part of a petroliferous basin. Area of play is about 7 million acres on
the north offshore slope of Sumatra (area 6, fig. 6).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .10 .42 .90
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 1 3 8
C. AVERAGE EFFECTIVE PAY (feet) 50 100 500
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 1 7.5 25
E. OIL RECOVERY (BBLS/AF) 100 150 300
F. GAS RECOVERY (MCF/AF) 800 1,400 1,800
G. NGL RECOVERY (BBLS/MMCFG) 11 53 100
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .014 BB, GAS 1.63 TCF, NGL .086 BB, OE .371 BBOE

REMARKS
A. Structural trends of the onshore basin extend into play area though perhaps
diminishing away from the higher relief topography. Paleogene trends appear to
antedate the structural low north of Sumatra so that the Deep Reef and Paleogene
Basal Drapes may prevail. An area-weighted average of the percentage trap area
in the play is 6 percent.
B. The percentage of trap that would be productive is 5 percent if I average the
two deeper plays, but considering the likelihood of poorer reservoirs and less
developed structure, 3 percent is assumed.
C. The weighted average pay of the Deep Reef and Paleogene reefs is 140 ft, but
would perhaps be diminished in this further offshore position; I estimate
100 ft.
D. Analogous to the adjoining deep plays, it is deemed that only 7.5 percent of
the petroleum is oil.
E. Oil recovery would be about the same as for the adjoining deep plays or about
150 barrels per acre-foot.
F. Gas recovery also would about average that of the adjoining deep plays of North
Sumatra or about 1,400,000 ft 3 per acre-foot.
G. It is assumed that the NGL recovery would be about the same as Arun.
Limiting Factor: The overriding limiting factor may be the lack of adequate
reservoi rs.
Total resources for all plays in basin: .362 BBO, 9.0 TCFG, .412 BBNGL, 2.274 BBOE

160
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Central Sumatra, No. 2 COUNTRY Indonesia PLAY Lower Miocene Sandstones
AREA OF BASIN (Mi 2 )27,000 ______________No. 1
VOLUME OF BASIN (Mi^)29,000 AREA OF PLAY (MMA) 17.2
ESTIMATE ORIGINAL RESERVES 8.746 BBO 0.21 TCFG PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Back Arc 8.746 BBO 0.21 TCFG
DEFINITION AND AREA OF PLAY:Petroleum accumulations in lower Miocene deltaic sand-
stones which are affected by drag folding or draping. The play area includes practi-
cally all of the Central Sumatra basin (figs. 1, 11, 12).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .050 .236 .350
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 3.0 6.0 8.8
C. AVERAGE EFFECTIVE PAY (feet) 70 200 600
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 80 95 98
E. OIL RECOVERY (BBLS/AF) 260 350 500
F. GAS RECOVERY (MCF/AF) 400 760 1,000 -
G. NGL RECOVERY (BBLS/MMCFG) 8 11 22
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .942 BB, GAS .108 TCF, NGL .001 BB, OE .961 BBOE

REMARKS
A. Traps are sedimentary drapes, e.g., Minas and Duri Fields, or drag folds associ-
ated with wrenches. Extrapolation from field maps leads one to an estimate that
about 5.5 percent of the play is trap area. Assuming 75 percent of the traps
have been tested, untested trap area is 236,000 acres.
B. The wildcat discovery rate is about 22 percent but will probably decline. 'I
estimate that perhaps 15 percent of untested traps will contain petroleum. The
amount of fill varies from 22 percent to 100 percent; I estimate 40 percent may
be a good average. This indicates that about 6.0 percent of the untested trap
area contains petroleum.
C. Net effective sandstone reservoir thickness varies. It is often 200 to 400 ft
and may be as much as 800 ft. Perhaps 200 ft would be a good average in the
less favorable prospects remaining.
D. Gas to oil ratios appear unusually low (35 CFG/BO at Minas). Perhaps gas has
leaked from basin. I estimate undiscovered petroleum will be 95 percent oil.
E. Oil recovery varies with porosity, which ranges from 10 to 40 percent; it aver-
ages 27 percent at Minas, which I; take as average for the basin. The primary
oil recovery factor varies from a low of 7.4 percent at Dun" Field to pre-
sumably 25 percent. I estimate an average recovery of about 350 barrels per
acre-foot.
F. There is little gas potential, but assuming an average reservoir depth of 5,000
ft and given the temperature gradient of 3.7°F per 100 ft, I estimate 765,000
ft3 per acre-foot.
G. World-wide average.
Limiting Factors: The thorough exploration to date of relatively uncomplicated
geology and the apparently limited volume of source rock to
generate much more petroleum than already discovered.

161
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN South Sumatra, No. 3 COUNTRY Indonesia PLAY Lower Miocene Sandstones,
AREA OF BASIN (Mi'-), 18,300 ______________No. 1
VOLUME OF BASIN (Mi 3 ) 40TTO" AREA OF PLAY (MMA) 11.7
ESTIMATE ORIGINAL RESERVES 1.7 BBO 4.0 TCFG PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Back Arc 1.3 BBO 2.0(?) TCFG
DEFINITION AND AREA OF PLAY: Accumulations in 01igo-Miocene (Talang Akar Formation)
deltaic sandstones trapped in anticlines of drape or drag-fold origin. The play area
includes practically all of South Sumatra basin or some 11.7 million acres (figs. 15
and 18).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS L 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .050 .164 .250

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 3 5 20
C. AVERAGE EFFECTIVE PAY (feet) 50 200 500
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 40 50 60
E. OIL RECOVERY (BBLS/AF) 130 205 400
F. GAS RECOVERY (MCF/AF) 400 1,030 1,600
G. NGL RECOVERY (BBLS/MMCFG) 8 11 22

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .168 BB, GAS .845 TCF, NGL .009 BB, OE .317 BBOE

REMARKS

A. A structure map of part of area indicates traps make up 11.5 percent, but it is
in an area of concentrated fields; over the whole play I estimate that, by area,
traps may make up 7 percent. Assuming 80 percent of traps have been tested,
164,000 acres remain to be tested.

B. In recent years, the wildcat success rate has been about 10 percent where it is
likely to remain for some time. I estimate from oil field maps the average fill
is 40 percent, indicating 4 percent of trap area will be productive. There are
some prospects of stratigraphic traps (as Abab) perhaps raising percentage to 5.

C. Although the deltaic sandstones are discontinuous and lensing, I estimate an

average net thickness of 200 ft in the Raja Field and assume it to be a represen-
tative sample of the play.

D. Volume-wise the gas-oil ratio at Raja Field appears to be 3 to 1. Other fields

appear to have only small gas caps. I estimate 50 oil in the petroleum mix.

E. Porosity at Raja Field ranges from 15 to 23, averaging perhaps 19 percent.

Water saturation of 25 percent and oil recovery factor of 25 percent are assumed.

F. Assuming the same reservoirs, an average depth of 10,000 ft, and a thermal
gradient of around 2.15°F per 100 ft.

G. World-wide average.

Limiting Factor: Extensive exploration to date may have left few undiscovered
petroleum accumulations.
Total resources for all plays in basin: .250 BBO, 1.518 TCFG, .016 BBNGL, .518 BBOE

162
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN South Sumatra, No. 3 COUNTRY Indonesia PLAY Miocene carbonates,
AREA OF BASIN (Mi 2 ) 18,300 No.2
VOLUME OF BASIN (Mi 3"] 40,000 AREA OF PLAY (MMA) 11.7
ESTIMATE ORIGINAL RESERVES 1.7 BBO 4.0 TCFG PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Back Arc ? BBO 2.0(?) TCFG
DEFINITION AND AREA OF PLAY:Petroleum, mainly gas, accumulations in lower Miocene
(Baturaja) carbonate reefs and banks. The play area is taken to be practically the
entire basin (figs. 15, 18, and 19).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .070 .140 .250

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 2 4 10
C. AVERAGE EFFECTIVE PAY (feet) 50 170 300
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 5 30 30
E. OIL RECOVERY (BBLS/AF) 150 230 300
F. GAS RECOVERY (MCF/AF) 300 1,000 1,600
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .066 BB, GAS .666 TCF, NGL .007 BB, OE 184 BBOE

REMARKS
A. Extrapolation of a reef distribution map (fig. 11) indicates 1 percent of the play
area has identified carbonate buildup, but it is suspected that double this amount
will be discovered as the demand for gas increases and more advanced seismic tech-
niques become available. Assuming 40 percent of eventually discovered reef has
been tested, I estimate 140,000 acres of untested trap remain.
B. Recent wildcat success rate is 13 percent. The hydrocarbon fill of Baturaja
reservoirs in the Raja Field appears to be about 30 percent, indicating productive
trap area of 4 percent.
C. In the Raja Field, the Baturaja limestone "ranges from thin shaly limestone
sections to intervals of 170 ft of extremely porous limestone" (Basuni, 1978).
I assume 170 ft is an average thickness of limestone buildups of the basin.
D. The carbonate reefs are largely gas filled; however oil has been produced in some
recent discoveries (e.g., Ramba). I estimate oil makes up about 30 percent of
the oil-gas mix.
E. At the Raja Field, porosity averages 20 percent and water saturation 20 percent.
This is taken as an average for the play, indicating an oil recovery of 230
barrels per acre-foot.
F. Assuming the same reservoirs, an average thermal gradient of 2.15°F per 100 ft
and an average depth of 9,000 ft, the gas recovery would be about 1 million
cubic ft per acre-foot.
G. World-wide average.
Limiting Factor: The relative sparseness of reservoirs limits the amount of
petroleum in this play.
Total resources for all plays in basin: .250 RRO, 1.518 TCFG, .016 BBNGL, .518 BBOE

163
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN South Sumatra, No. 3 COUNTRY Indonesia PLAY Mio-PIJocene Sandstones,
AREA OF BASIN (Mi 2 L 18,300 _____________No. 3
VOLUME OF BASIN (Mi 3")40,000 AREA OF PLAY (MMA) 11.7
ESTIMATE ORIGINAL RESERVES 1.7 BBO 4.0 TCFG PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Back Arc 0.2(?)BBO TCFG

DEFINITION AND AREA OF PLAY: Petroleum accumulations in middle Miocene to Pliocene

sandstones in drag fold and drape anticlines. The area of play is approximately
that of the basin, i.e., 11.7 million acres (fig. 15).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .030 .082 .120

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 0.5 1.5 2.5
C. AVERAGE EFFECTIVE PAY (feet) 50 75 150
n. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 30 70 90
E. OIL RECOVERY (BBLS/AF) 150 250 350
F. GAS RECOVERY (MCF/AF) 100 300 600
G. NGL RECOVERY (BBLS/MMCFG) 8 11 22
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .016 BB, GAS .008 TCF, NGL .00 BB, OE .017 BBOE

REMARKS
A. In the absence of data, I assume the structure is approximately parallel to that
of the underlying early Miocene. However these sandstones have been eroded from
crestal portions of structures and have been subject to more intensive exploration
so that the trap area is only about half the untested trap-area of the early
Miocene play.
B. The wildcat success rate is low since this thoroughly explored play is now only
considered a secondary drilling objective. I estimate a 5 percent wildcat
success and assume a 30 percent fill, indicating 1.5 percent of the untested
trap is productive.
C. In the absence of any data and considering the small amount of production, I
estimate a net pay thickness of 75 ft.
D. The percent of oil in the petroleum mix would initially be the same as the 01igo-
Miocene play except probably more gas has escaped these shallow sandstones. I
estimate 70 percent oil.
E. Assuming average reservoir conditions (porosity of 20 percent), oil recovery of
250 barrels per acre-foot is estimated.
F. Assuming same reservoirs, an average depth of 2,500 ft, and a thermal gradient
of 2.15°F per 100 ft, I estimate a gas recovery of 300,000 ft 3 per acre-foot.
G. World-wide average.
Limiting Factor: The advanced stage of exploration in this shallow play limits
any further discoveries.
Total resources for all plays in basin: .250 BBO, 1.518 TCFG, .016 BBNGL, .518 BBOE

164
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Northwest Java, No. 4 COUNTRY Indonesia PLAY Paleogene Volcanics,
AREA OF BASIN (Mi 2 ) 20,600 _____________No. 1
VOLUME OF BASIN (Mi 3!25,600 AREA OF PLAY (MMA)774
ESTIMATE ORIGINAL RESERVES 2.754 BBO 2.1 TCFG(1979) PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Back Arc .16 BBO TCFG

DEFINITION AND AREA OF PLAY:Petroleum accumulations in fractured Paleogene

volcanics in traps formed by block-faulting and drapes. Play area essentially
restricted to Jatibarang subbasin of some 740,000 acres (figs. 20 and 22).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .005 .018 .025
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 6 12 20
C. AVERAGE EFFECTIVE PAY (feet) 100 350 1,000
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 40 75 80
E. OIL RECOVERY (BBLS/AF) 130 237 400
F. GAS RECOVERY (MCF/AF) 400 800 1,600
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .134 BB, GAS .151 TCF, NGL .002 BB, OE .161 BBOE

REMARKS
A. By analogy to the overlying Talang Akar play in other parts of the basin, the
trap area is 6 percent of the play area. If 60 percent of the traps are deemed
tested, .018 million acres of trap area remain.

B. By analogy to the Talang Akar play, the untested trap area which may be produc-
tive is estimated at 12 percent.

C. The average gross thickness of fractured volcanics above the oil-water contact
in the Jatibarang Field is 800 ft. According to Todd and Pulanggano, 1971,
"average cumulative reservoir thickness is 600 ft." Sembodo, 1973, illustrates
120 ft as a sample. Controlled by fracture permeability, reservoir thickness
is irregular. I estimate 350 ft as average for play.

D. By analogy to the Talang Akar play, 75 percent of the petroleum mix is oil.

E. Estimating 22 percent porosity and assuming other reservoir parameters are

average, the primary oil recovery is 237 barrels per acre-foot.

F. Assuming same reservoirs, average reservoir depth of 6,600 ft, and thermal gra-
dient of 3.0°F per 100 ft, the gas recovery would be 800,000 ft 3 per acre-foot.

G. World-wide average.

Limiting Factors: The reservoir quality from prospect to prospect is unpredictable.

Total resources for all plays in basin: .953 BBO, 1.941 TCFG, .011 BBNGL, 1.024 BBOE

165
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Northwest Java, No. 4 COUNTRY Indonesia PLAY Paleogene (Talang Akar)
AREA OF BASIN (Mi7)20,600 Sandstones "575 No. 2
VOLUME OF BASIN (Mi ______
25,600 AREA OF PLAY (MMA)______
ESTIMATE ORIGINAL RESERVES 2.754 BBO 2.1 TCFG(1979) PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Back Arc BBO TCFG
DEFINITION AND AREA OF PLAY: Petroleum accumulations in traps formed by fault clo-
sures of Paleogene deltaic sandstones or by draping of these sandstones onto flanks
or over fault-block highs. Play largely restricted to subbasins or half-grabens
(figs. 20 and 22).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .05 .099 .250
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 5 12 20
C. AVERAGE EFFECTIVE PAY (feet) 40 110 250
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 40 75 90
E. OIL RECOVERY (BBLS/AF) 150 269 400
F. GAS RECOVERY (MCF/AF) 400 812 1,600
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .264 BB, GAS .265 TCF, NGL .003 BB, OE .311 BBOE

REMARKS
From extrapolation of small map portion of Sunda basin, trap area is 9 percent of
play area. By analogy to geologically similar South Sumatra basin, trap area is
5.5 percent and by analogy to the somewhat similar East Java Sea basin, 7 percent,
I estimate 6 percent, or 330,000 acres, of which 70 percent has been tested.
The overall wildcat success rate for the basin is high - 31 percent, but this is
largely attributable to later Miocene plays; I estimate a somewhat lesser rate,
perhaps 25 percent for the Talang Akar sandstones. Fill is thought to be 70 per-
cent for Miocene traps of this basin and 35 percent for analogous Paleogene traps
of South Sumatra. Accordingly 'I estimate an average of 50 percent fill, giving
an average productive area of 12 percent.
The average cumulative reservoir thickness is reportedly 110 ft (Todd and
Pulunggono, 1971).
No precise data available, I estimate that 75 percent of the petroleum mix is
oil at this level.
E. Based on a reported average porosity of 25 percent and assuming 25 percent water
saturation and 25 percent oil recovery.
F. Assuming same reservoirs, an average depth of 8,000 ft, and a thermal gradient
of 2.8°F per 100 ft.
G. World-wide average.
Limiting Factor: No salient limiting factor. Since closures appear half-filled,
source rock richness may be a limiting factor.
Total resources for all plays in basin: .953 BBO, 1.941 TCFG, .011 BBNGL, 1.024 BBOE

166
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Northwest Java, No. 4 COUNTRY Indonesia PLAY Lower Miocene carbonates
AREA OF BASIN (Mi 2 ) 20,600 ____________No. 3
VOLUME OF BASIN (Mi 3"]25,600 AREA OF PLAY (MMA) 3.84
ESTIMATE ORIGINAL RESERVES 2.754 BBO 2.1 TCFG(1979) PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF M5TN: Back Arc .6(?) BBO 1(?) TCFG
DEFINITION AND ARtA OF PLAf:Petroleum accumulation in lower Miocene (partly Oligo-
cene) porous carbonate (Baturaja Formation) drapes and buildups. Area of play is
the Sunda, Arjuna and northern Jatibarang subbasins, and peripheral area - about
6,000 mil (figs. 20, 25, and 26).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .050 .138 .400
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 5 9 20
C. AVERAGE EFFECTIVE PAY (feet) 50 100 200
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 15 70 90
E. OIL RECOVERY (BBLS/AF) 150 230 400
F. GAS RECOVERY (MCF/AF) 400 690 1,000
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .243 BB, GAS .257 TCF, NGL .003 BB, OE .289 BBOE

REMARKS
A. From partial maps of basin, I estimate about 12 percent of play area (.461 MMA)
is trap area, of which 30 percent (.138 MMA) is untested.

B. Discovery rate for all plays is 31 percent; in absence of data, I. assume this
is about the rate for this play. Estimating a 30 percent fill (analogy to late
Miocene reefs), the untested trap area would be 12,000 acres (9 percent).

C. Average net pays are 66 ft at FF Field, 125 ft at Arimba Field, 75 ft at Zelda

Field, and 40-100 ft at Krishna Field. Todd and Pulunggono (1971) report an
"average cumulative reservoir thickness of 175 ft for the basin." I believe
100 ft is a good average for net effective thickness.

D. The Sunda Subbasin appears to be largely oil-prone; Arimba Field in the eastern
basin, on the other hand, is largely gas. I estimate petroleum fill is 70
percent oil, somewhat less than in the underlying Paleogene sands.

E. Assuming 25 percent porosity and 25 percent water saturation, primary oil

recovery would be 280 barrels per acre-foot.

F. Assuming same reservoirs, as for oil, an average reservoir depth of 3,000 ft,
and a temperature gradient of 2.8°F/100 ft, the average gas recovery is about
690,000 ft 3 per acre-foot.

G. World-wide average is assumed.

Limiting Factor: Porosity distribution in the carbonate reservoirs.

Total resources for all plays in basin: .953 RBO, 1.941 TCFG, .011 BBNGL, 1.024 BBOE

167
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Northwest .Java, No. 4 COUNTRY Indonesia PLAY Miocene Draped Sandstones,
AREA OF BASIN (Mi 2 )20,600 ______________No, 4
VOLUME OF BASIN (Mi 3!25,600 AREA OF PLAY (MMA)176
ESTIMATE ORIGINAL RESERVES 2.754 BBO 2.1 TCFG(1979) PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Back Arc 1.2(?) BBO (?) TCFG
DEFINITION AND AREA OF PLAY:Petroleum accumulations in middle to mainly upper
Miocene sandstones (Air Benakat or Upper Cibulakan Formations) in drape closures
over fault blocks or carbonate buildups. Play limited by effective sandstone distri
bution to Arjuna subbasin (1.2 MMA) and peripheral (0.4 MMA) (figs. 22 and 23).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .010 .030 .050
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 10 21 30
C. AVERAGE EFFECTIVE PAY (feet) 50
30" 250 350
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 60 80
E. OIL RECOVERY (BBLS/AF) 100 224 350
F. GAS RECOVERY (MCF/AF) 300 457 1,000
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .212 BB, GAS .288 TCF, NGL .003 BB, OE .263 BBOE

REMARKS
A. By analogy to closures at Talang Akar level (see play 2), 6 percent of play is
in trap or about 100,000 acres. I estimate that about 70 percent of closure
has been found and tested, leaving an untested trap area of 30,000 acres.
B. The basin's wildcat success is about 31 percent, which we assume is average for
this play. The petroleum fill of the principal sand (B-28) in the Arjuna B
Field is 70 percent. I assume this to be average for play, giving a productive
area of about 21 percent.
C. Average net pay is reportedly 250 ft (Todd and Pulunggono, 1971).
0. The percent of oil should be about the same as the underlying Talang Akar sandstones
since they have a common source; however the gas-oil ratio is higher in these
sandstones, i.e., 40:60 in contrast to 25:75 for the Talang Akar.
E. Assuming average porosity of 26 percent and water saturation of 40 percent
(Arjuna B Field) is average for basin, and primary oil recovery of 25 percent.
F. Assuming same reservoirs, average depth of 3,000 ft, and thermal gradient of
2.6°F per 100 ft.
G. World-wide average.
Limiting Factor: The most limiting factor is probably sand distribution, confining
the production to the Arjuna subbasin area.
Total resources for all plays in basin: .953 BBO, 1.941 TCFG, .011 RRNGL, 1.024 RROE

168
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Northwest Java, No. 4 COUNTRY Indonesia PLAY Mid-Miocene carbonates, No. 5
AREA OF BASIN (Mi 2 )20,600 AREA OF PLAY (MMA) 3.2 ~
VOLUME OF RASIN (Mi j ) 25,600 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 2.754 BBO 2.1 TCFG(1979) .01 BBO 1(?) TCFG
TECTONIC CLASSIFICATION OF BASIN: Back Arc
DEFINITION AND AREA OF PLAY: Gas and some oil accumulations in middle Miocene car-
bonate reefs and banks. Play not limited to subbasinal areas but extends across
basin. Appears not to be developed in vicinity of the Sunda subbasin (3.2 MMA)
(figs. 20 and 22).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .150 .250 .400
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 4 8 20
C. AVERAGE EFFECTIVE PAY (feet) 50 120 400
n. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 5 15 30
E. OIL RECOVERY (BBLS/AF) 150 270 350
F. GAS RECOVERY (MCF/AF) 300 480 1,000
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .10 BB, GAS .980 TCF, NGL .010 BB, OE .273 BBOE

REMARKS
A. As indicated by published maps (Burbury, 1977), there are 690,000 acres of car-
bonate trap. From distribution of wildcats that 36 percent or 250,000 acres
remain to be tested.
B. On basis of wildcat activity, a 20 percent success rate is indicated for the play
as a whole, although it may vary from subbasin to subbasin. Petroleum fill also
varies, but in this rather shallow play it may be lower than the 70 percent of
the deeper Miocene drapes, perhaps 40 percent, indicating a productive area of 8
percent.
C. Effective pay appears to range from 30 to 400 ft. Taking into consideration
the varying and unpredictable porosity, the average carbonate porous zone would
average some 120 ft in thickness.
D". Production indicates these reservoirs to be gas prone though some oil is produced.
Oil is considered to make up 15 percent of the oil-gas mix.
E. No data; assuming poor to average reservoir parameters.
F. Assuming similar reservoir parameters, an average depth of 3,000 ft, and a thermal
gradient of 3.6°F per 100 ft.
G. World-wide average.
Limiting Factors: The overall limiting factor for petroleum appears to be limited
and unpredictable porosity and lack of thick cover. The limiting factor for
the oil fraction is lack of migration avenues to the shale encased reefs from
the deeper mature source rock.
Total resources for all plays in basin: .953 BBO, 1.941 TCFG, .011 BBNGL, 1.024 BBOE

169
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN East Java Sea, No. 5 COUNTRY Indonesia PLAY Shelf Reef, No. 1
AREA OF BASIN (Mi 2 )_ 43,000 AREA OF PLAY (MMA) 5
VOLUME OF BASIN (Mi 3!77,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESEWTS 7707 BBO -- TCFG .02 BBO TCFG
TECTONIC CLASSIFICATION OF BASIN: Back Arc
DEFINITION AND AREA (JF PLAY: Petroleum accumulations in Tertiary reefs and banks
of the basin shelf and shelf margin. Play area limited to carbonate platform area,
which makes up about 30 percent of basin shelf or 5 million acres (figs. 28 and 30)
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .050 .200 .500

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 3 6 15
C. AVERAGE EFFECTIVE PAY (feet) 100 200 400
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 20 40 80
E. OIL RECOVERY (BBLS/AF) 140 194 300
F. GAS RECOVERY (MCF/AF) 350 568 1,000
G. NGL RECOVERY (BBLS/MMCFG) 7 11 22
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .186 BB, GAS .818 TCF, NGL .009 BB, OE .331 BBOE

REMARKS
A. An unpublished map of part of area indicates that carbonate buildups make up 7
percent of play area, but for entire play, I would judge percentage to be some-
what lower, about 5 percent, giving a trap area of 250,000 acres. Perhaps 20
percent of this area has been tested leaving 200,000 acres of untested trap.
B. Announced discoveries indicate success rate of 18 percent, but none of discover-
ies were developed, and a realistic estimate would perhaps halve this rate to
about 10 percent. Fill ranges from 100 percent at Poleng Field, and 6 percent at
53A-1. I estimate 60 percent fill, indicating 6 percent of untested trap area
will be productive.
C. Net pay of Poleng Field is 255 ft and an early discovery, JS-1-1, had 20 ft of
net pay (Soeparjadi and others, 1975). Average figure for productive accumula-
tion would probably have to be at least 200 ft; which is assumed as an average.
D. From the Poleng Field reef, which is filled by 102 ft of oil overlain by 153 ft
of gas (Soeparjadi and others, 1975), it is assumed that average fill is 40
percent oil.
E. Porosity distribution in these carbonate reservoirs is often poor and unpredictable,
Assuming a somewhat low average porosity of 18 percent, the yield is 194 barrels
per acre-foot.
F. Assuming the same reservoirs, a reservoir depth of 5,000 ft, and a thermal
gradient of 2.2°F per 100 ft, the gas recovery is 568,000 ft 3 per acre-foot.
G. World-wide average.
Limiting Factors: Evident small size of traps and unpredictability of favorable
reservoir parameters.
Total resources for all plays in basin: .356 BRO, 1.592 TCFG, .018 BBNGL, .638 BBOE

170
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN East Java Sea, No. 5 COUNTRY Indonesia PLAY Shelf Drapes, #2
AREA OF BASIN (Mi?) 43,000 AREA OF PLAY (MMA) 17.0
VOLUME OF BASIN (Mi 3!77,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES .207 BBO -- TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF BASIN: Back Arc
DEFINITION AND AREA OF HLAY: Petroleum accumulations in Tertiary sands or calcarenites
draped over basement tilted fault blocks. Play area is that of the basin shelf -
about 17 million acres (figs. 28 and 30).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .10 .30 .60
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 2 4.5 6
C. AVERAGE EFFECTIVE PAY (feet) 50 100 400
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 20 40 80
E. OIL RECOVERY (BBLS/AF) 150 270 350
F. GAS RECOVERY (MCF/AF) 350 770 1,000
G. NGL RECOVERY (BBLS/MMCFG) 7 11 22

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .145 BB, GAS .624 TCF, NGL .007 BB, OE .255 BBOE

REMARKS

A. An unpublished structure map of part of area indicates drape traps make up 5

percent of play, but if one includes the less structured parts of the shelf, I
think this percentage would be half that of the mapped area or 2.5 percent or
425,000 acres, of which perhaps 30 percent has been tested leaving 300,000 acres.

B. The wildcat success rate is 18 percent on the basis of announced discoveries, but
none have been developed; perhaps half this rate would be more realistic. Assum-
ing a fill somewhat less than for the carbonate play, say 50 percent, the percent
of untested trap likely to be productive is 4.5 percent.

C. No data are available. Effective pay of at least 50 ft would be required for an

economic offshore prospect. I assume an average of 100 ft.

D. In the absence of data, I estimate the percent of oil in the petroleum fill is
the same as that for the reef play, i.e., oil is 40 percent.

E. Assuming average reservoir parameters, I estimate 270 barrels per acre-foot.

F. Assuming same reservoirs, a reservoir depth of 5,000 ft, and a thermal gradient
of ?.2°F per 100 ft, gas recovery is estimated to be 770,000 ft 3 per acre-foot.

G. World-wide average.

Limiting Factor: Reservoir quality is likely to be poor in this very calcareous

sedimentary section.

Total resources for all plays in basin: .356 BBO, 1.592 TCFG, .018 BBNGL, .638 BBOE

171
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN East Java Sea, No. 5 COUNTRY Indonesia PLAY Basinal Folds, #3
AREA OF BASIN (Mi*) 43,000 AREA OF PLAY (MMA) 10.7
VOLUME OF BASIN (Mi 3} 77,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES .207 BBO TCFG .201(?)BBO TCFG
TECTONIC CLASSIFICATION OF BASIN: Back Arc

DEFINITION AND AREA OF PLAY:Petroleum accumulations in Neogene folds of the deep,

basinal part of East Java basin. Play area between relatively shallow shelf to the
north and the volcanic arc to the south is about 10.7 million acres (figs. 28 and 30)
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .50 .150 .500

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 1.5
C. AVERAGE EFFECTIVE PAY (feet) 100 200 700
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 10 30 90
E. OIL RECOVERY (BBLS/AF) 100 195 350
F. GAS RECOVERY (MCF/AF) 300 475 1,000
G. NGL RECOVERY (BBLS/MMCFG) 7 11 22

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .026 BB, GAS .150 TCF, NGL .002 BB, OE .053 BROE

REMARKS
A. Onshore traps are small and play exploration very mature. Deep prospects are
relatively unevaluated. Offshore there are some larger folds, east of and on
trend with Madura Island, i.e., along and immediately basinward of shelf edge. In
a limited zone of 2.5 million acres, closures make up about 5 percent of play area
or about 125,000 acres, most of which are untested. Considering the onshore small
closures, perhaps 150,000 acres remain to be tested.
B. Recent drilling in the offshore found one gas discovery plus a blowout and an oil
show. I estimate a discovery rate of perhaps 15 percent. Percentage fill in
onshore traps is 10 percent (Soetantri, 1973); that is assumed average for play
indicating 1.5 percent of untested trap area would be productive.
C. Large net sand figures are reported, 440 to 639 ft in onshore and 500 ft in off-
shore well, MS-1. These figures appear high considering the small amount of
production obtained. I would estimate 200 ft as an average net thickness.
D. Onshore wells produced only oil but gas was only flared in those early years.
One gas discovery and one blowout in offshore along with thick, probably over-
pressured shale suggests gas. I estimate petroleum mix is 30 percent oil.
E. Porosity is reportedly relatively low, about 18 percent in onshore wells. On
this basis I estimate an oil recovery of about 194 barrels per acre-foot.
F. Assuming the same reservoirs, a reservoir depth averaging 4,000 ft, and a
thermal gradient of 2.1°F per 100 ft, I estimate a gas recovery of 475,000 ft^
per acre-foot.
G. World-wide average.
Limiting Factor: Most of effective trap formation happened very late after a good
part of the migrating petroleum may have escaped updip.
Total resources for all plays in basin: .356 BBO, 1.592 TCFG, .018 BBNGL, .638 BROE

172
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Barito, No. 6 COUNTRY Indonesia PLAY Folded Sandstones, No. 1

AREA OF BASIN (Mi*) 19,000 AREA OF PLAY (MMA) 2.35
VOLUME OF BASIN (Mi 3!43,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES .134 BBO ____
.005 TCFG ___
.134 BBO ____
.005 TCFG
TECTONIC CLASSIFICATION OF BASIN: Foreland plus collision zone
DEFINITION AND AREA OF PLAY:Petroleum accumulations in Eocene to Miocene sandstones
involved in Miocene and Pliocene folds. The area of folds is largely limited to the
northeastern quarter of the basin (figs. 33 and 34).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .08 .015 .050
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 2 5 10
C. AVERAGE EFFECTIVE PAY (feet) 50 150 300
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 30 50 80
E. OIL RECOVERY (BBLS/AF) 150 244 400
F. GAS RECOVERY (MCF/AF) 300 467 600 -
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .014 BB, GAS .026 TCF, NGL .001 BB, OE ,018 BBOE

REMARKS
A. No map available, but it is assumed that in the relatively small area explora-
tion has reached a mature state. The Tanjung Field is about 3,700 acres, and
the Warukin Field is smaller. It would appear that the equivalent of only two
Tanjung Fields can remain, which would amount to some 15,000 acres of trap
closure (assuming 50 percent fill).
B. Little drilling history is available; I estimate a success rate of 10 percent.
Fill at Tanjung is estimated to be 50 percent and this is taken as average for
the basin, indicating that 5 percent of untested trap area would be productive.
C. Reportedly there are three principal Eocene sandstones at Tanjung making some
230 ft in all plus an estimated 150 ft of Miocene sand. The Miocene sandstones
are not likely to extend over the play area. I estimate an average reservoir
thickness of 150 ft for the play.
D. The Tanjung Field has a small gas cap, 10 percent of trap volume as a guess.
A gas discovery has been made in the overlying Berai Formation carbonate on
the edge of basin. I estimate that oil makes up 50 percent of petroleum mix.
E. On basis of 20 to 25 percent porosity (Tanjung) and assuming average reservoir
parameters, i estimate an oil recovery of 244 barrels per acre-foot.
F. Assuming sane reservoirs, an average depth of 3,000 ft, and a thermal gradient
of 1.87°F per 100 ft, I estimate a gas recovery of 467,000 ft 3 per acre-foot.
G. World-wide average.
Limiting Factors: Small size of play coupled with maturity of exploration.
Total resources for all plays in basin: .184 BBO, .483 TCFG, .007 BRNGL, .270 RBOE

173
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Barito Basin, No. 6 COUNTRY Indonesia PLAY 01igo-Miocene Reefs, #2

AREA OF BASIN (Mi 2 .19,000 AREA OF PLAY (MMA) T?72
VOLUME OF BASIN (Mi 3!43,000 PLAY EST. ORIG. RESERVES,
.005 TCFG
ESTIMATE ORIGINAL RESERVES .134 BBO ____ ___0 BBO ____0 TCFG
TECTONIC CLASSIFICATION OF M5TN: Foreland plus collision zone

DEFINITION AND AREA OF PLAY:Petroleum accumulations in Oligo-Miocene (Berai Forma-

tion) reefs. Reefs identified in southwestern, far northern, central (Tanjung Field)
and eastern parts and therefore assumed to cover basin (figs. 33 and 34).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .05 .183 .400
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 2 6 11
C. AVERAGE EFFECTIVE PAY (feet) 50 130 300
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 30 50 80
E. OIL RECOVERY (BBLS/AF) 150 200 300
F. GAS RECOVERY (MCF/AF) 300 568 800
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .143 BB, GAS .405 TCF, NGL .005 BB, OE .215 BBOE

REMARKS

A. Assumed analogous to Berai Formation of adjoining East Java Sea shelf where I
estimated the reefal facies took up 30 percent of shelf and that 5 percent of
the reef facies was trap. 1.5 percent of 12.2 million acres is 183,000 acres
of which very little has been tested.
B. A wildcat success rate of 12 percent is estimated. Assuming petroleum fill of
Tanjung, 50 percent, could apply to this play; 6 percent of untested trap area
is productive.
C. At Tanta (adjacent to Tanjung), 250 ft of producing reservoir was found, in the
Upper Kapuas River (NW of basin), 131 ft was found. In adjoining East Java Sea,
average thickness of 125 ft was assumed for equivalent reservoir. I estimate
an average thickness of 130 ft for the play.
D. I assume percentage of oil is same as for the Folded sandstones play.
E. No data, by analogy to equivalent reservoirs of East Java Sea, primary oil
recovery would be about 200 barrels per acre-foot.
F. By analogy to reefs of adjoining East Java Sea, which have about the same
average depth, 5,000 ft, and about the same thermal gradient, i.e. 2.2°F versus
1.67°F per 100 ft, the average gas recovery would be 568,000 ft^ per acre-foot.
G. Uorld-wide average.
Limiting Factors: Small size of reefs, and uncertain reservoir characteristics and
insufficient thickness for much oil and gas generation.
Total resources for all plays in basin: .184 BBO, .483 TCFG, .007 BBNGL, .270 BBOE

174
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN _________________
Barito, NQ. 6 COUNTRY _________
Indonesia PLAY Drape Sandstones, No. 3
AREA OF BASIN (MiM 19,000 AREA OF PLAY (MMA) 12.2
VOLUME OF BASIN (Mi 3 ) 437000" PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES .134 BBO .005 TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF MsTN: Foreland plus collision zone
DEFINITION AND AREA OF PLAY:Petroleum accumulations in Paleogene sandstones draped
over basement knobs in the shelfal area. Play extends over entire basin (figs. 33
and 34).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .040 .100 .200
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 0.5 1.5 5.0
C. AVERAGE EFFECTIVE PAY (feet) 50 150 300
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 30 50 80
E. OIL RECOVERY (BBLS/AF) 150 244 400
F. GAS RECOVERY (MCF/AF) 300 467 600
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20

WODUCT UF MOST
LIKELY PROBABILITIES: OIL .027 BB, GAS .052 TCF, NGL .001 BB, OE .037 BBOE

REMARKS
A. In one unpublished map in northern part of the play, the trap area made up .85
percent of the map area; extrapolated to the whole play area this comes to
about 100,000 acres.
B. No wildcats have been successful. I estimate success rate will be low - about
3 percent. The fill is assumed to be the same as the folded sands, i.e. 50
percent.
C. By analogy to the Folded sandstone play.
D. By analogy to the Folded sandstone play.
E. By analogy to the Folded sandstone play.
F. By analogy to the Folded sandstone play whose reservoirs are at about the same
depth.
G. World-wide average.

Limiting Factors: Small size of knobs and uncertainty of closure.

Total resources for all plays in basin: .184 BBO, .483 TCFG, .007 BBNGL, .270 BBOE

175
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN ______^
Kutei, No..^______
7 COUNTRY _________
Indonesia PLAY Neogene Delta Sandstones,
AREA OF BASIN (Mi*) 50,000 (78,000 includ. water >600') ______No. 1
VOLUME OF BASIN (Mi 3 )210,000 (310,000 in. water >600') AREA OF PLAY (MMA) 17.5 ~~
ESTIMATE ORIGINAL RESERVES 2.56* BBO 10.4 TCFG(1979) PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF "BXSTN: 2.56 BBO 10.4 TCFG
Rifted Pull-Apart
DEFINITION AND AREA OF PLAY:Petroleum accumulations in folded Miocene and Pliocene
deltaic sandstones. The area of play includes the Mahakam ancestral delta plus the
so-called Pasir subbasin (area 1, fig. 41).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .100 .270 .400

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 5 13 30
C. AVERAGE EFFECTIVE PAY (feet) 50 300 900
0. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 5 20 50
E. OIL RECOVERY (BBLS/AF) 100 233 500
F. GAS RECOVERY (MCF/AF) 800 1,900 2,500
G. NGL RECOVERY (BBLS/MMCFG) 5.0 25.7 50.0

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .490 BB, GAS 16.0 TCF, NGL .411 BB, OE 3.57 BBOE

REMARKS
A. Many traps have been mapped and tested, but I estimate from an unpublished
map that there are some 400,000 acres of prospects and leads, of which
approximately two-thirds, as finally mapped, will be untested potential traps,
or about 270,000 acres.
B. Wildcat success rate is about 33 percent. Percent of areal fill ranges from
3.8 percent fill (of original prospect) at Bekapai to 37 percent at Attaka, to
100 percent at Handil; 40 percent is taken as average. 33 x 40 = 13 percent
trap area.
C. Sandstone thicknesses vary considerably. Handil appears to have about 624 ft of
effective pay and Badak 1,120 ft, but these fields are located near the delta
front; average for whole delta area would perhaps be only one-third or about
300 ft.
D. At a recent stage, 320 MBOD and 550 MMCFG were being produced. I estimate
that new oil discoveries may do little more than balance declining reserves,
but new gas discoveries will more than double present production. Petroleum
resources are believed to be only 20 percent oil versus gas.
E. Porosities appear to range from 14 to 35, averaging perhaps 25 percent; water
saturation averages about 35 percent; a 25 percent recovery is assumed.
F. Most gas from 10,000 to 12,000 ft. Allowing for a higher (double) pressure gra-
dient below 10,000 ft (top of overpressure), a high gas recovery is estimated.
G. Badak Field data.
Limiting Factors: Amount of available trap and reservoir; for oil, lack of
primary migration channels.
Total resources for all plays in basin: .631 BBO, 20.171 TCFG, .492 BBNGL, 4.487 BBOE
* Includes NGL.

176
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Kutei , No. 7 COUNTRY Indonesia PLAY Paleogene Drapes, No. 2

AREA OF BASIN (Mi^50,000 (78,000 incl.water >600 ft) AREA OF PLAY (MMA) 13.0
VOLUME OF BASIN (Mi 3 ) 210/100 (310,000 in.water >600') PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 2.56 BBO 10.4 TCFG(1979) 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF BASIN:
Rifted Pull-Apart
DEFINITION AND AREA OF PLAY: Petroleum accumulation in Paleogene sandstones draped
over topographic highs; includes accumulations of reservoired oil redistributed by
later, renewed fault-block movement. Western (Paleogene) shelfal area or inner Kutei;
includes north and south flanks (area 2, fig. 41).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .050 .187 .400
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 5 4 30
C. AVERAGE EFFECTIVE PAY (feet) 50 140 500
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 5 10 60
E. OIL RECOVERY (BBLS/AF) 100 233 500
F. GAS RECOVERY (MCF/AF) 800 1,900 2,500
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20.0
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .024 BB, GAS 1.8 TCF, NGL .020 BB, OE .344 BBOE

REMARKS
A. Unpublished prospect and lead map indicates 280,000 acres of poorly defined,
untested trap area; some leads will not develop, but others may be found. I
estimate that two-thirds of the indicated area may, when finally mapped, be
potential trap.
B. Few wildcats have been drilled in this large area, and they were dry. Recent
drilling indicates that the Paleogene of the inner Kutei basin is overmature.
I estimate that the success rate would be at most 10 percent. Petroleum fill
is estimated to be that of the delta play or 40 percent, giving a 4 percent
productive area.
C. From Paleogene sandstones of Tanjung Field (of the Barito basin) but only separated
from the Kutei basin by the relatively recent (L. Miocene) Meratus Range.
D. i assume that this play's source rock is largely overmature, and the oil-gas
mix is only some 10 percent.
E. In the absence of data, I estimate the same reservoirs as the delta sandstones.
F. Gas would probably be deep enough, coming from basal sandstones , to be in or near
the overpressured zone and 1,900 MCF/AF (sane as Neogene delta play) is assumed.
G. Estimated same as for the Neogene delta play (Radak Field data).
Limiting Factor: Source rocks are overmature.
Total resources for all plays in basin: .631 BBO, 20.171 TCFG, .492 BRNGL, 4.487 BBOE.

177
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Kutei , No. 7 COUNTRY Indonesia PLAY U.Oligocene-L.Miocene
AREA OF BASIN (Mi*) 50,000 (78,000 inc. water >600 ft) Reefs, No. 3
VOLUME OF BASIN (Mi 3 ) 210,000 (310,000 inc. water >600') AREA OF PLAY (MMA) 5.2
ESTIMATE ORIGINAL RESERVES 2^56 BBO 10.4 TCFG(1979) PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: 0 BBO 0 TCFG
Rifted Pull-Apart
DEFINITION AND AREA OF PLAY:Shelf-edge late 01igocene-early Miocene carbonate buildups
on south and north flank of basin. 4.2 million acres in south and 1.0 million
acres on the north, giving 5.2 million acres in all (area3, fig. 41).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .050 .130 .400
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 1 4 20
C. AVERAGE EFFECTIVE PAY (feet) 50 200 600
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 10 20 70
E. OIL RECOVERY (BBLS/AF) 100 194 500
F. GAS RECOVERY (MCF/AF) 600 1,000 2,000
G. NGL RECOVERY (BBLS/MMCFG) 5 25.7 50

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .040 BB, GAS .832 TCF, NGL .022 BB, OE .201 BBOE

REMARKS
A. In the geologically similar carbonate shelfal area of the East Java Sea, build-
ups make up 5 percent of play area; however these buildups are large and easily
mapped. These buildups appear half as well developedand concentrated along the
shelf edge; I estimate 2.5 percent of the play area. A negligible amount of
trap has been tested.
B. The number of wells drilled primarily to test this play could not be ascer-
tained, but one gas discovery has been made. I estimate discovery rate of 10
percent. Fill is assumed to be the same as East Java carbonate shelf or 40
percent, indicating 4 percent of the play area to be productive.
C. i assume the effective pay to be the same as that estimated for the reefs of
the East Java Sea or an average of 200 ft.
D. The percentage of oil in the aerial fill is unknown, but I assume it to be
between the 10 percent fill of the Paleogene drapes or the 50 percent of the
buildups of the East Java Sea carbonate platform, say 20 percent.
E. Assumed to be the same as the average of the East Java Sea reefs.
F. Also analogous to the East Java Sea but about twice as deep, giving a recovery
of a million cubic feet per acre-foot versus 500,000.
G. Assumed to be the same as the Neogene deltaic sands.
Limiting Factors: Source rock and seal distribution is critical.
Total resources for all plays in basin: .631 RBO, 20.171 TCFG, .492 RBNGL, 4.487 BBOE,

178
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Kutei , No. 7_______ COUNTRY Indonesia PLAY Mio-Pliocene Reefs, #4

AREA OF BASIN (Ml 2 ) 50,000 (78,000 inc. water >600 ft) AREA OF PLAY (MMA) 1.45
VOLUME OF BASIN (Mi 3 ) 210,000 (310,000 inc.water >600') PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 2.56 BBO 10.4 TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF BASIN:
Rifted Pull-Apart
DEFINITION AND AREA OF PLAY: Petroleum, probably gas, in isolated shale enclosed
reefs along the outer continental shelf, an area of about 1.45 million acres,
(area 4, fig. 41).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .020 .100 .300

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 2 12 40
C. AVERAGE EFFECTIVE PAY (feet) 40 110 500
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 1 10 75
E. OIL RECOVERY (BBLS/AF) 100 300 500
F. GAS RECOVERY (MCF/AF) 600 800 2,000
G. NGL RECOVERY (BBLS/MMCFG) 5 25.7 50

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .040 BB, GAS .95 TCF, NGL .024 BB, OE .222 BBOE

REMARKS
A. From unpublished maps, I estimate that the acreage in untested reef traps is
about 100,000 acres (or about 7 percent of the play area).
B. Two, and perhaps three, gas discoveries have been made in this play, giving a
success rate of possibly 25 percent, but this play does not appear to have been
seriously pursued, given the nearby higher prospective delta sandstones and the
small size of the reefs. The amount of fill is assumed to be 50 percent.
C. Observation of well logs indicates an average of 110 ft.
D. Most reefs are deep, 8,000 to 10,000 ft (but some are shallower, ranging up to
sea bottom). The more prospective deeper reefs, enclosed as they are in shale
and near or within the overpressured shale, are deemed to be largely occupied
by gas, say 10 percent oil.
E. No information; an average of 300 barrels per acre-foot is assumed.
F. Assuming an average depth of 9,000 ft and average reservoir parameters, I
estimate 800,000 ft 3 per acre-foot.
G. Assumed to be same as the delta sandstones, 25.7 B/MMCFG (Badak Field data).
Limiting Factors: The small size and depth, limiting commerciality for some reefs
and lack of seals on those reefs extending to the sea floor.
Total resources for all plays in basin: .631 BBO, 20.171 TCFG, .492 BBNGL, 4.487 BBOE

179
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Kutei , No. 7_______ COUNTRY Indonesia PLAY Deep Water Sandstones,
AREA OF BASIN (M1) 50,000 (78,000 inc. water >600 ft) ______ No. 5
VOLUME OF BASIN (Mi 3 ) 210,000 (310,000 inc. water >600) AREA OF PLAY (MMA) 11.5 ~
ESTIMATE ORIGINAL RESERVES 2.56 BBO 10.4 TCFG(1979) PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF "BASTN: 0 BBO 0 TCFG
Rifted Pull-Apart
DEFINITION AND AREA OF PLAY: Sands in structures in deep water beyond the conti-
nental shelf. Sandstones are of neritic origin recently depressed to depths up to
6,000 ft, an area of about 11.5 million acres (area 5, fig. 41).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .05 .46 .90
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 2 4 16
C. AVERAGE EFFECTIVE PAY (feet) 30 50 300
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 5 20 80
E. OIL RECOVERY (BBLS/AF) 100 200 500
F. GAS RECOVERY (MCF/AF) 600 800 2,000
G. NGL RECOVERY (BBLS/MMCFG) 5 25.7 50
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .037 BB, GAS .589 TCF, NGL .015 BB, OE .150 BBOE

REMARKS
A. On the basis of a partial, unpublished map, the area of untested prospects and
leads is about 8 percent of the play area in older drapes and more recent
fault traps. Probably only half the leads will finally be developed into good
prospects.
B. On basis that traps, reservoirs, and source are present, a wildcat success
rate of 10 percent is estimated. I assume a 40 percent petroleum fill as is
estimated for the other plays of the basin.
C. Thin reservoirs are assumed in this area, largely beyond the confines of the
ancestral Mahakan delta.
D. The percentage of oil is assumed to be the same as for the delta sandstones.
E. Reservoir parameters may be poorer in this area, more distal than other plays
from sedimentary sources. I estimate 200 bbs/AF.
F. Gas recovery is also expected to be lower on the basis of poorer reservoirs
and shallowness.
G. Sane as for other plays (Badak field data).
Limiting Factor: Possible absence of adequate reservoirs and deep water economic
feasi bi1ity.
Total resources for all plays in basin: .631 BBO, 20.171 TCFG, .492 BBNGL, 4.487 BBOE

180
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Tarakan, No. 8 COUNTRY Indonesia PLAY Carbonate Reefs & Banks
AREA OF BASIN (Mi 2 )^ 16,250 _____________No. 1
VOLUME OF BASIN (Mi 3!30,000 AREA OF PLAY (MMB) 10.4
ESTIMATE ORIGINAL RESERVES .469 BBO ____
.47 TCFG PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Back Arc 0 BBO 0 TCFG

DEFINITION AND AREA OF PLAY: Petroleum accumulations in carbonate reefs and banks
in the largely shale and carbonate sequence of Oligocene to early Miocene age. Play
probably extends over basin but is best developed in south over the Maura Shelf and
adjoining Mangkalihat Platform (fig. 48).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .150 .156 .800

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 1.0 3.5 10.0
C. AVERAGE EFFECTIVE PAY (feet) 50 100 500
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 10 20 50
E. OIL RECOVERY (BBLS/AF) 100 216 350
F. GAS RECOVERY (MCF/AF) 400 1,400 2,000
G. NGL RECOVERY (BBLS/MMCFG) 7 11 22
TOIDITCT UTMOST
LIKELY PROBABILITIES: OIL .024 BB, GAS .612 TCF, NGL .007 BB, OE .133 BBOE

REMARKS

A. Reef or near-reef facies have been penetrated by wildcats in the south and north
and are indicated on seismic sections, but size and distribution are largely un-
known. The play area may be analogous to the reefal area of the East Java Sea,
i.e.,30 percent of the play area is in a reefal facies of which 5 percent is trap.
B. By analogy to the 01igo-Miocene reef play of the Kutei basin and East Java Sea
basins, 'I assume a 10 percent wildcat success rate. I also assume a 35-per-
cent fill indicating that 3.5 percent of untested trap area will be productive.
C. The analogous carbonate plays of Kutei and East Java Sea basins have an esti-
mated average net reservoir thickness of 200 ft. Tarakan basin with less carbon-
ate platform and generally less carbonate development is judged to have 100 ft.
D. In this largely shale sequence a blowout was encountered, and I suspect over-
pressure, in which case primary oil migration would be impeded in favor of gas.
I estimate 80 percent gas.
E. In the absence of data and assuming average quality reservoirs, I estimate 216
barrels per acre-foot.
F. Estimating reservoir depth of 11,000', a thermal gradient of 2.35°F per 100 ft,
and average quality reservoirs, I estimate 1.4 million cubic ft per acre-foot.
G. World-wide average.
Limiting Factor: Evidence for the amount of trap and reservoirs is weak.
Total resources for all plays in basin: .234 BBO, 1.2 TCFG, .014 BRNGL, .449 BBOE

181
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Tarakan, No. 8 COUNTRY Indonesia PLAY Late Miocene Folds, No. 2
AREA OF BASIN (Mi<T 16,250 AREA OF PLAY (MMA) 7.8
VOLUME OF BASIN (Mi 3 30,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES .469 BBO .47 TCFG .069(?) BBO .47(?) TCFG
TECTONIC CLASSIFICATION OF BASIN: Back Arc

DEFINITION AND AREA OF PLAY: Petroleum accumulations in Miocene, primarily deltaic,

sand and probably some calcarenites which are involved in late Miocene folds. Play
occupies about 75 percent of basin, exclusive of the Muara-Mangkalihat Platform (fig. 48
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .050 .123 .300

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 4 8 12
C. AVERAGE EFFECTIVE PAY (feet) 75 140 300
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 20 60 80
E9 OIL RECOVERY (BBLS/AF) 100 250 350
F. GAS RECOVERY (MCF/AF) 400 1,076 2,000
G. NGL RECOVERY (BBLS/MMCFG) 7 11 22

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .207 BB, GAS .593 TCF, NGL .007 BB, OE .312 BBOE

REMARKS
A. The analogous Neogene Delta Play of Kutei basin of 17.5 million acres has an es-
timated 270,000 acres of untested trap. By analogy, this smaller (8 million
acres) play would have 123,000 acres of untested trap.
B. Onshore exploration has been very successful with wildcat success rate of about
39 percent. Offshore this rate is only 8 percent, hampered by poor trap resolu-
tion caused by shallow base-Pliocene unconformity and seismic reflection-dampen-
ing bottom conditions. I estimate future wildcat success as exploration moves
offshore to be 20 percent. This, with a fill of 40 percent (analogous to Kutei
folds), indicates 8 percent of untested trap to be productive.
C. As discussed in the text, the best estimate i can make is 140 ft.
D. Production to date indicates both oil and gas. I estimate that in this relatively
shallow play, i.e., less than 10,000 ft, oil would predominate, say 60 percent.
E. Estimated porosity is 25 percent (20 to 26 percent at Sembakung). Assuming reservoir
parameters to be average, 'I estimate a primary recovery of 250 barrels per acre-ft.
F. Assuming an average depth to gas reservoirs (near base of play) of 8,000 ft and
a thermal gradient of 2.35°F per 100 ft, I estimate a gas recovery of 1.076
million cubic ft per acre-foot.
G. World-wide average.
Limiting Factor: Amount of trap in offshore part of area is very conjectural.
Total resources for all plays in basin: .234 BBO, 1.2 TCFG, .014 BBNGL, .449 BBOE

182
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
RASIN Tarakan, No. 8 COUNTRY Indonesia PLAY Plio-Pleistocene Folds, No. 3
AREA OF BASIN (Mi z )f6,250 AREA OF PLAYTMMA) 6.9
VOLUME OF BASIN (Mi 3!30,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES .469 BBO 0.5 TCFG ,400(?) BBO -- TCFG
TECTONIC CLASSIFICATION OF BASIN: Back-arc
DEFINITHJN AND AREA OF PLAT: Shallow petroleum accumulations in relatively gentle
folds of Plio-Pleistocene deltaic sandstones overlying a regional, profound unconfor-
mity. Play covers largely offshore two-thirds of basin, an area of about 6.9 million
acres (fig. 48).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .005 .020 .050

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) .5 .7 1.5
C. AVERAGE EFFECTIVE PAY (feet) 75 300 800
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 20 70 90
E. OIL RECOVERY (BBLS/AF) 100 100 200
F. GAS RECOVERY (MCF/AF) 100 100 500
G. NGL RECOVERY (BBLS/MMCFG) 7 11 22
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .003 BB, GAS .001 TCF, NGL 0 BB, OE .004 BBOE

REMARKS
A. These shallow, simple anticlinal traps have been mapped and drilled, and only
relatively small untested traps appear to remain; I estimate possible 20,000
acres.

B. Aside from small production-adjoining closures on Tarakan and Bunju Islands, no

discoveries have been made since 1930's. A low success rate of 2 percent is
assumed. If fill is 35 percent, untested trap area which would contain petroleum
is 0.7 percent.

C. 700 ft of net sand in 12 pays is reported at Tarakan, I estimate an average

of about 300 ft for the entire play.

D. No gas is produced at Tarakan, but some is at Bunju. Because of generally poor

seal, I estimate that oil is at least 70 percent of the gas-oil mix.

E. Porosities appear good, i.e. 20 to 38 percent, but water saturation is

extremely high in Tarakan, i.e. about 95 percent; oil recovery factor is 50
percent. If these characteristics prevail over the play, the average recovery
is 100 barrels per acre-foot - barely commercial onshore.

F. Considering the shallow reservoir depth (perhaps 1,500 ft) and the high water
saturation, only about 100,000 ft3 per acre-foot may be expected.

G. World-wide average.

Limiting Factors: Lack of remaining untested traps and high water saturation in
reservoi rs.

Total resources for all plays in basin: .234 BBO, 1.2 TCFG, .014 BBNGL, .449 BBOE

183
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN West Natuna, No. 9 COUNTRY Indonesia PLAY Oligocene Drapes, No. 1
AREA OF BASIN (Mi'-) 34,000 AREA OF PLAY (MMA) 1570
VOLUME OF BASIN (Mi 3 ) 45,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES .402 BBO TCFG .2(1} BBO TCFG
TECTONIC CLASSIFICATION OF BASIN: Rift
DEFINITION AND AREA OF PLAY: Potential petroleum accumulations in largely Oligocene
sandstones draped over Oligocene (or older) fault blocks. Play largely restricted to
basin perimeter (depth <10,000 ft) where redistributing drag folds are less
prevalent and where basal sandstones developed (fig. 51 and 53).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .25 .63 1.00
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 2.5 7.0 10.0
C. AVERAGE EFFECTIVE PAY (feet) 50 86 200
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 30 50 70
E. OIL RECOVERY (BBLS/AF) 100 216 350
F. GAS RECOVERY (MCF/AF) 400 790 1,000
G. NGL RECOVERY (BBLS/MMCFG) 7 11 22

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .410 BB, GAS 1.500 TCF, NGL .016 BB, OE .676 BBOE

REMARKS

A. Extrapolation from a limited area map indicates 7 percent of play under closure.
With play area of 15 million acres on basin perimeter, this is 1.05 million acres
of trap area. An estimated 40 percent has been tested leaving 630,000 acres
untested.

B. Wildcat success rate for all plays appears to be 17 percent; it is assumed the
Oligocene drape play has about the same success rate. The Udang Field appears
to be about 44 percent filled. Assuming this is an average for the basin, it
appears that about 7 percent of the untested trap area may be productive.

C. The average net pay of the Udang Field is reportedly 86 ft, and this is assumed
to be the average for the play.

D. Udang Field production is about two-thirds oil, but this may be selective. I
estimate oil may average half of the oil-gas mix.

E. Assuming average, conservative reservoir parameters, i assume 216 barrels per

acre-foot.

F. Assuming an average reservoir depth of 5.000 ft, a thermal gradient of 2.2°F

per 100 ft, a gas recovery of 790,000 ft-* per acre-foot is indicated.

G. World-wide average.

Limiting Factor: Small volume of source rock available in this shallow basin.

Total resources for all plays in basin: .655 BBO, 3.410 TCFG, .037 BBNGL, 1.259 BBOE

184
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN West Natuna, No. 9 COUNTRY Indonesia PLAY Miocene Drag Folds, No. 2
AREA OF BASIN (Mi 2 ) 34,000 AREA OF PLAY (MMA) 7.0
VOLUME OF BASIN (Mi 3!45,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES .402 BBO _- TCFG .2(1} BBO 0 TCFG
TECTONIC CLASSIFICATION OF BASIN: Rift
DEFINITION AND AREA OF PLAY: Potential petroleum accumulations in Miocene drag
folds of central basin areas involving Oligocene and Miocene reservoirs. Play area
largely limited to thicker (>10,000 ft) part of basin fill where this type of folds
can develop (figs. 51 and 54).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .20 .21 .80

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 2.5 9.0 15.0
C. AVERAGE EFFECTIVE PAY (feet) 50 200 400
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 15 30 70
E. OIL RECOVERY (BBLS/AF) 100 216 350
F. GAS RECOVERY (MCF/AF) 400 723 1,000
G. NGL RECOVERY (BBLS/MMCFG) 7 11 22

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .245 BB, GAS 1.91 TCF, NGL .021 BB, OE .583 BBOE

REMARKS

A. Extrapolation from an unpublished map limited area indicates that about 5 percent
of the play area is drag fold closure. This corresponds with other areas of
analogous drag folds associated with wrench faults, e.g. Central Sumatra has 5.5
percent drag fold closure. 40 percent of these drag folds may have been tested,
leaving an untested trap area of 210,000 acres.
B. The wildcat success rate (1982) for all plays was 17 percent; I assume this holds
also for this play. The KH Field has a fill of 55 percent, and this is taken as
the average percentage fill for this play, indicating that 9 percent of the
untested trap area may be productive.
C. Although 375 ft of pay (gross?) was reportedly tested at Anoa-1, the sandstones thin
eastward and are thin or missing over the larger anticlines. Oligocene sandstones
of 40 to 190 ft thickness occur in the anticlines, and a combined average thickness
of 200 ft is assumed for both Oligocene and Miocene sandstones.
D. The Anoa-1 test found 315 ft of gas and 60 ft of oil. I estimate that oil is
about 30 percent of the petroleum mix in this play.
E. Assuming average conservative reservoir parameters, I estimate an oil recovery
of 216 barrels per acre-foot.
F. Assuming an average reservoir depth of 4,500 ft and a thermal gradient of 2.2°F
per 100 ft, the average gas recovery is 723,000 ft 3 per acre-foot.
G. World-wide average.

Limiting Factor: The limiting factor, especially in contrast to this same oil play,
prolific in the adjoining Malay basin, is probably the smaller volume of source
rock in this shallower basin.

Total resources for all plays in basin: .655 BBO, 3.410 TCFG, .037 BBNGL, 1.259 BBOE

185
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN East Natuna, No. 10 COUNTRY Indonesia PLAY Drapes, No. 1
AREA OF BASIN (Mi 2 ) 27,000 AREA OF PLAY (MMA)1773
VOLUME OF BASIN (Mi 3 ) 57,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 0 BBO 60* TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF BASIN:
Rifted Continental Margin
DEFINITION AND AREA OF PLAY: Potential petroleum accumulations in Oligocene to
Middle Miocene sandstones in drape or fault closures. Play area encompasses the
entire basin (fig. 60).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .20 .80 1.50

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 5 10.5 16
C. AVERAGE EFFECTIVE PAY (feet) 75 100 200
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 15 20 60
E. OIL RECOVERY (BBLS/AF) 75 86 200
F. GAS RECOVERY (MCF/AF) 100 467 900
G. NGL RECOVERY (BBLS/MMCFG) 7 11 22

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .145 BB, GAS 3.13 TCF, NGL .035 BB, OE .703 BBOE

REMARKS
A. From observation of unpublished maps, I estimate that some 6 percent, or about
1.0 million acres of play area is under drape or fault closure. If 20 percent of
the closures have been tested, the remaining untested trap is .80 million acres.
B. Early wildcat success was nil possibly because this- was usually a secondary objec-
tive of wells testing younger carbonates. Eight recent wildcats with this play as
an objective were dry but with some shows. Deep Vietnam wildcat, Oua-IX, 20 miles
to north was an oil discovery. I estimate future wildcat success will be about
15 percent. On the basis of almost 100 percent fill at AL-IX, 70 percent fill is
estimated for the basin, indicating 10.5 percent of trap area will be productive.
C. Reportedly the net reservoir thickness is 175 ft in the northern, shelfal, part
of the basin but it thins to the south. I estimate 100 ft as average for basin.
D. The basin appears to be gas prone from occurrence to date. While the younger
reefs encased in overpressured shale produced gas, these lower sandstones may not
be so overpressured, allowing some primary migration of C5 + molecules. I deem
this play has at least 20 percent oil.
E. Assuming 20 percent porosity and average reservoir parameters, and estimating
the 60 percent of reservoir space occupied by carbon dioxide.
F. Assuming same reservoirs, average depth of about 12,000 ft, thermal gradient of
2.5°F per 100 ft, and that reservoir 60 percent occupied by carbon dioxide.
G. World-wide average.
Limiting Factors: Principal one is occupation of reservoirs by carbon dioxide. Lim-
iting for oil is an inhibiting effect on primary migration by overpressured shale.
* An estimated 60 TCFG is discovered but unproduced at AL-IX.
Total resources for all plays in basin: .308 BBO, 20.07 TCFG, .7.7.1 BBNGL, 3.665 BROE

186
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN East Natuna, No. 10 COUNTRY Indonesia PLAY Miocene Reefs, No. 2
AREA OF BASIN (Mi*) 27,000 AREA OF PLAY (MMA) TO"
VOLUME OF BASIN (Mi 3!57,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 0 BBO 60* TCFG 0 BBO 60* TCFG
TECTONIC CLASSIFICATION OF BASIN: Rifted Continental Margin
DEFINITION AND AREA OF PLAY: Potential petroleum accumulations are in upper Miocene
(Terumbu Fm.) reefs and platform carbonate reservoirs in drapes or fault traps. Play
limited to carbonate platform area, which covers approximately 60 percent of basin
(fig. 60).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .05 .35 .50

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 5 14 20
C. AVERAGE EFFECTIVE PAY (feet) 100 700 4,000
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 2 5 50
E. OIL RECOVERY (BBLS/AF) 80 95 300
F. GAS RECOVERY (MCF/AF) 100 520 900
G. NGL RECOVERY (BBLS/MMCFG) 7 11 22

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .163 BB, GAS 16.94 TCF, NGL .186 BB, OE 2.962 BBOE

REMARKS

A. From observation of unpublished maps of part of play area, I estimate about 7

percent of carbonate platform is reefal, of which about half has been tested.
B. There is one substantial discovery, AL-IX, with indicated reserves of some 60
TCFG. However some wildcats have had sizeable oil and gas shows which may even-
tually be considered commercial. I estimate an eventual success rate of 20
percent. The AL-IX trap appears completely full while the shows only fill small
parts of the closure, e.g. Bursa-1 is 15 percent. I estimate 70 percent fill,
indicating 14 percent of untested trap area will be productive.
C. The only substantial recovery, AL-IX, has 5,250 ft of porosity, 1,750 ft reef
porosity of 28.4 percent and 3,500 ft of platform porosity of 14.5 percent.
This thickness is exceptional, and I estimate the remaining, smaller traps will
average around 700 ft.
D. Although some oil is present (notably Bursa-IX), this play is gas prone, particularly
the deeper reefs which may be amid overpressured shale. i estimate that the
petroleum mix is 95 percent gas.
E. On basis of an average 22 percent porosity (C above) and assuming average parame-
ters, primary recovery only, and 60% of pore space occupied by carbon dioxide.
F. Assuming above reservoirs, an average depth of 10,000 ft, a 2.5°F per 100 ft
thermal gradient, and 60 percent pore occupancy by carbon dioxide.
G. In absence of data, assume world-wide average.
Limiting Factor: Overall, a high carbon-dioxide reservoir content. For oil, it is
the apparent lack of primary migration through overpressured shales.
*An estimated 60 TCFG is apparently discovered but unproduced at AL-IX.
Total resources for all plays in basin: .308 BBO, 20.07 TCFG, .221 RRNGL, 3.665 RROE

187
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Salawati-Bintuni, No. 11 COUNTRY Indonesia PLAY Salawati-Miocene Reefs, No. 1
AREA OF BASIN (Mi 2 )56,000 AREA OF PLAY (MMA) 1.5
VOLUME OF BASIN (Mi 3 ) 105,1)00" PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES ___.415 BBO TCFG .415 BBO TCFG
TECTONIC CLASSIFICATION OF "BA3TN: Foreland and collision zone
nEFINTTTON AND AREA OF PLAY: Potential petroleum accumulations in Miocene carbon,
ates of Sal awati subbasin. Area confined between 4 and 5 km basin-fill isopachs,
the thinner fill area having insufficient cover and the thicker fill being defi-
cient in reservoirs (fig. 64; area 1, fig. 69).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .020 .027 .040
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 3 5 12
C. AVERAGE EFFECTIVE PAY (feet) 30 165 700
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 60 90 95
E. OIL RECOVERY (BBLS/AF.) 300 530 600
F. GAS RECOVERY (MCF/AF) 800 450 1,700
G. NGL RECOVERY (BBLS/MMCFG) 8 50 100
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .106 BB, GAS .010 TCF, NGL .00 BB, OE .108 BBOE

REMARKS
A. A published map (fig. 70) indicates that carbonate reefs make up 6 percent of
the play area or about .09 MMA. Exploration deemed 70 percent complete, leaving
27,000 acres untested trap.
B. Late wildcat success rate has been about 20 percent. Fill is extremely variable
(Walio-23, Sele-2, Kasim-25, Kasim Utera-50 percent). I estimate average fill
of 25 percent, indicating a productive trap area of 5 percent.
C. Net pay thickness varies from 30 to 700 ft. I estimate an average of 165 ft.
D. On the basis of evident water drive and poor seal (fracturing) for gas, 'I
estimate 90 percent oil.
E. Oil recovery varies considerably because of unpredictable fracturing and
porosity; I assume that the published recovery of the Kamono Field, 530 bbls
per acre-foot, may be average.
F. Assuming average reservoir conditions, a thermal gradient of 3°F per 100 ft, and
an average depth of 3,500 ft, 'I estimate the average gas recovery to be about
450 MCF/AF.
G. Average of Magoi and Wasian Fields.
Limiting Factor: The factor appears to be the seal. On the edges of the basin where
cover is thin, large traps are empty or have a low percentage of fill.
Total resources for all plays in basin: .647 BBO, 2.322 TCFG, .115 BBNGL, 1.145 BBOE

188
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Salawati-Bintuni, No. 11 COUNTRY Indonesia PLAY Bintuni Miocene Reefs, No. 2
AREA OF BASIN (Mi^) 56,000 AREA OF PLAY (MMA) 5.0
VOLUME OF BASIN (Mi 3 ) 105,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES .415 BBO TCFG BBO TCFG
TECTONIC CLASSIFICATION OF BASIN: Foreland and collision zone

DEFINITION AND AREA OF PLAY: Potential petroleum accumulations in Miocene carbonate

buildups in Bintuni subbasin. Area of play limited by effective cover of Klasafet
shales and concentrated along carbonate shelf edge (area 2, fig. 69).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .05 .15 .25
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 1 1.5 6
C. AVERAGE EFFECTIVE PAY (feet) 30 165 700
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 20 50 90
E. OIL RECOVERY (BBLS/AF) 300 530 600
F. GAS RECOVERY (MCF/AF) 800 1,750 2,000
G. NGL RECOVERY (BBLS/MMCFG) 8 50 100
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .098 BB, GAS .324 TCF, NGL .016 BB, OE .168 BBOE

REMARKS
Reefs analogous to Salawati are indicated but not proven, therefore 3 percent of
area is assumed reef trap (versus 6 percent for Salawati). Nine wildcats have
have failed to find a viable reef (Wiriagar is considered primarily a drape structure)
Reefs appear to be small requiring a fine seismic net.
Although Miocene reefa! carbonate is evident, no reef accumulations were discov-
ered. However, I estimate a 5 percent success rate will develop. Because of
better cover, the fill is deemed to be somewhat more than the similar Salawati
subbasin traps, or about 30 percent, indicating approximately 1.5 percent of the
untested trap area will be productive.
In the absence of data, the average effective pay is deemed the same as the
geologically similar Salawati subbasin.
Originally the percent of oil in oil-gas mix was probably similar in both Sala-
wati-Bintuni subbasins, but owing to thicker cover, less gas escaped from the
Bintuni subbasin; so about 5 times as much gas is postulated, or about 50 percent.
Oil recovery is assumed to be the same as that for the Salawati subbasin.
The objective carbonate traps appear to average about 12,000 ft in depth and the
thermal gradient is about 1.6°F per 100 ft, indicating a gas recovery of about
1,750 MCFG/AF.
Average of Magoi and Wasian Fields.
Limiting Factors: The limiting factors are the apparent small size and depth of the
reefs.
Total resources for all plays in basin: .647 BBO, 2.322 TCFG, .115 BBNGL, 1.145 BBOE

189
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Salawati-Bintuni, #11 COUNTRY Indonesia PLAY Miocene Drapes, No. 4

AREA OF BASIN (Mi 2 ) 56,000 AREA OF PLAY (MMA)T2771
VOLUME OF BASIN (Mi 3 ) 105,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES .415 BBO 0 TCFG BBO TCFG
TECTONIC CLASSIFICATION OF BASIN: Foreland and collision zone

DEFINITION AND AREA OF PLAY:Drapes over northwest-trending pre-Tertiary ridges.

Area of play limited to Bintuni subbasin outside Lengguru Foldbelt, but including
recently folded carbonates in northeast Bintuni subbasin (area 3 and 4, fig. 69).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .500 .528 1.00
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 1 3 7
C. AVERAGE EFFECTIVE PAY (feet) 30 83 200
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 20 70 90
E. OIL RECOVERY (BBLS/AF) 100 215 300
F. GAS RECOVERY (MCF/AF) 400 819 1,700
G. NGL RECOVERY (BBLS/MMCFG) 8 50 100

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .198 BB, GAS .323 TCF, NGL .016 BB, OE .267 BBOE

REMARKS
A. By estimation from unpublished map of part of play area, traps make up 5.5 per-
cent of area. On this basis there are .66 MMA of trap of which 20 percent has
been tested.
B. Discovery rate has been about 10 percent. Assumed fill is 30 percent (world
average), indicating 3 percent untested trap area will be productive.
C. These drapes are over older ridges, which may be sites for reef carbonates;
however reservoir development would be less than expected for the strictly reef
plays. I estimate carbonate and sandstone reservoir would average perhaps half as
thick as the Salawati Reef reservoirs, or some 83 ft.
D. Assumed to be intermediate to Salawati and Bintuni reef plays reflecting the
intermediate depth of burial.
E. Assuming that the average porosity is about 20 percent (Mogoi and Wasian average
about 14 percent, but porosities at Bintuni-Al averaged 32 percent, and Wiriager
is assumed to be about the same).
F. Assuming the same reservoirs and an average depth somewhere between that of the
Bintuni subbasin (12,000 ft) and the Salawati subbasin (3,500 ft), say 9,000 ft.
G. Average of the Mogoi and Wasian Fields.
Limiting Factor: The limiting factor is probably the presence of reservoir develop-
ment and, therefore, favorable traps along these pre-Tertiary ridges.
Total resources for all plays in basin: .647 BBO, 2.322 TCFG, .115 BBNGL, 1.145 BROF

190
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Salawati-Bintuni, No. 11 COUNTRY Indonesia PLAY Cretaceous Drapes
AREA OF BASIN (Mi*) 56,000 No. 3
VOLUME OF BASIN (Mi 3 ) 144,000 AREA OF PLAY (MMA)1876
ESTIMATE ORIGINAL RESERVES .415 BBO 0 TCFG PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Foreland and 0 BBO 0 TCFG
collision zone
DEFiNITTTJN AND AREA OF PLAY: /^cumulations in faulted and draped Cretaceous which
are largely limited to the Bintuni subbasin, exclusive of the foldbelt and including
the Misool-Onin-Kumawa ridge area (area 3 and 4, fig. 69).
PROBABILITY DISTRIBUTION
\ MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .500 .920 2.000

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 1 3 10
C. AVERAGE EFFECTIVE PAY (feet) 50 100 500
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 15 40 50
E. OIL RECOVERY (BBLS/AF) 150 180 450
F. GAS RECOVERY (MCF/AF) 400 960 2,500
G. NGL RECOVERY (BBLS/MMCFG) 8 50 100

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .200 BB, GAS 1.60 TCF, NGL .080 BB, OE .543 BBOE

REMARKS
A. Cretaceous shelfal sediments are faulted or draped over low-relief tilted horst
ridges. Examination of unpublished maps over parts of subbasin indicate an aver-
age of 5.5 percent of subbasin is under drape closure. Of this, perhaps 10
percent has been tested, leaving about 920,000 acres.
B. Six wildcats have been unsuccessful. However, on basis of generally favorable
geology, i assume a future success rate of 10 percent. With no data, I
assume a 30 percent fill indicating about 3 percent of trap would be productive.
C. Great thicknesses of sandstone (Kembelangan Group) are reported in outcrops,
but no specific reservoir parameters are available. i assume at least 100 ft
of effective reservoir (with porosity of 15 percent).
D. Because of great depth, over 20,000 ft in central part of Bintuni subbasin, I
estimate the petroleum to be largely gas, perhaps 60 percent.
E. Assuming average reservoir parameters, it is estimated that 300 barrels of oil
would be produced per acre-foot of trap volume.
F. Assuming average reservoir, and reservoir depths of 10,000 to 12,000 ft.
G. Average of Magoi and Wasian Fields.
Limiting Factor: Although average estimates are made for reservoir volume on the
basis of outcrops, the existence of viable reservoirs at depth is unknown.
Total resources for all plays in basin: .647 BBO, 2.322 TCFG, .115 BBNGL, 1.145 BBOE

191
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Salawati-Bintuni, No. 11 COUNTRY Indonesia PLAY Neogene Folded Sandstones, No

AREA OF BASIN (Mi 2 ) 56,000 AREA OF PLAY (MMA) 6.14
VOLUME OF BASIN (Hi 3 ) 144,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES .415 BBO 0 TCFG BBO TCFG
TECTONIC CLASSIFICATION OF BASIN: Foreland and collision zone

DEFINITION AND AREA OF PL7\Y: Potential accumulations in Pliocene anticlinal folds

involving essentially Neogene elastics and limited to Lengguru Foldbelt of the
Eastern Bintuni subbasin (area 5, fig. 69).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .100 .307 .500
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 1 1.5 6
C. AVERAGE EFFECTIVE PAY (feet) 30 50 200
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 30 90 95
E. OIL RECOVERY (BBLS/AF)" 120 200 350
F. GAS RECOVERY (MCF/AF) 300 750 1,000
G. NGL RECOVERY (BBLS/MMCFG) 8 50 100

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .041 BB, GAS .017 TCF, NGL .001 BB, OE .045 BBOE

REMARKS
A. By analogy to the percentage of trap area to play area of similar young foldbelts
in Indonesia (e.g. Kutei basin about 3 percent, Nerth Sumatra about 8 percent),
I estimate 5 percent.
B. About four wildcats have tested this play, but perhaps only one was definitive,
Suga-1, which was a reported gas discovery. Traps will be difficult to find in
these complex folds; I estimate a success rate of only 10 percent. Leakage
would be high; we estimate a fill of 15 percent, indicating 1.5 percent of trap
area would be productive.
C. Visser and Hermes, 1962, indicate poor reservoir development; I estimate average
net pay of only 50 ft. Reservoirs may be from the Kembalangan Group, the New
Guinea Limestone Group, or the Klasaman-Steenkool sandstones.
D. Two oil seepages occur. Sealing is weak. Ry analogy to the Salawati subbasin,
I estimate oil is 90 percent of oil-gas mix.
E. Poor reservoirs are indicated; I estimate 200 BO/AF.
F. Assuming average depth of 8,000 ft, the average gas recovery is estimated to be
750 MCFG/AF.
G. Average of Mogoi and Wasian Fields
Limiting Factors: The limiting factors, according to Visser and Hermes, are the
amount and quality of the reservoirs. Rich source rocks are yet to he demonstrated.
Total resources for all plays in basin: .647 BBO, 2.322 TCFG, .115 BBNGL, 1.145 BBOE

192
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Salawati-Bintuni, No. 11 COUNTRY Indonesia PLAY Salawati Pliocene

AREA OF BASIN (Mi 2 ) 567000 Diapirs, No. 6
VOLUME OF BASIN (Mi 3 ) 144,000 AREA OF PLAY (MMA) 1.53
ESTIMATE ORIGINAL RESERVES .415 BBO TCFG PLAY EST. ORIG. RESERVES
TECTONIC CLASSIFICATION OF BASIN: Foreland and _. BBO TCFG
collision zone
DEFINITION AND AREA OF PLAY: Accumulations in Pliocene sandstones involved in diapir
anticlines in the deeper, basinal part of the Salawati subbasin (area 6, fig. 69).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .100 .154 .200

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) .001 1.0 5.0
C. AVERAGE EFFECTIVE PAY (feet) 25 50 200
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (*) 1 30 70
E. OIL RECOVERY (BBLS/AF) 100 160 300
F. GAS RECOVERY (MCF/AF) 700 900 1,800
G. NGL RECOVERY (BBLS/MMCFG) 8 50 100
PRTTDUCT OF MOST
LIKELY PROBABILITIES: OIL .004 BB, GAS .048 TCF, NGL .002 BB, OE .014 BBOE

REMARKS

A. From a measurement of traps jm an unpublished map, there are approximately

.154 million acres untested trap indicated.

B. Only one test of a diapir was dry hole and no further tests were made indicating
probable low rate of future success, say 3 percent. No fill data; I assume 30
percent (world-average) indicating productive area of 1 percent.

C. Section must be mostly shale; sandstones would be thin; j estimate an average of

about 50 ft.

D. The play is obviously in an overpressured shale deep where primary oil migration
is inhibited. I estimate at least 70 percent gas.

E. Section mostly on shale; basin reservoirs probably poor, say 15 percent porosity.

F. Assuming same reservoirs and 8,000 ft depth but no overpressuring of reservoir

for most likely case.

G. Average of Magoi and Wasian Fields

Limiting Factor: Sufficient reservoir

Total resources for all plays in basin: .647 BBO, 2.322 TCFG, .115 BBNGL, 1.145 BBOE

193
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Arafura, No. 12 COUNTRY Indonesia PLAY Anticlines, No. 1
AREA OF BASIN (Mi 2 50,000
VOLUME OF BASIN (Mi 3 ) 120,000 AREA OF PLAY (MMA) 11.5
ESTIMATE ORIGINAL RESERVES 0 BBO 0 TCFG PLAY EST. ORIG. RESERVES,
TECTONIC CLASSIFICATION OF BASIN: Foreland and 0 BBO 0 TCFG
collision zone
DEFINITION AND AREA OF PLAY:Play combines two structural plays, drag folds in the
northwestern area of basin (5.1 MMA) and compressional folds along northern edge of
basin involving Mesozoic sandstones (6.4 MMA). Possible drape folds are included in
play (figs. 71 and 72).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .300 .376 .500

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 3 4.5 15
C. AVERAGE EFFECTIVE PAY (feet) 50 200 250
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%} 10 30 90
E. OIL RECOVERY (BBLS/AF) 150 215 450
F. GAS RECOVERY (MCF/AF) 900 1,360 2,200
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .215 BB, GAS 3.22 TCF, NGL .036 BB, OE .782 BBOE

REMARKS
A. By analogy to the wrench-faulted Central Sumatra basin, I assume that drag-fold
closures make up 5.5 percent of the drag-fold area of 5.1 MMA or 280,000 acres.
Compressional folds - i estimate from an outcrop map (Visser and Hermes, 1962) that
about 1.5 percent of compressional fold area (6.4 MMA) is effective trap, or
about 96,000 acres. The percent of trap area tested is considered negligible.
Only two wildcats have been drilled in this play area and both were dry. However,
because the traps are mainly folds, deemed more effective than fault or drape
structures of the adjoining Australian Northwest Shelf (11 percent success as of
1982), 'I estimate a success rate of 15 percent and assume an average fill of 30
percent, indicating 4.5 percent of the trap area is productive.
C. Great thicknesses of Cretaceous sandstones are found in outcrops; I estimate a
conservative average of 200 ft of pay.
An oil seep occurs at the west end of the play area, Discoveries on trend 100
miles to the east in equivalent sandstones are gas. The petroleum fill is assumed
to be about 30 percent oil.

Assuming average reservoir parameters, it is estimated that the average oil

recovery is about 300 barrels per acre-foot.

F. At estimated reservoir depths of 1?,000 to 16,000 ft, the gas recovery is assumed
to be about 1,900 MCFG.

G. In the absence of data, world-wide average figures are assumed.

Limiting Factor: Volume of source rock in this rather cool basin.
Total resources for all plays in basin: .350 BBO, 4.141 TCFG, .046 BBNGL, 1.089 BROE

194
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Arafura, No. 12 COUNTRY Indonesia PLAY Miocene Reefs, No. 2
AREA OF BASIN ( _ 50,000 AREA OF PLAY (MMA) 20.0
VOLUME OF BASIN (Mi 3 ) 120,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES ~~Q BBO 0 TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF MSlN: Foreland and
Collision zone
DEFINITION AND AREA OF PLAY:Area of play is confined to Miocene subbasins where
Miocene reefs are enveloped in Miocene shales. These subbasins are estimated to
makeup 60 percent of the Arafura basin, or about 20 million acres (fig. 71).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .200 .600 1.000
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 1 2.5 5
C. AVERAGE EFFECTIVE PAY (feet) 50 83 150
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 10 30 90
E. OIL RECOVERY (BBLS/AF) 150 300 450
F. GAS RECOVERY (MCF/AF) 500 875 1,500
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .112 GAS .763 TCF, NGL .008 BB, OE .247 BBOE

REMARKS
A. Estimate reefs are only half as prevalent as in the Salawati subbasin or about 3
percent of the play area, indicating an average acreage of 600,000 acres.
B. No reefs have been drilled; we estimate a success rate less than half of that of
the Salawati subbasin (25 percent) or about 10 percent. By Salawati subbasin
analogy, 25 percent fill is assumed indicating an average of 2.5 percent of the
trap area will be productive.
C. On the basis that reefs are probably not as well developed, I estimate half the pay
of the Salawati-Bintuli basin.
D. On the basis of discovery results on-strike, some 100 miles to the east in Papua,
which tested only gas, we assume petroleum is 70 percent gas.
E. We judge that reefs are less developed and probably poorer reservoirs than in the
Salawati-Bintuni basin; assuming average reservoir parameter, I estimate 300
barrels per acre-foot.
F. By analogy to the equally deep and equally cool Bintuni subbasin, but with about
half the reservoir depth, I estimate a yield of 875 ft 3 per acre-foot.
G. World-wide average.
Limiting Factor: The presence of satisfactory reef development is yet to be
demonstrated.
Total resources for all plays in basin: .350 BBO, 4.141 TCFG, .046 BBNGL, 1.089 BBOE

195
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Arafura, No. I?. COUNTRY Indonesia PLAY Am Hinge Area, No. 3
AREA OF BASIN (Mi 2 ) 50,000 AREA OF PLAY (MMA)375
VOLUME OF BASIN (Mi 3 ) 120,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 0 BBO 0 TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF BASIN: Foreland and
Collision zone
DEFINITION AND AREA OF PLAY: The Aru hinge trends northward through Aru Island.
The hinge structure is a densely step-faulted slope westward from the Arafura Plat-
form into the Aru Trough. It has an approximate area of 3.5 million acres (Aru
(Aru subbasin, fig. 71).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .035 .070 .200

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) .5 3 5
C. AVERAGE EFFECTIVE PAY (feet) 50 100 500
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 10 50 90
E. OIL RECOVERY (BBLS/AF) 150 215 500
F. GAS RECOVERY (MCF/AF) 800 1,500 3,000
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20

PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .023 BB, GAS .158 TCF, NGL .002 BB, OE .051 BBOE

REMARKS
A. From unpublished maps of the area, it appears that valid tilted fault-block
closures make up about 2 percent of the play area.
B. The faulted closures do not appear effective. Five wildcats have been dry. Except
for weak closure, other factors appear favorable, and a success rate of 10 percent
is estimated. A 30 percent fill is assumed indicating 3 percent of trap area is
productive.
C. The objective reservoirs are mainly the Kembelangan (Cretaceous) sandstones, which
would have only half the thickness as supposed for the rest of the Arafura (200 ft)
basin, being close to the pinchout of the formation.
D. Seals should not be as efficient in this faulted play so less gas is assumed
than in the other parts of the basin; 50 percent oil is assumed.
E. Assuming average reservoirs and primary recovery.
F. Assuming average reservoir conditions, thermal gradient of 1.65°F per 100 ft,
and average reservoir depth of 10,000 ft.
G. Assuming world-wide average.
Limiting Factor: Effectiveness of fault traps.
Total resources for all plays in basin: .350 BBO, 4.141 TCFG, .046 BBNGL, 1.089 BBOE

196
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Waropen, No. 13 COUNTRY Indonesia PLAY Drag Folds, No. 1
AREA OF BASIN (Mi 2 )24,000 AREA OF PLAY (MMA) 15.36
VOLUME OF BASIN (Mi 3 ) 40,800 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 0 BBO 0 TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF BASIN: Outer Arc
DEFINITION /TND AREA OF PLAY:Petroleum accumulations in Pliocene sandstones in drag
folds associated with east-west sinistral wrench faults, which transect the entire
basin. Diapir folds are, because of data-lack, included in this play (fig. 74).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .300 .845 1.600
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) .5 2 4
C. AVERAGE EFFECTIVE PAY (feet) 40 100 200
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 10 20 40
E. OIL RECOVERY (BBLS/AF) 100 215 400
F. GAS RECOVERY (MCF/AF) 100 1,000 2,000
G. NGL RECOVERY (BBLS/MMCFG) 8 11 21
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .073 BB, GAS 1.352 TCF, NGL .015 BB, OE .314 BBOE

By analogy to the Central Sumatra basin where wrench faulting and associated
drag folds dominate the structure, I estimate that drag-fold traps make up 5.5
percent of the play area or 845,000 acres.
Because of small volume of thermally mature source rock, a 20 percent average
fill is estimated. No discoveries to date; given the relatively poor source,
the poor reservoirs, and unknown, complex structure, I estimate a success rate
of 10 percent, indicating only 2 percent of trap area productive.
Good quartz sandstones make up only a small percentage of the section, given the
graywacke development and volcanic provenances. i estimate an average
effective sandstone pay of 100 ft.
Shows and seeps are largely gas. The basin fill is mainly shale, which appears to
be overpressured, inhibiting th.e primary migration of larger petroleum molecules.
I estimate 80 percent gas.
Reservoirs appear to be poor to fair. Assuming 20 percent average porosity and
average reservoir parameters, i estimate 215 BO/AF as an average.
Assuming the above reservoir, an average depth of 10,000 ft, a thermal gradient
of 1.34°F per 100 ft.
G. World-wide average.

Limiting Factors: The apparent lack of sufficient source-rock volume.

Total resources for all plays in basin: .093 BBO, 1.49 TCFG, .017 RBNGL, .359 BBOE

197
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Waropen, No._13 COUNTRY Indonesia PLAY Drapes and Reefs, No. 2
AREA OF BASIN (Mi 2 24,000 AREA OF PLAY (MMA) 1.6
VOLUME OF BASIN (Mi 3 ) 40,800 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 0 BBO 0 TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF BASIN: Outer Arc
DEFINITION ANQ,AREA OF PLAY:Petroleum accumulations in reefs or draped sandtones
localized by topographic highs on the buried Paleogene island-arc surface. Play area
is taken to be the shallow-basin area approximately along the northern coast (fig. 74)
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .100 .288 .600
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) .5 1 4
C. AVERAGE EFFECTIVE PAY (feet) 50 80 300
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 10 40 40
E. OIL RECOVERY (BBLS/AF) 100 215 400
F. GAS RECOVERY (MCF/AF) 200 1,000 2,000
G. NGL RECOVERY (BBLS/MMCFG) 8 11 21
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .020 BB, GAS .138 TCF, NGL .002 BB, OE .045 BBOE

REMARKS
From an unpublished map, it appears that isolated topographic highs make up about
18 percent of the island-arc surface which, very approximately, is a shallow ridge
along the present north coast of Irian Jaya of 1.6 million acres.
On the basis of the apparent lack of sufficient source and cover, petroleum fill
is deemed to be only 20 percent. No discovery has been made. On the basis of
poor reservoirs and migration distance from the depocenters where generation must
take place, I estimate a discovery rate of only 5 percent.
Lack of data necessitates the lumping of carbonate and sandstone reservoirs. 735
ft of carbonate with three zones of porosity were found at 0-1. Carbonate is mis-
sing from R-l, Niengo-1, and Mamberambo-1; Niengo-1 tested a 110 ft sandstone and
R-l a 22 ft sandstone. On the basis that half the highs may be carbonate capped,
I estimate an average effective pay of 80 ft.
On the basis of a preponderance of gas shows and of thick overpressured shale,
the basin is deemed gas-prone. However, the overpressure may not extend over
all of this rather shallow play. I estimate 60 percent gas.
Assuming 20 percent porosity and average reservoir parameters, i estimate an
average of 215 barrels will be recovered from an acre-foot.
F. Assuming the same reservoirs, a depth of 8,000 ft, and heat gradient of 1.34°F
per 100 ft, an average recovery of about 1,000 MCFG/AF.
G. World-wide average.
Limiting Factor: The apparent lack of sufficient source rock.
Total resources for all plays in basin: .093 BBO, 1.49 TCFG, .017 BBNGL, .359 BBOE

198
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN South Makassar, No. 14* COUNTRY Indonesia PLAY Miocene drapes
AREA OF BASIN (Mi 2 ) 16,310 AREA OF PLAY (MMA)1074
VOLUME OF BASIN (Mi 3 ) 407000" PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 0 BBO 0 TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF MSlN: Rift

DEFINITION AND AREA OFPLAY: Potential petroleum accumulation in Miocene and Plio-
cene sandstones draped over Lower Miocene tilted fault blocks. Play occupies entire
basin (figs. 1, 76, and 77)
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%

A. UNTESTED TRAP AREA (MMA) .050 .260 1.000

B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 0.5 4 10
C. AVERAGE EFFECTIVE PAY (feet) 35 50 200
D. PERCENT OIL VERSUS GAS IN PETROLEUM-FILL (%) 5 15 50
E. OIL RECOVERY (BBLS/AF) 150 233 450
F. GAS RECOVERY (MCF/AF) 400 1,900 2,500
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .018 BB, GAS .840 TCF, NGL .009 BB, OE .041 BBOE

REMARKS
A. By analogy to the East Java Sea basin, about 2-1/2 percent of the play-area is
assumed the most likely trap-area.
B. Assuming some traps and reservoirs are established, a 10 percent discovery rate
is postulated. By analogy to the Kutei basin, the estimated trap area filled is
40 percent, giving a most likely figure of 4 percent as the amount of trap area
productive.
C. In this deep basin, abyssal shales are expected to dominate with negligible reef
development and minor sandstones around the perimeter. The most likely average
effective pay is estimated to be 50 ft.
D. Percent of oil is deemed low in this largely shale basin; 15 percent is estimated
(Kutei basin, 20 percent).
E. Analogous to Kutei basin.
F. Analogous to Kutei basin.
G. World-wide average estimate.

Limiting Factors: Postulated lack of reservoirs

*Kartaadiputra (1932), and Situmorang (1982).

199
 Figure 76. Isopach of south Makassar basin.

P606
hi

Co Late-Mid
4 J MIc
Miocene
-C2 Early Ml(
Eafly Miocene
6
C.Pre-Tertiary

3ure 77.--West-east geologic section across west flank of south Makassar basin.

200
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM
BASIN Sumatra Outer Arc, #15* COUNTRY Indonesia PLAY Miocene Reefs, No. 1
AREA OF BASIN (Mi 2 )97,000 AREA OF PLAY (MMA)15
VOLUME OF BASIN (Mi J )200,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES _0_ BBO ____0 TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF RASIN: Fore Arc
DEFINITION AND1TREA OF PLAY: Reef play would be limited to basin perimeter; esti-
mate 25 percent or around 15 MMA. There may be a second play, i.e. sandstones, but
the folded Paleogene are indurated and tectonized and the Neogene beds have little
structure or porosity (figs. 1, 78, and 79).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .200 .900 2.000
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 1.0 1.5 5.0
C. AVERAGE EFFECTIVE PAY (feet) 50 74 200
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 5 10 60
E. OIL RECOVERY (BBLS/AF) 100 200 400
F. GAS RECOVERY (MCF/AF) 200 500 1,000
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .020 BB, GAS .450 TCF, NGL .005 BB, OE .100 BBOE

REMARKS
A. Reef frequency and sizes deemed analogous to Salawati subbasin (i.e. 6 percent),
giving an average trap area of .9 MMA.
B. One gas discovery from 21 wildcats = about 5 percent success (Muelabach-1,
.7 MMCFCD). Fill estimated to be 30 percent, giving 1.5 percent untested trap
productive (gas). This low percentage is supported by analogies to other fore-
arc basins which have similar low thermal gradients, i.e. about 1.3°F per 100 ft.
C. Using Muelabach as an example, the average pay would be 74 ft.
D. Muelabach gas and other gas shows were dry gas. Some oil seeps occur onshore;
I assume about 10 percent of petroleum mix is oil.
E. Assuming average to poor reservoir parameters, I estimate an average recovery
of 200 barrels per acre-foot.
F. Assuming principal objective, middle Miocene reefs, at 4,000 ft, average thermal
gradient of 1.3°F per 100 ft, and recovery factor of 80 percent.
G. Assume world-wide average.
Limiting Factor: Low thermal gradient (ave. 1.3°F/100 ft) puts top of mature source
rock at about 13,000 ft (4 km), too deep to affect most Neogene rock but will
affect some tectonized Paleogene. Poor sand reservoirs.
*Rose (1983).

201
 INDIAN OCEAN

6°
CONTOUR INTERVAL-1 KILOMETER

100 200 KILOMETERS

8°

106°

Figure 78.--Map showing tectonic elements and isopach of Neogene sediments,

Sumatra Outer Arc basin. After Hamilton (1979).

202
 sw OUTER ARC / NIAS ISLANO SW SUMATRA 8ASIN

S»o Itvtl

O
CO

Figure 79.--Geologic cross-sections, A-A1 , across the Sumatra Outer Arc basin.
After Kartaaduputra (1982).
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Java Outer Arc, No. 16* COUNTRY Indonesia PLAY Miocene Reefs, No. 1
AREA OF BASIN (Mi 2 )50,000 AREA OF PLAY (MMA)8
VOLUME OF BASIN (Mi 3 ) 120,000 PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES 0 BBO ____ TCFG 0 BBO 0 TCFG
TECTONIC CLASSIFICATION OF BASIN: Fore Arc
DEFINITION AND AREA OF PLAY: Reef play area would be on highs and perimeter of
basin; estimate 25 percent of basin. Tertiary sandstones might be a second play, but
the Paleogene appears too tectonized and volcanic, and the largely seismically
opaque, Neogene lacking in trap structure; and so not considered (figs. 1, 79 and 80)
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .100 .480 1.00
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 1.0 1.5 5.0
C. AVERAGE EFFECTIVE PAY (feet) 50 74 200
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 5 10 60
E. OIL RECOVERY (BBLS/AF) 100 200 400
F. GAS RECOVERY (MCF/AF) 200 500 1,000
G. NGL RECOVERY (BBLS/MMCFG) 8 11 20
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .011 BB, GAS .240 TCF, NGL .003 BB, OE .054 BBOE

REMARKS

A. By analogy to the Sumatra Outer Arc (and Salawati subbasin), 6 percent of play
area is under trap.
B. By analogy to the Sumatra Outer Arc, untested trap area will be around 1.5
percent productive.
C. By analogy to the Sumatra Outer Arc, average effective pay around 74 ft.
D. By analogy to the Sumatra Outer Arc.
E. By analogy to the.Sumatra Outer Arc.
F. About same average depth (4,000 ft) and thermal gradient (1.3°F per 100 ft) as
the Sumatra Outer Arc.
G. World-wide average.

Limiting Factor: Low thermal gradient indicates that the oil-generating zone is
below the Neogene in the largely tectonized melange dominated
Paleogene sediments. Poor sand reservoirs.
*Bolliger and de Riuter (1975).

204
ro
o
en

Figure 80.--Map showing tectonic elements and isopach of Neogene sediments, Java
outer arc basin, contour interval 1 kilometer, after Hamilton (1979).
 PLAY ANALYSIS SUMMARY OF UNDISCOVERED PETROLEUM

BASIN Bone-Senkang No, 17 COUNTRY Indonesia PLAY Carbonate Buildups,

AREA OF BASIN (Mi 2 ) 22,400 AREA OF PLAY (MMA)375
VOLUME OF BASIN (Mi 3 ) 40~000~ PLAY EST. ORIG. RESERVES,
ESTIMATE ORIGINAL RESERVES ___ BBO .75 TCFG(unproduced) ___BBO .75 TCFG
TECTONIC CLASSIFICATION OF BASIN: Fore-Arc

DEFINITION AND AREA OF PLAY:Only appreciable reservoirs appear to be carbonate

buildups. Area of play is assumed to be limited to periphery of basin or about one-
fourth the basin area or approximately 3.6 mi 11ion acres (fig. 1).
PROBABILITY DISTRIBUTION
MOST
MAJOR GEOLOGICAL/EXPLORATION FACTORS 95% LIKELY 5%
A. UNTESTED TRAP AREA (MMA) .10 .18 .50
B. PERCENT UNTESTED TRAP AREA PRODUCTIVE (%) 3 7.5 15
C. AVERAGE EFFECTIVE PAY (feet) 50 200 700
D. PERCENT OIL VERSUS GAS IN PETROLEUM FILL (%) 2 4 10
E. OIL RECOVERY (BBLS/AF) 200 300 400
F. GAS RECOVERY (MCF/AF) 200 424 1,000
G. NGL RECOVERY (BBLS/MMCFG) 7 11 22
PRODUCT OF MOST
LIKELY PROBABILITIES: OIL .032 BB, GAS 1.10 TCF, NGL .012 BB, OE ,227 BBOE

REMARKS
A. From an explored onshore part or subbasin (East Senkang, Grainge & Davies, 1983
map), it appears that 5 percent of that area is trap. Extrapolation over play-
area indicates an untested trap area of .18 MMA.
B. Wildcat success rate to date is about 25 percent, average fill about 30 percent,
indicating about 7.5 percent trap area productive.
C. Gross pay at wildcat K.B.-l is shown as 75 m (230 ft), average net pay of Kampung
Baru field reportedly 99 m (300 ft). I estimate 200 ft as average pay over play
area.
D. Grainge and Davies indicate 4 percent oil or condensate, 96 percent gas in K.B.
field. I take this as average for play.
E. Oil recovery on basis of 28 percent average porosity + average parameters.
F. Assume average depth of 700 m (2,300 ft) and thermal gradient of 1.4°F/100 ft.
G. World-wide average.

Limiting Factor: The volume of trap and reservoir is extrapolated into the largely
unknown offshore area.

206
 Conclusion: assessments of undiscovered recoverable petroleum
Resource estimates were made by consensus of a group of eight geologists
of The World Energy Resources Program of the U.S. Geological Survey on the
basis of a geologic review of the principal petroleum basins of Indonesia, as
presented In this report, Including the play analyses. These estimates were
made of the undiscovered recoverable oil and gas In the four main groups of
basins In Indonesia, I.e., Sumatra/Java, Kalimantan, Natuna, and Irlan Jaya.
The following consensus estimates were made In ranges of three values,
with a value for the mode (most likely), a low value with a 95-percent
probability that the resource quantity will exceed It, and a high value with a
5-percent probability that the resource quantity will exceed It.
Oil Gas
(billions of barrels) (trillions of cubic ft)
95% ML 5% 95% ML 5%
Sumatra-Java 1.5 3.3 5.9 8.2 17.2 32.9
Kalimantan 0.8 1.8 4.1 11.0 21.5 41.9
Natuna 0.4 1.1 2.8 11.0 25.9 64.4
Irlan Jaya 0.7 2.2 5.8 5.1 14.8 35.0
These numbers are computer processed by using probabilistic methodology
(Grovel 11, 1981). The resulting curves show graphically the resource values
associated with a full range of probabilities and determine the mean as well
as other statistical parameters.
The cumulative probability curves for the undiscovered recoverable oil
and gas resources are shown In figures 81 through 88, and aggregated for total
Indonesia oil and gas In figures 89 and 90. The principal objective In making
these curves Is to find the mean quantity of undiscovered resources, a
quantity which embodies estimates of the most likely quantity along with more
remote probabilities for larger or smaller quantities, but particularly
substantially of undiscovered larger quantities (sleepers) of undiscovered oil
and gas.
The mean estimates of the four main groups of basins, as determined from
the probability curves are summarized below:
Oil Gas
(billions of barrels) (trillions of cubic ft)
Sumatra/Java 3.55 19.32
Kalimantan 2.21 24.63
Natuna 1.41 33.29
Irlan Jaya 2.86 18.11
Figures 89 and 90 show the aggregation of the probability curves and
accompanying statistical parameters for the undiscovered recoverable oil and
gas resources of Indonesia. The aggregation assumes 75 percent dependence
between the estimated probabilities, an assumption deemed proper to provide a
proper statistical tie affecting all the aggregated parameters except the mean
probablIIty.

207
 The mean estimates are the principal results of the study and, when
aggregated, show that the undiscovered recoverable petroleum resources of
Indonesia are 10 billion barrels of oil, and 95 trillion cubic ft of gas (not
Including 60 trillion cubic ft of discovered, but undeveloped, gas resources)

208
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O Ocncnouiuiaao
F o a m -J
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o
 INDONESIA - NATUNA
Recoverable Oil Assessment Date : Dec. 13, 1985
^ ~~^-s.
ESTIMATES
> Mean = 1.41
\ Median = 1.30
\ Mode = 1.10
\ F95 = 0.40
t-* \ F75 = 0.88
w \ F50 = 1.30
c£
IJL,
§
.

-
x F25
me.
r UO
S.D.
=
=
=
1.83
o or\
Z . OU
0.75

O c\i_
03
o, o
0-
\ V

V "---.

0 0.6 1 IJ5 2 2.6 3 3.5 4 4.5

BILLION BARRELS RECOVERABLE OIL

Figure 83. Cumulative Probability Curve, Natuna, recoverable oil

INDONESIA - IRIAN JAYA

Recoverable Oil Assessment Date : Dec. 13,1985
"\ Mean
ESTIMATES
= 2 . 86
Median = 2.63
Mode = 2 . 20

\ \
F95
F75
F50
F25
=
=
=
=
0.70
1.72
2.63
3.74
F05 = 5.80
S.D. = 1.59
o
\
O
P-, ""^^
2468 10
BILLION BARRELS RECOVERABLE OIL

Figure 84.--Cumulative Probability Curve, Irian Jaya, recoverable oil.

210
 INDONESIA - SUMATRA/JAVA
Recoverable Gas Assessment Date : Dec. 13, 1985

^ Mean
ES"
MMATE S
19.32

\ Med i ari =
Mode
18.60
17.20

\
CO
F95 8.20
F75 13.93

\ F50
F25
18.60
23.92

\ F05
S.D. =
32.90
7.59

O
a,
\ ^
^^

10 15 20 25 30 35 40 50
TRILUON CUBIC FEET RECOVERABLE GAS

Figure 85. Cumulative Probability Curve, Sumatra/Java, recoverable gas

INDONESIA - KALIMANTAN
Recoverable Gas Assessment Date : Dec 13, 1905

\\ Mean
Mode
F95
F75
F50
ESTIMATES
= 24.63
Median = 23.56
= 21.50
=
=
11.00
17.83
= 23 . 56

\\
F25 = 30.25
\ F05 = 4 1 . 90
S.D. = 9.54

V^^-_ "T'BBI

10 20 30 40 50 60 70
TRILLION CUBIC FEET RECOVERABLE GAS

Figure 86.-Cumulative Probability Curve, Kalimantan, recoverable gas

211
 INDONESIA - NATUNA
Recoverable Gas Assessment Date : Dec, 13, 1905
ESTIMATES
Mean ^ 33.29

L
Median = 30.69
iS °3
£u o
\ Mode
F95
=
=
25 . 90
11.00
F75 = 21.33
W F50 = 30.69

\\ \
C£ F25 = 42.37
Q «.
f** 0 F05 = 64.40
ft S.D. = 16.77

1:
v "^- .
O cvj_
03 o
cu -

n- _
20 40 6O 80 100 120
TRILLION CUBIC FEET RECOVERABLE GAS
Figure 87. Cumulative Probability Curve, Natuna, recoverable gas.

INDONESIA - IRIAN JAYA .

Recoverable Gas Assessment Date : Dec, 13,1985
ESTIMATES
Mean = 18. 11
Median = 16.97
Mode 14.80
F95 5.10
F75 11.50
F50 16.97
F25 23.47
F05 35.00
S.D. 9.27

10 20 30 40 50 60
TRILLION CUBIC FEET RECOVERABLE GAS
Figure 88., Cumulative Probability Curve, Irian Jaya, recoverable gas

212
 INDONESIA
Recoverable Oil Assessment Date : Dec. 13, 1985
ESTIMATES
Mean 10.04
Median 9.28
Mode 7.92
F95 4.83
F75 7.10
F50 9.28
F25 12.12
F05 17.83
S.D. 4.15

5 10 15 20 25 30
BILLION BARRELS RECOVERABLE OIL
Figure 89.--Cumulative Probability Curve, recoverable oil.

INDONESIA
Recoverable Tbtal Gas Assessment Date : Dec. 13,1985
^ Mean
ESTIMATES
= 95.35

\\ Median = 88.56
Mode
F95
F75
F50
F25
= 76.39
= 47.05
= 68.33
= 88.56
= 114.78
F05 = 166.69
S.D. = 38.06

\x-^_
50 100 150 200 25O 300
TRILLION CUBIC FEET RECOVERABLE GAS

Figure 90.--Cumulative Probability Curve, recoverable total gas.

213
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217