RC.04F.08-05/056947-EXPL I•

FOREWORD

The crucial problem faced by Indonesia petroleum upstream industry toward and after 2000' s is the emergence of existence crisis because of the shrink of oil and gas reserve in traditional area. During this period every oil company to be able to come out of the crisis has to increase its exploration activities. According to its objective there are two main solutions; intensification of exploration in the traditional areas or extensification activities in open areas through a new assessment. The extensification in the eastern part ofIndonesia basically has many handicaps; while the main problem for intensification is marginal reserve.

Nowadays intensification activities can be carried out by accommodating the ever expending explorationtechnology; while the extensification in the eastern part ofIndonesia requires new assessmentbecause the target of its activities is beyond the petroleum system widely known.

One of the significant result ofBPPKA - PSC Exploration Managers Meeting, Surabaya21-23 June 1995, is the judgment to produce a book on "Petroleum Geology ofIndonesian Basins", in which each of PSC is required participate. The book will be used as a guide and reference toward increasing exploration activities in Indonesian in the future. This volume of the Petroleum Geology ofIndonesian Basins which discusses widely aspects of petroleum system is a professional explorationist's guide to the methodology to find another attractive oil and gas accumulation.

Synthesizing the data in this volume was a long one difficult task shared by operators and PERTAMINA BPPKA. We are grateful for the Team for their hard work in conceiving this book. The high quality of this book is a product of their effort.

Finally, we hope it wi II find widespread use to support efficient exploration and development.

.r

S. Zuhdi PaneVice President

FOREWORD

Indonesia with a potential production more than1.6 million barrels of oil per day and producing around7.9 billion cubic feet of gas daily, presently ranks as the largest oi I and gas producing country in Southeast Asia.

Today there are some 60 known basins in Indonesia, of which only 14 have in production. Modern theories and available technology have anabled to gain a greater understanding of the region, particularly the geology of the main hydrocarbon - bearing basinal areas of Indonesia.

In the past three decades, the oil exploration activities in Indonesia have continued to decline. During this period, we achieved high performances between 1968and 1970, 1980 - 1984, and between 1990 - 1993. The maturity of exploration activities in the western part of Indonesia on the one hand, and the complex geographical location and geological system of the eastern part of Indonesia on the other hand has become a dilemma in our attempts to promote exploration activities to increase production realisticly and economicly.

In attempt to preclude the dilemma, it is necessary to activate scientific activity by evaluating the basins where the PSC work. Further advances in the basin evaluation enabled the Indonesia petroleum upstream activity to increase its drill ing success - ratio.

It is hope that the development of the application of science and technology will continue to improve the drilling success ratio in both exploration and development phases of oil industry. Finally, grateful appreciation is extended to Exploration Department BPPKA for their enthusiasm in organizing this publication. We thank the Team for their hard work in preparing this volume.

ead of Exploration and ProductionForeign Contractors Ventures Development Body

Preface

The science of petroleum geology continues to make technical advances and is becom ing more and more soph isticated. As exploration ist, we have an excellent opportunityto incorporate this vast amount of technology into the effort of locating new commercial accumulations of hydrocarbons. The idea of the treatise originated from a concept put forth by Mr. S. Zuhdi Pane. Driven by his continued encouragement and with input from advisory board consisting of geologists and geophysicists from existing Indonesian Production Sharing Contractors, Pertamina designed the set of publications to reflect cutting edge technology and its applipation in petroleum exploration. It is a great honor for us that Mr. S. Zuhdi Pane committed his time and experience as a professional geologist to this project in addition to his busy schedule as Vice President of Foreign Ventures Development Body.

This treatise illustrates and discusses the wide ranging application of geological studies and hydrocarbon play types in the Tarakan sedimentary basin. A new structure pattern is presented in this volume, which can give some ideas about this basin. Modified stratigraphic column due to additional new well data are combined with other geological successions chart such as sea level curves and tectonic intensity chart. Paleogeographic maps presented in this volume also give backgrounds about tertiary sedimentary prospects. This volume serves as a guide to the petroleum geology of the Tarakan sedimentary basins, incorporati ng data from existing field In addition, it provides exploration ists in different fields of geology, with an example of a structured approach for evaluating basins allowing them to compare and contrast their approach to studying and evaluating the geology and petroleum systems in their area of interest. For the explorationist, who is building and selling prospects, nothing is more convincing than a close analogy.

r would like to point out the subject of petroleum geology, in the Tarakan Basin' Basin, is considerably more complex than this volume indicates. We understand that some statements and perceptions herein will have to be modified as additional geological information becomes available in the future.

I would Iike express my sincere appreciation to Mr. Herman Darman and Mr. Michael R. Lentini of Shell Companies in Indonesia, Mr. Achmad Fauzi ofPT. Etaksatria Petrasanga and Mr. Nandang Heriyanto of Pertamina, who formulated the structure of this volume and provided significant support throughout this project. They deserve most of the credit for bringing this project to completion and I am grateful for their contributions.

T

Cholidy H. RemintonExploration ManagerForeign Contractors Ventures Development Body

VII

The Committee

Originator

Advisor

Chairman

Technical Committee

Secretary

Treasurer

Support

Editors

S. Zuhdi Pane, Pertamina

Sungarna Sukandar, Pertamina

Cholidy H. Reminton, Pertamina

Karsani Aulia, PT. Caltex Pacific IndonesiaRamli Djaafar, Pertamina Husein Hatuwe, Pertarnina Emir Lubis, PertaminaS. Sosromihardjo, Mobil Oil IndonesiaFirman A. Yaman, Atlantic Richfield IndonesiaEtty Nuay, Vico Indonesia

Amrullah Yazid, Pertamina

A. N awawi, Pertamina

Anwar Suseno, Pertamina

A. Nawawi, PertaminaAnwar Suseno, PertaminaNandang Heriyanto, Pertamina

Working Group on The Tarakan Basin:

J Herman Darman, Shell Companies in Indonesia Michael R Lentini, Shell Companies in Indonesia Achmad Fauzi, PT. Etaksatria Petrasanga

Nandang Heriyanto, Pertamina

Chapter 4 : Oil Play Concept 30Chapter 5 : Conclusions 34

Tarakan Basin

TABLE OF CONTENTS

PageForeword m-v

Preface VB

Chapter 1 Introduction

LocationExploration and Production HistoryReserves, Cumulative production anddistribution of oil and gas field 3

Chapter 2 Regional Geology 6

Tectonic 6- Regional Tectonic Setting 6- Regional Tectonic History 8- Structural Styles 8

Stratigraphy 10- Pre-Tertiary 14- Eocene 14- Early Oligocene 14"- Late Oligocene - Miocene 16- Middle to late Miocene 18- Late Miocene - Pliocene 18- Quartenary 20

Chapter 3 Petroleum System 23

Reservoirs 23Trapping 25Seals r 26Source Rocks 27Petroleum Generation and Migration 27

References 35

1

Chapter 1Introduction

Location

The Tarakan Basin is located in the north-east Kalimantan, lying both onshore and offshore (Figure 1 & la). The northern basin boundary is the Semporna high which lies just north of the Indonesia and Malaysia border. To the south, the Mangkalihat Ridge separates the Tarakan Basin from the Kutai Basin; and to the west it extends onshore for 60 to 100 kilometres where progressively older Tertiary formations crop out towards the strongly folded Pre- Tertiary rocks of the Kuching High. Eastward the basin extends to unknown limits out across the continental shelf of the Sulawesi Sea into the deep Makassar Trough. This basin occupies an area of approximately 40,000 krrr'.

Exploration and ProductionHistory

Exploration for petroleum began in the Tarakan Basin, when oil was first found on Tarakan Island in 1899. Thereafter exploration has continued to the present.

In 1967 Pertamina awarded the first PSCcontract in offshore Tarakan to Japex (Figure2). Twelve exploration wells were.drilled; four by Japex (Bunyu-A 1, A2, B I and C I), five by farm-in partner Total (Kanah-I, Ahus-l, Serb an 1 and 2 and Menulun-I) and three wells by Amoseas as a farm-in partner (Mayne-I, Giru-l and Segitiga-I; Figure 7).Pertamina and Redco signed a TAC in 1971,

covering the Tarakan Island. Tesoro farmed into Redco's interests in 1971. Thereafter, between 1973 and 1976 the Mengatal, South Pamusian and Selatan fields were discovered. Tesoro's interest was relinquished in 1982 by which time they applied for a PSC covering the Tarakan island. The last field to be discovered on the island was Mamburungan (1986) after farm-ins by Shell and others.

The Tapa gas field on Bunyu Island (Figure 7) was discovered by Pertamina in 1975. This led to the construction of a methanol plant to utilize the gas discovered on Bunyu Island. Bunyu Nibung and Barat Field were discovered in1974 and 1979 respectively and are essentiallysatellite fields of Bunyu Field.

Arco acquired the onshore Sembakung PSC in ) 974 (Figure 2) and drilled some 20 wells and had three sign i ficant discoveries: Sembakung and Bangkudulis oil fields and gas at Sesayap. A portion of the Sembakung PSC is presently held by Pertamina- Teikoku who have drilled four wells in the area.

In 1985 the old Japex area was awarded as a new offshore PSC (Bunyu PSC) to a consortium ... with Sceptre as operator (Esso 45%, Hadson28.75% and Santa Fe 6.25%) coveringbasically the area of the Tarakan basin, excluding the Bunyu and Tarakan island PSC's.

After several partnership changes and the drilling of 5 wells of which 4 wells contained subcommercial quantities of hydrocarbons, the PSC was relinquished in 1993. So far, there is only one well has been drilled in down deep position, the Sceptre Vanda-l, drilled in348 meters of water depth in the central partof the offshore.

Petrocorp's Maratua and Karang Besar PSCwere awarded in 1990 covering the on and

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FIGURE 1 - Tectonic Framework of the Tarakan Basin and Its Sub-Basin Distribution(Modified after BEICIP, 1985)

3

offshore Berau and Muara Sub-basin south of Sceptre's Bunyu PSC. The offshore part ofthis area is remote from clastic input from the Tarakan deltas and is essentially a carbonate province. These two blocks were awarded to Maersk in 1995. On the other hand, Shell's Sebawang PSC was awarded in 1995 covering Tarakan Sub-basin.

Reserves, cumulative production and distribution of oil and gas field

Exploration in the Tarakan Basin has resulted in the discovery of 1.4 oil and gas fields. Cumulative production from these fields is approximately 320 MMBO in a basin

of 7,000 km-, with EUR from the proven fields estimated at 500 MMBO. Total gas produced to date from 13 wells are 81 BCFG. Nearly86% of the oil production to date has come from two fields: the Pamusian Field on Tarakan Island (195+ MMBO produced); and, Bunyu Field on Bunyu Island (84 MMBO produced; Figure 3 and 4). Most of the remaining production comes from a series of very small fields located in individual fault blocks on Tarakan and Bunyu Islands. Oomkens (1979) reports that most of the structures on the Islands are only partially filled. Most likely cause for the undefilling of structures are inadequate top and cross fault seals. All the production and most of the drilling to date have been limited to an area defined by the fold axes ofthe Bunyu, Tarakan, and Ahus arches (Figure 5).

FIGURE la - Tarakan Basin Index Map

4

1961-74 1974-81

1988 1982-96

oo H

• PertaminaiTeikoku

Bangkudulis Fld, JOB 1968-94 • • EXSPANTaraltan PSC & lAC1982·94

FIGURE 2 - Exploration History of the Tarakan Basin, 1961 - 1996.

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P3l)111sian - Million Barrels

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DISCOVERY YEAR for field >, MMBbls

FIGURE 3 - Tarakan Basin Production. Cummulative production to 1991 was320 MMBO (million barresl of oil), with three of the largest fields discovered bed ween 190 I and 1924, No major reserves have been added since the 1970's (modified from Wight et al., 1993)

Bunyu

Sembakung23,2 MMBO

Juata16.8 MMBO Total Others

4.8 MMBOI5% 1%

82,6 MMBO

26%

Pamusian192,8 MMBO

FIGURE 4 - Cummulative Oil Production by Field. Pamusian with 192 MMBO cumrnulative production, is the largest field in the basin, Bunyu

produced 82.6 MMBO or 26%, followed by Sembakung with 23,2MMBO (modified fromWight et al., 1993)

7

Reservoirs in the Muara Sub-basin aredominantly carbonates.

-

Chapter 2Regional Geology

Tectonic

Regional Tectonic Setting

The Tarakan Basin is generally a passive deltaic margin with a minor wrench tectonic overprint. Oligocene and Miocene sediments onlapping the older Eocene eventually thinning onto an Eocene Rift sequence. Magnetic anomalies imply sea-floor spreading with associated NW trending transform faults. The Tarakan basin is divided into four sub-basins (Figure I & 5):

I. Muara Sub-basin, the southernmost depocentre developed exclusively offshore.

<,

2. Berau Sub-basin mostly onshore and located southward.

3. Tarakan Sub-basin, mostly offshore but including Bunyu and Tarakan Islands.

4. Tidung Sub-basin, the most northerly and mainly onshore.

The NW-SE trending Muara Sub-basin is bounded to the SW by a coast parallel wrench fault zone along the north shore of the Mangkalihat Peninsula. Towards the NE the Muara Sub-basin is bounded by another wrench fault zone and associated with basement high upon which the Maratua reefal islands have developed (Figure 5). Seismic data suggests

5000 metres of rift and passive margin sediments in the Muara Sub-basin, predominantly Oligocene to Recent carbonates resting on older volcanics. Little structuration is present in the post rift portion of the section.

Source rocks within the Eocene rift section are likely, however, are poorly documented.

The Berau Sub-basin is bounded to the north and south by Pre-Tertiary outcrops. The Suikerbrood Ridge forms the southern margin, contains igneous rocks. Eastwards the basin extends into the Tarakan Sub-basin (Figure 5). The division between the Tarakan and Berau Sub-basins is based upon the pinch-out of the Tarakan Formation. Several NNW-SSE trending compressional features are present within the Berau Sub-basin. This structurationis related to left lateral movement along wrenchzones accommodating the o~oing spreading of the Makassar Strait. '

The thick clastic fill in the Tarakan Sub-basin is an amalgamation of numerous Plio- Pleistocene clastic depocentres located below Bunyu and Tarakan Islands and prograding further offshore. The Pliocene thins regionally to the west and south, onlapping Miocene highs and eventually pinching out. The Tidung Sub- basin is separated from the Tarakan Sub-basin by the Sebuku Platform, as defined by the northern pinchout of the Tarakan Formation. Tidung Sub-basin contains a prominent positive feature and several NW trending tightly folded anticlines. Thrusting also occurs along the coastal strip.

In the north it is bounded by the Semporna fault zone exhibiting sinistral transform movement.

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l.-.-....J WITH SOME IGNEOUS ROCKS(TESTED PLAY)

PALAEOGENE D IGNEOUS ROCK

(UNTESTED PLAY) .:»: BASIN BOUNDARY1"'...-'" GROWTH FAULT TREND

FIGURE 5 - Simplified Geologic Map of the Tarakan Basin (modified after Pertamina- Beicip, 1992; Netherwood & Wight, 1993; Hidayat et al., 1992; Situmorang

8

Regional Tectonic History

The Tarakan Basin was initiated simultaneously with the formation of the Sulawesi Sea by rifting of north and west Sulawesi from East Kalimantan (Hamilton,1979). Extension and subsidence began during the Middle to Late Eocene and had stopped by the end of the Early Miocene (Burollet and Salle, 1981; Situmorang, 1982, 1983; Figure10). This extensional tectonic phase opened the Tarakan Basin eastward, indicated by the existence of en-echelon block faulting which has a slope downward to the east. The opening of the Sulawesi Sea has been interpreted as being related to the same tectonic episode responsible for the opening of the South ChinaSea (Rangin, 1991).

nKa1oof

The Tarakan Basin was more tectonically stable from the Middle Miocene up to Pliocene with deltaic sedimentation from the west through several drainage systems. During this phase the combination of basin subsidence and gravity induced listric faulting created accommodation space for an increased volume of deltaic sediments.

The latest tectonic phase is a reactivation of transform movement along the wrench faults crossing the Makassar Strait beginning in the uppermost Pliocene and continuing to present day. Transpression during this period resulted in the formation of major dip oriented arches. Vitrin ite reflectance, porosity and seisrn ic data suggest 1000-1500 m of structural inversion has occurred during arch formation.

rThe Sulawesi Sea is underlain by an old PacificOceanic Crust (Figure 6), trapped by the westward bending of the Sulawesi Island due to the spearheading westward thrust along the Sorong Transform Fault system (Katili, 1977). On the western margin of Sulawesi Sea,.

Structural Sty les

Depocentres

The Tarakan Sub-basin boundaries with the neighbouring Tidung, Berau and Muara Sub- basins (Achrnad and Samuel, 1984) cau'be more rigorously defined in terms of stratigraphy and structure. The sub-basin is composed mainly of a collection of contiguous Plio-Pleistocene depocentres underlain by Miocene depocentres which have not been upl ifted to outcrop, as the onshore sub-basins case(Wight et. a l., 1993). The Miocene depocentre is located in the vicinity of Nun uk an and Sebatik Islands and onshore Simenggaristo the Northwest of the Tarakan Sub-basin boundary, with the distil portion continuing below the Tarakan Sub-basin (Figure 5). Portions of the Pliocene depocentres .are inverted, as for example below Tarakan( and Bunyu Islands, while the Pleistocene depocentres, the Kantil and Mandul troughs,

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continued to subside. The easternmost depocentre, east of the Mayne fault, contains active growth faulting and expansion of both Pliocene and Pleistocene ages (Wight et. al.,1993).

Faults

Three sinistral wrench faults are found in the Tarakan Basin (Figure 5). Semporna fault is the most northern wrench fault. It separates the volcanics of the Semporna Peninsula from the Neogene sediments on Sebatik Island. Further onshore it becomes a boundary between Cretaceous sediments in the north and Neogene sediments in the south. Field evidence, however, is very limited due to remote access.

Maratua Fault occurs as a complex transpressional zone. It forms the boundary between the Tarakan and Muara Sub-basins. The third major wrench fault forms the southern boundary of Muara Sub-basin, along the north shore of the Mangkalihat Peninsula. It appears as the extension of the Palu-Koro fault in Sulawesi.

Growth faults are the most common structure in the Tarakan Sub-basin (Figure 8) . They are north-northwest and north east oriented with a trend change shown by the prominent swing in coastline orientation at the Sesayap River mouth, from north-northwest in the south of Tarakan Island to northeast in the north of Bunyu Island (Wight et. aI., 1993). The set of north oriented faults are most continues, longest and have the largest displacements in the east, at the Mayne fault system, which extends more than ISO km. from the Bulungan delta to north of the Mayne-I well (Figure 8). This represents the extensional edge of the Holocene basin. A regional seismic dip linedown the Kantil Trough shows the typical

expression of the extensional zone and north-south Mayne fault system in relation to the folded area to the west, where the fold axes are generally north-northwest to northwest oriented.

Anticlines

Five arches dominate the western area structure, informally named from north to south, the Sebatik, Ahus, Bunyu, Tarakan and Latih arches (Figure 5 & 7). They are broad SE plunging flexures formed by NE-SW transpression and are oriented roughly NNW- SSE, surveying to the NW further northwards. The age of compression appears younging northwards and is coeval with, but coupled from, the major extensional system to the east of the Mayne fault. The intensity of folding also increases northwards where the broad arches give way to tight folds in the onshore Simenggaris area (Figure 5 & 7). The existing oil and gas fields are found as combination of structure and stratigraphic traps at the axis of the Tarakan and Bunyu arches.

Latih and minor anticlines develop in the southern part of the Tarakan Basin. They are NW-SE oriented. The minor anticlines are inverted structures, cored by Eocene to Late Miocene bathyal shales and tight turbidite limestones (Wight et. al., 1993). All three anticlines have been drilled resulted with oil shows in Sajau-l well and gas flows from thin turbidite sandstones in Birang-l well.

Stratigraphy

The stratigraphic sequence of interest in the Northeast Kalimantan basinal areas were deposited above Pre-Tertiary basement (Figure 10).

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FIGURE 8 - Composite Line A. A specially processed, composite seismic Line along the axis of the Ahus arch show: a. a western trough with an a angular unconformity Pliocene and the Pleistoence, b. the shallow, uplifte Miocene shelf edge (carbonates), c. easterly thickening Pliocene, d. Pliocene growth - faulting east of OB-A2, e. a footwall anticline on the Mayne fault (Mayne-I), f Thick Pleistocene growth east of the Mayne fault (from Wight et ai, 1993).

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Each cycle beginning with the oldest (Palaeocene to Late Eocene) sedimentary rocks exposed in the Berau Sub-basin, was terminated by volcanism, uplift and unconformity.

The overall post-rift stratigraphic sequence consists of generally shallowing-upwards environment, starting with Eocene clastics to Oligocene carbonates and becoming progressively more clastic again during Miocene to Pleistocene. Minor marine incursions punctuated the section in the present day nearshore and onshore.

Pre- Tertiary

The Pre-Tertiary basement, Danau Formation, consists of intensely metamorphosed flysch sediments and is possibly Pre-Cretaceous in age (Figure 10). This unit composed of micaceous sandstones alternating with dark grey slates and silty marls with numerous red and green chert beds near the top (Nordeck, 1974). Information about this formation is scarce because of its inaccessibility and lacking commercial mineral or hydrocarbon potential. The closest and best described sections of th is formation are found along the upper Kayan River.

The Pre-Tertiary Bengara Formation is found in Tidung Sub-basin. This formation consists of Upper Cretaceous shale, sandstone, and tuffaceous materials. This unit is highly metamorphosed, having slickensides and abundant of quartz veining.

!

Eocene

The Pre-Tertiary basement is unconformably

sediment (Figure 10). The Sembakung Formation is the oldest post basement sedimentary unit encountered and is Eocene in age. It unconformably overlies basement and consists of clastic and volcanic material deposited in a rift setting. In the Tidung Sub- basin, Hidayat et. al., (1992) observed foraminiferal limestone facies with sandstone and shale intercalation, indicate of a marine environment (Figure I I a). The Seilor Limestone was primarily deposited in the Muara Sub-basin, having been penetrated by Karang Besar-I and Tabalar-I wells (Figure II a). The Pulau Fanny-I well is the northern most penetration of the Seilor Formation. Micropalaeontology analysis of several outcrop samples in the north (Sekatak River) show marine environment of deposition (Brown et. al., 1991). Clastic sediments were transported from Sekatak and Suikerbrood High to the northeast down to the basin during Late, Eocene. The upper part of the Eocene interval is less tectonised than the lower part.

Early Oligocene

Basal coarse sandstones with poor reservoi"r properties of Sujau Formation give way vertically to marine shales and finally to a regional micritic and dolom itic carbonates of the Seilor Formation. These carbonates pass vertically and laterally into basinal shales and marls of Mangkabua Formation. Late Oligocene unconformity eroded some of upper part of Lower 01 igocene sequence. The Oligocene interval as well as Late Eocene is commonly tectonised, though not as severelyas the Early Eocene package (BEICIP, 1985).

The carbonate shelf sediments of Seilor Formation are distributed in southern and

western part of Tarakan Basin (Figure II b).

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The Seilor limestone consist primarily of micritic limestone and grades upward and basinward into thick massive marls of the Mangkabua Formation (Achmad & Samuel,1984). The Mangkabua basinal deposits occur locally in the east, and are penetrated by Bunyut-I well (Figure II b), where it is comprised of intercalations of shale, siltstone and minor marl with calcareous siltstone, packstone and boundstone. Further south the Mangkabua is time equivalent to the Sembulu Formation along the northern margin of Kutai Basin, named Sembulu Formation (FigureII b). Lepidocyclina limestone lenses occur as part of Seilor Formation. It is a fossiliferous limestone, wackestone to packstone containing algae, foraminifera, and massive hard coral. Crystalline reef limestone with low porosity occur in places (Rustam, 1977). Although terrigenous clastic deposits are not common, some lava and pyroclastic deposits are found in the west, supplied from the Sekatak - Berau Ridges.

Late Oligocene-Miocene

In the west volcaniclastic deposits of lelai Formation were accumulated during Late Oligocene (Figure 12a). Further transport of volcanic materials basinward produced basal volcanic sandstones and coals of the Tempilan Formation, deposited over the Late Oligocene unconformity. It grades laterally southward into the Tabalar Formation; a platform carbonate sequence that forms a good regional seismicmarker.

r

Volcanic breccia of .Jelai Formation was observed in the western portion ofTidung Sub- basin, ranging from Late Oligocene to Lower Miocene in age (Hidayat et. aI., 1992). Tuff and lava interbeds occur within this formation. The breccia unit consists of basaltic igneous

rock fragments with siltstone and tuffaceous'sandstone matrix. The source of these materials are the vulcanoes of the Dent Volcanic Arc (Tongkul, 1991; Hidayat et. al., 1992).

The Tempilan Formation is comprised of alternating thin bedded sandstones, tuffs, shales and coal seams (Achmad & Samuel,1984). The thickness in outcrops was reportedup to 1000 m. The thickness penetrated by drilling is much less ranging from 45 m in the P. Fanny-I well to 270 m in the Barat-I well (Pertamina - Beicip, 1983).

The Tabalar Formation represents a platform carbonate sequence with local reef development, and is deposited unconformably over the Seilor Formation (Figure 12a, 15;Achmad & Samuel, 1984). Several build-upsin this unit have been drilled without success. The Tabalar Formation is dominantly a micritic limestone of Late Oligocene - Early Miocene age. This formation is widespread over most of the onshore and nearshore areas mostly in the southern part of the Tarakan Basin. The thickness of the Tabalar Fm. is 500 m near the Su ikerbrood ridge and 800 m at Segitiga; I well. The Tabalar Formation gradually thinsto less than ISO in the northern margin of theTarakan Sub-basin (Pertamina - Beicip, 1983). Farther to the north, the Tabalar limestone grades laterally into alternating marls, limestones and shales of the Mesaloi Formation. This formation is rich in planktonic foraminifera which indicates an open marine environment and in deeper water grades

laterally into shales of the Birang (Figure IS)and Naintupo Formations.

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being found in the Muara Sub-basin and in the northern portion ofTarakan Sub-basin. The contact between the Tabalar and the Birang Formations is gradational turning into shales, and marls with thin limestone beds. As an open marine facies, this formation is r ich in planktonic foraminifera. The thickness of the Birang / Naintupo varies from 200-400 m but in the Tarakan Sub-basin it increases to 600-800 m and was deposited over the entire region(Figure 12b).

Middle to Late Miocene

Middle to Late Miocene facies varies from proximal deltaic in the Sembakung-I well, prograding eastward to Nunukan Island, to shallow to deep marine delta front facies encountered in the Kanah-I & Teratai-I. Shallow marine and continental facies, however, are present far to the east (Vanda-I well; Wight et. ai., 1993). A carbonate platform emerged in the south where a local high developed as a result of inversion along transform faults. Supratidal deposits are found in the west and north of the basin. These sediments were transported from imbricated ophiolite complex in the northwest and volcanic arc in the north (Figure 13).

The delta front facies, of the Meliat Formation (also equivalent to the Latih Formation in the south; Figure 13a), consists of fine to coarse grained sandstone with quartz fragments, silty in part, interbedded with shale and conglomeratic sandstone locally (Rustam,1977). This formation was deposited in early Middle Miocene. The Japex's OB-A2 well penetrated prodelta-shelf facies, indicated by marine shale and limestone units. On Bunyu and Tarakan Island the facies change to delta front and prodelta. Micropalaeontologic analysis shows fresh to brackish water

environment (Tower, 1975). In the south of the Tarakan Basin the clastic sequences were all succeeded by shallow marine limestone during Late Miocene. The carbonates were deposited in delta front or platform environments, reflecting deposition outside of the main (northern) depocentre (Figure 13b).

Tabul Formation sediments of upper Middle Miocene to Late Miocene age consist of an eastward prograding delta complex. This formation is dominantly shale prone containing sandstone and silt interbeds and is restricted to the Tarakan and part of the Tidung Sub-basin. In the Mandul Island area, it exceeds 1500 m in thickness and tends to increase in thickness toward the east. The laterally equivalent calcareous mudstones, marls, and limestones ofMenumbar Formation were deposited in the Muara Sub-basin. This marine sedimentary section was deposited unconformably above the Birang Formation, however, is sand poor as a result of deposition south of the main deltaic area. Upwards, the Menumbar gradually develops into micritic limestones. In the northeastern part of the Tarakan Sub-basin, the lower Menumbar extends as thick limestone beds and is 'an equivalent unit to the Tabul Formation in the western Tarakan and Tidung Sub-basins.

Late Miocene - Pliocene

The deposition of the delta-front facies during the Middle to Late Miocene shifted southward during Late Miocene to Early Pliocene. In the area around Bunyu Island it is interpreted to have prograded locally from the southwest (Akuabatin et ai, 1984). A thick Late Miocene to Early Pliocene sequence is encountered at Pamusian and Mamburungan Fields located on Tarakan Island.

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The Tarakan or Sajau Formation is composed of sandstone, shale and coal interbeds that belong to this Upper Miocene to Pliocene deltaic system. Cross bedded sandstone and pebbles sands, lenticular clay and coal beds in the north (Bunyu Island) are interpreted as channel deposits. Fine grained sands and laterally continuous clay and coal beds in the south are interpreted as upper flood plain deposits of highly meandering rivers on Tarakan Island (Newton & Hewett, 1983).

At the same time a carbonate platform developed well in places where ecosystem is not charged by clastic influx of the deltas. These carbonates are represented by the Domaring Formation in the south and Tarakan Carbonates penetrated by the Mayne-l well in the north (Figure 14a, 15). The carbonate platform sequences grade eastward into outer neritic marls and shales. The Domaring was unconformably deposited in the onshore over the underlying formation, especially on the western margin of the basin, while offshore the contact seems to be conformable.

The Tarakan and Sajau Formations of Pliocene age are composed of marine to supralittoral clastics and coals. These formations have a lower overall sandstone percentage than the Pleistocene and becomes carbonate-dominatedin the distal prodelta offshore, east of the

Tarakan Sub-basin (Figure 14a). Seismic data suggests that during sea level drops numerous incised valleys were cut into the exposed palaeo-shelf and forcing thick lowstand deltaic deposits to bypass the shelf and be deposited near the shelf edge. Evidence for such a model exist in the thick sandstone deposits encountered in the shallow Pleisto.cene of Vanda-I and the Holocene deltas that have a pronounced present day bathymetric expression far down dip of the present coastline. Additional lowstands may have occurred during the Pliocene and Miocene, particularlyat the Middle to Late Miocene boundary(10-11 Ma).

Quartenary

Sediments of this cycle were deposited after the general marine onlap caused by a global rise of sea level. This transgression has shifted back the Pliocene deltas westward to near the present coastline. The Bunyu Formation was deposited in an upper deltaic plain to fluvial environment. It consists of clastic units containing numerous intercalations of lignite, lying unconformably upon Tarakan Formation. Waru Formation carbonates were deposited seaward (Figure 14b), in areas free from deltaic influence (Achmad & Samuel, 19'84).

21

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23

Chapter 3Petroleum System

Reservoirs

The Muara Sub-basin lying offshore of the Berau Delta has a sedimentary fill comprising predominantly Oligocene-Recent carbonates overlying volcanic basement and Eocene rift sediments. In the Muara and Berau Sub-Basins data on reservoir quality from the few wells drilled is scarce. Poor reservoir properties are lacking in Domaring Carbonates. Segitiga-I and Tabalar-I wells which penetrated this formation and encountered reefs trending parallel to the Mangkalihat Peninsula.

Tabalar Formation carbonate platform reservoirs are located in the southern part of the basin. These carbonate platforms contain localized reefal facies exhibiting 12% porosities in Tabalar-I well and 22% in Karang Besar-I well. The thickness of the Tabalar Formation ranges up to 1200 m thick at Segitiga-I and a test over an interval of 30 m recovered 540 bpd of salt water. Pinnacle reefs may exist with good reservoir characteristics, however, are difficult to identify using seismic (Pertamina-BEICIP, 1992). Additional reservoirs may be found along the flanks of the Maratua basement high in the form of carbonate talus and turbidite deposits containing carbonate bank material shed during sea level drops.

In the Berau Sub-basin the Tabalar Formation is tight and of limited thickness in the onshore wells. Slight shows are reported in the Bunyut-I well. A thick Eocene-Oligocene section of clastics was encountered in Latih-I well.

Eighty metres of sandstone intervals were recorded in NW Berau-I and Bunyut-I wells. These intervals have good flow rates of water with traces of gas. The sands are mixed with volcanics-to the west (Pertamina-BEICIP,1992).

Some Latih Formation sandstones beds with favourable reservoir properties were observed in the Bunyut-I and Sajau-I wells. This formation is partly or totally eroded further onshore. The Latih deltaic sequence is assumed to have a sufficient percentage of sandstones further east and south in the offshore to constitute an attractive reservoir characteristic (Pertamina-BEICIP, 1992).

The onshore sub-basins fill consisting of mainly Eocene to Miocene sediments deposited during a period of generally rising sea level. Thick homogeneous shales and claystones grade upward into marls and carbonates. They crop-out in broad, N-S oriented folds in the Berau Sub-basin and a series of tightly folded, NW-SE oriented anticlines which bring Miocene clastics to the surface in the northern Tidung Sub-basin.

In the Tidung Sub-basin the primary objectives are clastics of the Tabul Formation of Late Miocene age. Sembakung Field is the only field where production has been established in the Miocene. Here the entire field is drained by six wells out of the Tabul Formation having well initials of2000-2500 barrels of oil per day and rates remaining stable for much of the field life.

Prodelta sandstones of the Tabul formation deposited during sea level low stands have considerable reservoir potential ar d are secondary objectives in the offshore Tarakan Basin. In much of the offshore the Tabul sandstones are present beneath a thick cover

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25

of Plio-Pleistocene age sediments and are probably to deeply buried to be a viable objective in the offshore. Miocene age sandstone was encountered near total depth in well Vanda-l suggesting Miocene reservoir potential far downdip in the basin. Porosity- depth trend curves of Miocene sandstone indicate them to have slightly higher porosities than those for the Pliocene at equivalent depths (Fig. 16a & 16b). The cause of this distinction remains speculative, however, there are many references to the presence of volcanic clasts in the Plio-Pleistocene sandstones and it may be that the Miocene sandstones were derived from

\ a different provenance.

In the northern portion of the Tarakan Basin, clastic sediment supply was limited giving rise to a carbonate shelf with isolated build-ups. These wells have been tested by several wells and found to be tight.

During the Plio-Pleistocene large volumes of interbedded fluvio-deltaic sandstones, shales and coals were deposited into the major depocentres on and between the arches. Isopach maps show that Pliocene deposition was more active south of the Bunyu Arch and in the vicinity of Tarakan Island, whilst the focus of Pleistocene deposition was to the north in the Ahus Arch area. The Pleistocene reaches its maximum thickness (>3000 m) north and south of the Bunyu Arch, whilst the Pleistocene exceeds 2000 m in the Ahus Arch area. North of the Ahus Arch the Plio-Pleistocene is characterized by a larger proportion of carbonates. Ocean circulation appears to have swept clastic input southwards into the TarakanSub-basin allowing clear water conditions in

sandstone percentage than the Pliocene. Thick sandstones of Pleistocene age were encountered in Yanda-I well indicating the potential for sandstone deposited during forced regressions occuring in those parts of the basin characterized today by deep water. It may be expected that similar forced regressions during Pliocene (and Miocene) time also brought shelf by-pass coarse clastics into the distal parts of the basin.

As in all deltaic depositional systems, reservoir continuity can be expected to be very poor in the portions of the section deposited in a delta plain environment where shales and coal beds are cut by channels filled with either sandstone or shale (depending upon the style of abandonment). Reservoir continuity should be much higher in the distributary channel.jriver mouth-bar, and inner fringe environments of the deltaic system (most likely where the percentage sandstone decreases to between10% to 40%). Maximum thickness of any individual sandstone reservoirs should be on the order of 2S-30m. During lowstands the distributary channel system should have migrated to the shelf margin thus enabling , sandstones to reach the deeper water areas.

Traps

In the south ofTarakan Basin, several potential stratigraphic and structural traps occur. The stratigraphic traps are include the reefal buildup ofDomaring Formation. The pinnacle reefs aligned along structural ridges or shelf

the north where carbonates.. could develop. edges. Other reefal facies, Tabalar and SeilorCarbonates are located on basement highs or

The Pleistocene Bunyu Formation comprises marine to supralittoral sandstones in coal measure sequences. It has a lower overall

on discrete ridges. They are enhanced and sealed by age equivalent Birang formation shale.

In the Tarakan Island, Pliocene supralittoral point bar, braided stream, channel sandstones and coals found in outcrops indicate delta plain environment. Thick Pliocene deltaic sandstones have also been encountered in wells Ahus-I , OB-A I, OB-A2, Kanah-I, Teratai-I and on Bunyu Island. These Tarakan Formation sandstones are notably volcaniclastic in origin indicating a northern provenance from igneous centres located In

Sabah (Semporna High).

Wedge out stratigraphic trapping geometries are found Withi~5It~iC sands. This trap style occurs 6n-stmcture flanks or along the unconformities. Onlap and pinchout traps possibly occur within Eocene Sujau Formation, however, poor seismic data at that depth obscure adequate trap definition.

Anticline structures in the north and west of Segitiga-l well (Berau River Delta) are mostly wrench. The structural features, the western compressional and eastern tensional tectonic regimes and the effects of tectonism on sediment dispersal are intimately related to hydrocarbon trapping mechanisms of the northern Tarakan Basin. The basin is a complex combination of major arches comprising Pliocene and Pleistocene inverted depocentres which were filled with regressive, sandprone sediment which host all the major hydrocarbon accumulations except the late Miocene deltaic of the onshore Sembakung field (Wight et ai, 1993).

Roll-over associated anticlines occur within the Bunyu and Tarakan Formation. The fault plains are dipping to the easl, down to the basin. Fault block trap formed at the upthrown side of the fault. Shale diapirisms in the east also produced traps together with the roll over anticlines. Complex structures 'generated traps

by structuFaLi~on. They often combined with (trike-s-I+p""\'nduced deformations. Carbonate- tr~PsCo'"c"cur as mixed trap at the upthrown slide of the fault or within the reefal facies on the shelfedge.

Seals

In the southern sub-basin, the thick marine mudstones of Oligo-Miocene Birang Formation are effective seals for the Tabalar Carbonate. The Menumbar Formation forms a potential seal for Miocene reefs located towards the basin margins. The Domaring carbonate is sealed by the Pleistocene Waru Formation. Possible lateral seals in this area are sealing faults, facies changes, or diagenetical differences within limestone. For the clastic sections of northern Tarakan Basin, marine, prodelta, and delta plain mudstone facies can form seals. The lack of thick and laterally continuous' shale seals in the more proximal portions of the basin is considered the main reason for the lack of recent exploration success to date. With a high net.to gross sandstone and thin seals fault trapping is difficult. In a more distal part of the basin (i.e., further offshore) the net to gross will decrease and thicker laterally. In this location continuous seals will be deposited during transgressions. Therefore seal is not considered to be a critical risk further offshore in the Tarakan Basin. Many of the direct hydrocarbon indicators observed on seismic also suggest that the shales provide effective lateral seals where they are juxtaposed against sandstones across faults. Furthermore, the young age of the shales and the presence of over pressuring are strong indications that smearing along faults can also provide effective sealing.

27

Source Rocks

Identified source rocks in the northern Tarakan sub-basin include coals and siltstones of the Middle Miocene Meliat and Late Miocene Lower Tabul Formations. Geochemical data suggests that source rocks which generated the Tarakan oi Is are interpreted as lacustrine, coastal plain and deltaic deposits. The coals are mainly drift coals containing inertinite and as much as 45% cuticular matters with vitrinite usually subordinate and have hydrocarbon

generating potential. Coals from the coastal plain and deltaic environments are the richest source rocks with around 10 to 70% TOe. Inertinite is also found in siltstones, associated with the coals. The oil consists of low gravity (20-400 API) asphaltic crude (Beicip, 1985).

Pyrolysis GC data and geochemical plots suggest a multitude as various source rocks. They indicate that the source rocks are ranging from types 111111or IV (Juata-IV, Pamusian, Mengatal and Bunyu-IIIIII) to type 1111 (Sembakung, Bunyu Tapa, Bangkudulis and Vanda- I oil and condensate; Figure 17). The source rocks appear to be more complex and from more varied depositional environments than earlier believed. Based upon presence of hydrocarbon charge source rocks are also apparently widespread, occuring from Bangkudulis in the west to Vanda- I, 110 kmto the east and between Sembakung in the north105 km to the south, at Muara Makapan-l (condensate) and oil seeps 30 km still further south, onshore in the Berau sub-basin (Wight et al., 1993). r

In the south (Muara Sub-basin) oil and gas shown in exploration wells indicate that source facies with generative potential are present in the basin. The source rock intervals in this sub-basin are possibly the Eocene Malio

Formation and the Oligo-Miocene Birang Formation. The Malio Formation consists of fossiliferous mudstone with minor carbonaceous material. Planktonic shales and marls of an open marine facies are dominant within the Birang Formation.

Petroleum Generation andMigration

Geothermal gradients are quite variable within the basin, ranging from 2.6 °Cll00m to over3.5 °CII OOm to the south-west and at Bunyu Island. Where penetrated, the Pleistocene and Pliocene coals and coally shales are immature to early mature (max. Ro usually 0.5 sometimes reaching 0.6+) in all wells except at the base of Mamburungan-I (3065m), where peak maturity (Ro 0.7) is just attained. Modeling of vitrinite maturity profiles by previous operators indicates that an Ro of 0.7 would be attained below wells at depths of around 3200-3900 m (within the Miocene) depending on local heat flows.

For the well sections and hypothetical stratigraphic units below them, oil expulsion appears to have been more recent than 2 Ma (i.e., from around latest Pliocene onwards). Heat flows appear to have been generally higher during the Pliocene (1.7 HFU) than the Pleistocene (1.6 HFU) and are higher than those generally attributed to passive margins. Lower values are measured in the eastern area (e.g., Vanda-I has 1.2 HFU). This progressive heat flow decrease with distance offshore is similar to that observed for other deltaic margins in the world. A notable exception is Mamburungan-I, in which present day heat flows of 1.9 HFU are higher than in the Pliocene. Also expulsion of type WIll oils appear to have taken place earlier (around 2 Ma)

28

N-Octene

Deep Lacustrine Oils

M+P Xylene Phenol

FieldsT. Tarakan Island Pamusian

Juata Mengatal

B. Bunyu Island BunyuBunyu Tapa #2

Onshore Sembakung #2Bangkudulis-1

Vanda-1 WellV1 DSTV2-4 RFTV5 Coal Extract

FIGURE 17- Tarakan Basin Oil Types. Type IIII and 1II1J1 oils (lacustrine and fluvial) are present in the basin and most were generated at relatively low maturities (Ro < 0.9). Oils are thus spatially widespread and from many depositional environments. Few gas condensates have been found (redrawn from Wight et al, 1993).

29

than in the other wells modeled. This hot spot may be due to the presence of deep seated transform movement responsible for the structural inversion that has taken place on Tarakan Island. Additional, as yet unrecognized, hot spots may also be present in the basin. The Middle-Late Miocene may have entered the gas window during the latest Pleistocene (approximately 0.2-0.7 MYBP) within the deepest portions of the depocentres.

The above constraints suggest that oils from terrestrial (Type 111111l)acustrine source rocks lying either directly below or lateral to, but around 900m vertically deeper than the well TDs, have migrated into the Tarakan and Bunyu Island fields and the Yanda-l accumulation. Maturities of these oils are mostly equivalent to Ro 0.7-0.8 (i.e. top of the oil window) except for the more mature Bunyu Tapa oils with a Ro 0.9. Since Miocene source rocks have been proven

onshore in the Tidung

sub-basin, it is proposed that similar facies are likely to be present below Tarakan and Bunyu Island and the Yanda area. The hydrocarbons encountered in the Yanda-I are extremely significant as it establishes that mature source rocks are present far out into the basin and well away from the delta plain coals that have been documented in the updip portions of the Tarakan Basin and that are typically regarded as the likely hydrocarbon source rocks along the eastern margin of Kalimantan. Although the Yanda-I flowed gas on test, a significant liquid hydrocarbon charge could be present in the offshore portions of the basin. A RFT near TD in the Yanda-I at 3559.7 m recovered 35.3API oil in two chambers and below the testedgas zones. This data suggests that the area is not overmature for oil. The geothermal gradients likely decrease in an offshore direction, an observation that is common in passive margin basins.

30

Chapter 4Oil Play Concept

Both the Tarakan and Bunyu Arches are proven hydrocarbon fairways into which hydrocarbon charge has been focused by these basin ward plunging noses into Plio-Pleistocene sandstone reservoirs deposited in a very proximal/delta plain depositional setting (Figure 18 and 19). Unfortunately, a play in this setting has resulted in the discovery of several oil and gas accumulations with poor lateral reservoir continuity, poor recovery efficiency and typically hydrocarbon volumes that are often too small to develop under current PSC terms and market conditions. The exploration effort on the shallow shelf has concentrated on the areas immediately along strike of the plunge of the arches. Little exploration effort has been made in areas to the northeast and southwest flanks of the arches, where sandstones may either pinch-out or become truncated giving rise to wholly or partially stratigraphic trapping geometries. Traps in this dip position are difficult to identify; cross fault leakage in highly likely due to a very high net-to-gross sandstone ration. The two largest fields in the basin, Tarakan (215 MMBO) and Bunyu (140MMBO and 3.w.&rCFD are faulted anticlines.

-Allof1FieOfner acctrrriulations are substantially dependent upon fault closure and all contain less than 25 MMBO recoverable. As the southeasterly plunging arches become progressively younger from south to north there could be problems with the timing of trap formation and hydrocarbon change in the northernmost part of the Tarakan Basin.

A Miocene clastic reservoir play has been proven in the onshore Berau and Tidung

b

Sub-Basins with th establishment of production at Sembak g Field (25 MMBO) in 1976 by Arco (Figml 18). This play type is located in a half gra· en tectonic province (Pertamina OAK-SSG, 1993). Traps are found at rollover anticlines within down block of major growth faults. Play objectives of this tectonic province are Santul, Tabul, ana Meliat Formation with carbonaceous source rock of Meliat Formation. Bangkudulis Field (2.4MMBO), which is located in the west ofBangkudulis Island has the same play type asSembakung Field (Pertamina OAK-SSG,1993). Additional accumulations are likely, however, exploration has been hampered by poor seismic data quality and coverage.

Little exploration effort has been made in areas further offshore which are characterized by growth faulting apart from the drilling of well Yanda-I by Sceptre in 1990 (Figure 18). Four potentially productive fairways have been identified: I. a shelfal trend of growth faults in water depths of 20-100 meters influenced by arch inversion; 2. a growth fault trend west of the Vanda-I well in water depths deeper than100 meters; 3. an inboard crestal collapse/ graben trend of faulting located down dip"of the Bulungan Delta and 4. an outboard crestal collapse/graben trend located in the southeastern portion of the Sebawang II PSC Block in water depths greater than 200 m and downdip to the inboard crestal collapse (Figure 18)

All four offshore fairways rely upon deltaic progradation to the east and forced regressions during drops in sea level to get deposition of reservoir far down dip of existing well control. Traps could exist containing thick delta front and turbidite reservoirs in the hanging walls of large scale listric growth faults. In this setting, reservoirs and seals could be thicker and more continuous.

+

31

Il7'OO'EIJ8"OOE 119'00';

,,- ,

+ "C<N

TURBIOITE PLAY (1)

+

2'C:)'N

N

'========50 .. ._'00Km

LEGEND

Turbidite play in present day deep water ponding behind toe-trust,

Shellal Plio-Pleistocene trend with growth faults influenced by arch inversion

Plio-PleistoceneGrowth fault trend

Puo-Plerstocene- inboard crestal collapse/graben down dip of Bulungan Delta

Plio-Pieislocen~ outboard crestalcollapse/graben south 01 Sebawang II Block

r-Ho-Pleistocene faulted anticline with high nett-to-qross

Miocene clastic play with roll over anticlines and major qrowth faults

[IJ]J Miocene Carbonate play

Oligo-MioceneCarbonate play

~ NW-SE anticline arches ~ Basin Boundary

FIGURE 18 - Oil Play Concept Map of the Tarakan Basin

«C

o

32

w

:z(f)«

ID,

w:z

ui(f)

:z~«a::«I-,

:z(f)

ID

,ID::>(f)

«a::«::>~,

::>«a::uiID

eo c::s

-0f='-

o""'!'3

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c

-e'u"2

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33

In the west and far north of the Tarakan Basin where clastic sediment supply appears to have been limited, Miocene carbonate shelf containing isolated build-ups rised (Figure 19). These build-ups have been tested by several wells and found to be tight. North of the Ahus Arch are the Plio-Pleistocene is characterized by a larger proportion of carbonates. Thick untested carbonate buildups have developed along the footwalls of many of the faults. Reservoir quality is the highest risk in these carbonate buildups.

Oligo-Miocene carbonate reefs of the Tabalar Formation comprise the most prospective play in the Muara Sub-basin (Figure 19). No commercial hydrocarbon discoveries have been made, however, oil and gas shows were reported in exploration wells which penetrated

reef prospects at Karang Besar-l , Segitiga-l and Tabalar-l. This sub-basin is structurally less complex being characterized by uniform subsidence between basement ridges and persistent carbonate deposition on basement highs and platform areas. Trap types include pinnacle reefs aligned on tenuous structural ridges or shelf edge, fore-reef talus deposits, wrench related folds, wedge out on flanks of structures or along unconformities, and reefal facies located on basement highs or on discrete ridges. Onlap and pinchout stratigraphic traps of Eocene sandstones are poorly defined from seism ic data (Beicip, 1992). Here the primary risks include charge, because the basin is not deeply buried, and trap because the build-ups are large along with the potential for thief zones on lapping the build-ups.

34

Chapter 5Conclusions

Tarakan Basin consists of four sub-basins, named Tidung, Tarakan, Berau and Muara Sub-basins. The basin initially formed by rifting during the Eocene with continued spreading of the Makassar Strait evident present day. The basin is bounded by Pre- Tertiary basement in the west and wrench faults in the north and south. The Tarakan Basin is open to the east. The sub-basins are separated by faults and unconformities.

Exploration activity in the greater Tarakan Basin dates back to the earliest exploration for oil and gas in Indonesia in the nineteenth century when discoveries were made at Pamusian (1906; ultimate recoverable 215MMBO), Juata (1918; ultimate recoverable 18MMBO), and Bunyu (1927; ultimate recoverable 140 MMBO and 350 BCF Gas). All of the subsequent discoveries are less than5 MMBO reco~erable with exception ofSembakung Field (1976; ultimate recoverable25 MMBO).

The presence of hydrocarbon charge is not considered to be a critical risk considering the existing production, the presence of onshore oil and gas seeps, natural offshore oil slicks and hydrocarbon shows in exploratory wells. The stratigraphy reflects -the generally regressive nature of the Late Cenozoic with marine carbonates of the Oligocene and Miocene grading into progressively more clastic dominated Plio-Pleistocene sequences.

identified throughout the Post-Oligocene section in all of the Sub-Basins.

All of the production to date occurs in a very proximal depositional setting. The objective section typically contains abundant coal units, thin continental and nearshore marine shales and numerous thin channel sandstones.

Reservoir net-to-gross and percent sandstone is typically quite high 30-65 percent; explaining the high failure rate of fault traps, and higher volumes in faulted and simple anticlines. Clastic plays further down-dip where reservoir and seal continuity may be much higher could be more successful.

Large carbonate build-ups of Oligo-Miocene age provide attractive exploration targets in she lightly explored Muara Sub-basin.

Acknowledgment

We gratefully acknowledge Shell Companies in Indonesia for data and facility support. We would like to thank Bambang, Wahyudi, Sugiran, and Hipni for their drafting support. Paul Kehrens is thanked for his contribution in Figure 5. The primary draft of this paper was reviewed by Geoff Edwards.

35

References

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