PROCEEDINGS INDONESIAN PETROLEUM ASSOCIATION Twenty Third Annual Convention, October 1994

ABSTRACT

TAMPUR FORMATION, THE FORGOTTEN OBJECTIVE IN THE NORTH SUMATRA BASIN ?

Rudy Ry acudu* Eddy Sjahbuddin*

Hydrocarbons within the North Sumatra Basin are produced mainly from both clastic and carbonate reservoirs of Miocene age (i.e. the Peutu/Belumai, Baong and Keutapang Formations). Currently, hydrocarbon exploration in the area is becoming more and more difficult since the basin has been intensely explored since the beginning of the century. The objective of this paper is to describe hydrocarbon potential in the Tampur Formation, a new and promising objective present below the existing "zone of interest" and an alternative drilling target for future exploration in North Sumatra.

The Tampur Formation was deposited as a thick and uniform shelf carbonate sequence over a broad shallow shelf during the Late Eocene. The formation is widely distributed over the Tampur Platform. The western margin of this shelf carbonate was apparently marked by the major north-south oriented Lokop- Kutacane Fault zone. East of this fault zone, reefal buildups occurred on the shelf edge.

The Tarnpur Formation carbonates have been described at outcrop as being of potential reservoir quality. Dolomitisation during diagenesis may have resulted in the formation of potential reservoir rocks. Areas where limestones are present within the dolomites may contain primary porosity. Secondary porosity may be present as fractures or vugs.

Since the early structuring of the basin, Tampur Formation limestones and dolomites have formed basin highs, structurally above and adjacent to, thick shale sequences laid down in the intervening troughs.

* Pertamina

These shales have been mature and generating hydrocarbons since the Miocene.

Significant quantities of gas have already been tested from the Tarnpur Formation where it occurs beneath the Peutu carbonates at Alur Siwah, Peulalu and from beneath certain of the Malacca Limestone Member reefs offshore. Strong gas shows are also recorded from the Tampur Formation at the Sembilan-A1 well in Aru onshore area.

Although the Tampur Formation could be considered as an additional drilling target, it does contain some risks. It is also postulated that a substantially untested hydrocarbon play exists within the Tampur limestones/dolomites and these could be tested where the formation is structurally high within the basin.

INTRODUCTION

The study area covers the North Sumatra Basin, which occupies a roughly triangular area located over both on- and offshore North Sumatra (Figure 1). The productive layers within the basin are commonly from both clastic and carbonate reservoirs of Miocene age: the Peutu/Belumai, Baong and Keutapang Formations. Minor discoveries have also been found in the post-Keutapang and pre-Belumai Formations.

Exploration in the basin is very mature, and almost all of the sizable structural anomalies in the primary objectives have been drilled. Major oil fields have been discovered and developed since the Dutch colonial time, such as the Rantau and Julu Rayeu, which produce hydrocarbon from Keutapang sandstone reservoirs. The most significant event in the post-war era was discovery of the giant Arun Field that discovered gas from the Peutu reefal limestone in

© IPA, 2006 - 23rd Annual Convention Proceedings, 1994

the early seventies, and lead to basin-wide exploration for Peutu carbonate objectives.

Exploration of the shallow targets, particularly the Keutapang Formation and some in the Middle Baong Sandstones objectives, have reached a very mature stage. Conventional exploration tools such as structural mapping on hvo dimensional seismic have reached the limits of their usefulness for the Keutapang objective. In the short term, seismic tools such as Direct Hydrocarbon Indicator (DHI) detection supported by modelling, attribute and Amplitude versus Offset (AVO) studies may open up new opportunities. In the longer term, three dimensional seismic should aid in finding additional fault blocks around existing fields. However this expensive method needs to be addressed by a costbenefit analysis prior to any decision to proceed.

Exploration for the deeper targets is made more difficult because it is. hard to predict the occurrence of good quality reservoirs, and maturity and migration pathways within the PeutdBelumai and older formations. Exploration plays are, so far, still concentrate on reefal buildups in the Peutu Formation and anticlinal traps in the Belumai Formation sandstones (equivalents of the Peutu Formation). Targets deeper than BelumaiIPeutu Formations (pre- Belumai) are relatively unexplored. Riadhy and Gutomo (1993) discussed the hydrocarbon potential in the Basal Sandstones (equivalent the Bampo Formation), but only a few papers that discuss the hydrocarbon potential of the pre-Belumai have been published.

The North Sumatra Basin is one of the few back-arc basins in Western Indonesia to contain Eocene carbonates (Figure 2). Other Eocene carbonate occurrences are reported in the East Java Sea region extending onshore onto what is now Java. There it consists of foraminifera-rich limestones, some of which contain significant buildups. These carbonate buildups have been described by Kohar (1985), have served as exploration targets in the East Java Basin, and have yielded gas in the area just west of Kangean Island. The Paleogene carbonate in the Kutei Basin, the Berai FormationKerendan Limestone is also a target for exploration.

The objective of this paper is to discuss hydrocarbon potential in the Eocene Tampur Formation as an

alternative target for future exploration in North Sumatra. However, due to very limited data and analyses available from this formation, the results of this study should be regarded as very preliminary and need to be followed-up by more comphrehensive and detailed work.

REGIONAL GEOLOGY

Tectonics and Structural History

The structural history of the North Sumatra Basin throughout the Tertiary period can generally be divided into the Paleogene and Neogene tectonic phases. Initial tectonic activity during the Paleogene began in the Late Eocene when the North Sumatra Basin was subjected to crustal extension as a result of collision between the Indian Continent with the Eurasian Plate (Daly et a1 1987), resulting in the formation of pull-apart "rift" sub-basins with a dominant north-south structural orientation. The major structural elements are the Pase Sub-basin which separates the Tampur and Sigli Platforms and is bounded by the Samalanga-Sipopok and the Lokop- Kutacane Faults (Figure 3). Collision and subduction of those plates then decelerated in the Early Oligocene. This changed the former extensional regime to compression resulting in basin inversion that is expressed by the regional uplift and an unconformity over Eocene sediments within the basin. Relaxation of above compressive stresses during the Late Oligocene resulting in block faulting which occurred along pre-existing lines of weakness of the Early Oligocene synthetic faults (Sosromihardjo, 1988). This uplift has thus placed the older sediments (the Tampur Formation) in a high structural position while the basin depocentres (grabens) provide locus for the younger, finer clastics deposition (Figure 4).

The rifting of Andaman Sea started in the Early Miocene (Neogene), and resulted in a marine incursion into the North Sumatra Basin (Davies, 1984). This allowed continuing transgressive periods within the basin that started in the Late Oligocene and reached a maximum by the end of Middle Miocene time. This period was marked by dominant right lateral transpression leaving a predominantly northwest-southeast structural orientation over the previous north-south structural grain. The Barisan uplift, which has been active since the Miocene,

climaxed in the Pliocene with successive pulses to the present day.

DEVELOPMENT OF THE TAMPUR CARBONATES

Lithologic Description

Tertiary sedimentation within the North Sumatra Basin is thought to have begun in the Late Eocene when transtensional tectonics created north-south trending grabens. These grabens filled with siliciclastic sediment, known as the Meucampli Formation, which unconformably overlies the pre-Tertiary basement (Figure 5). The sediment supply was from the west because farther east was a broad shelf where carbonates of the Tampur Fornlation accumulated. The Tampur carbonates, which are well developed in the east, interfinger with deep water shales of the Meucampli Formation. In the southwestern part of the basin, the Meucampli Formation exhibits a coarser clastic facies.

Following a major period of exposure in the mid - Oligocene, a major marine transgression occurred. The Parapat/Bruksah Formations represent an influx of fluvio-continental, coarse grained sediments into the basin. This was followed in the Late Oligocene by marine incursion and deposition of the Bampo shale. Certain of the troughs forming at this time foundered significantly and are the sites of very thick deposits of euxinic Bampo shale. By Early Miocene, a change in the paleogeography was evidenced by widespread carbonate deposition of the Peutu Formation on the shelf and on highs within the basin. This formation is equivalent to the Belumai Formation that was deposited in the eastern portion of the basin, and represents a shallower water setting which contains calcarenitic facies. The marine transgression that is marked by basin-wide sedimentation of marine shales of the Baong Formation climaxed in the mid-Miocene.

The uplift of the Barisan Mountains began in the latter part of the Middle Miocene. This uplift was preceded by a regression within the basin which 1cd to the sedimentation of the so-called the Middle Baong Sands. The Upper Miocene-Pliocene regressive phase began with the deltaic Keutapang Formation sandstones, followed by the continentallparalic Seurula and Julu Rayeu Formations, signaling the end of a long transgressive period in the North Sumatra Basin.

In its type area along the Tampur River, the Tampur Formation is described as being composed of massive, partly biocalcarenites and calcilutites, common dolarenites, chert nodules and basal limestone conglomerates that indicate an open marine sublittoral environment. In the surface outcrop west of Simpang Kanan River, the Tampur is interpreted as a thick shelf carbonate deposit with some reefal buildups (Cameron et a1 1980). In the subsurface, most of Tanipur lithologies are recorded from deep wells in the Am and Langkat areas of Pertamina acreage, the Asamera Block "A" and some of the Mobil "NSB" wells offshore. It consists of limestones, commonly dolomitised and fractured, and locally containing scattered quartz grains.

An example of detailed lithologic description of the Tampur dolomite in existing wells is represented by the Rajarnuda-1 well which encountered 557 feet of the Tampur Formation (Figure 6). The top of Tampur in this well is marked by an abrupt change of lithology from that of the overlying Belumai Formation. The formation is primarily composed of dolomite with minor lamination of calcilutite. The dolomite is light gray to light brown in colour, recrystallized, predominantly micro- to finely crystalline and sucrosic, hard, brittle, occasionally friable. Very fine fractures occur and are occasionally filled with white, subhedral, sparry dolomite and sparry calcite. With depth the dolomite becomes slightly argillaceous with traces of pyr~te and fine carbonaceous stylolites. The section shows minor intercrystalline porosity with some vugs having vuggy porosity.

Dolonlitic breccias also occur, (ex. Alur Siwah-3 well), and represent karstic debris associated with subaerial erosion of the Tampur Formation over emergent highs in the Late Oligocene to Early Miocene times.

Distribution

The Tampur Formation carbonates occur on what was apparently a fairly broad shelf over what is now the eastcm part of the North Sumatra Basin. The western

margin of this carbonate shelf corresponds with the position of the north-south trending Lokop-Kutacane Fault (see figure 4). This major fault probably represents a hinge zone across which the basin deepened rapidly westward into the Jawa Deep. Some evidence of Eocene reefal buildups is present on the carbonate shelf, but the carbonates generally disappear westward into what were apparently deep-water shales to the west of this fault. To the east, an influx of siliciclastics from the Sunda Craton influenced the development of carbonate deposition on the the Eocene shelf. The Tampur limestone and dolomite now form the lowest correlatable unit in the eastern part of the North Sumatra Basin.

As an exeption to this model is the existence of Tampur Formation in the Peusangan area to the west of the Lokop-Kutacane Fault on the Western High. In the Peusangan C-1 well, 956 feet of the Tampur limestone and dolomitic limestone sits on top of basement rock. The Tampur was not reached in the Peusangan D-1 well due to abandonment in the Peutu section, and it is absent in the Peusangan E-I well (Figure 7). One possible explanation for the presence of the Tampur in the Peusangan area is that it was a paleohigh during the Eocene, however the distribution pattern of the Tampur in this area is unknown.

Due to lack of identifiable fossil content within rocks older than Miocene in the North Sumatra Basin, age determination of pre-Miocene carbonates is difficult. Former explorationists, for practical reasons, often describe those pre-Miocene carbonates as the pre- Tertiary or economic basement without any further age investigation. Lithologic correlations of such carbonate rocks are arnbiguious due to existence of several formations containing carbonates that have ages older than the Tampur, such as the limestones of the Permo-Carboniferous Alas Formation and those of the Triassic Kualu Formation (Cameron et a1 1980). In spite of this, Robertson Research (1974, in Caughey and Wahyudi 1993) assigned the Tampur an age of mid-Eocene to Oligocene.

Age definition of the pre-Miocene carbonate formation is therefore subject to debate. However, within this paper all of the pre-Miocene carbonates in the eastern part of the basin are assigned to the Tampur Formation (after Sosromihardjo, 1988) and

are tentatively interpreted to be Late Eocene - Early Oligocene in age, exept where exact rock dating is available and conforms to an older age.

HYDROCARBON POTENTIAL

No specific data is availabIe on porosity or permeability data of the Tampur Formation limestones and dolomites, but suitable reservoir quality can be expected to occur considering its history of sub-aerial diagenesis and resulting dolomitisation. Pre-Miocene structuring, as well as the latter tectonism, may have resulted in extensive fracturing and carbonate dissolution, which could have enhanced the Tampur section as a prospective hydrocarbon reservoir.

The most common diagenetic process within carbonate rock that affects reservoir quality is dolomitisation. McArthur and Helm (1982), in their observation of the Miocene carbonate buildups offshore North Sumatra, found that the process of dolomitisation can both increase and decrease porosity. Porosity shancement by this process is achieved when the replacement of limestone by dolomite, the individual crystals do not interfere with each other. The additional porosity is preserved due to the tendency of dolomite not to infill pre-existing moldic pores. On the other hand, dolomitisation can proceed further with interference of crystals during growth resulting in hypidiotopic to xenotopic texture and destroy virtually all porosity (McArthur and Helm 1982). Such processes are expected to occur in the Tampur carbonates.

Cutting description from Sembilan-A1 well which penetrated 665 meters of the Tampur carbonate indicate fracture and vuggy porosities ranging from poor to fair. Nearby well Am Bay-1 drilled 85 meters of thick, fractured dolomites that may correlate with the Tampur carbonates and fracture porosity is estimated at 5 - 10 %.

Source Rock Consideration

The Tampur Formation was deposited in an open marine shelf setting that is in general lean in organic matter, and normally provide poor source materia1 for large scale hydrocarbon generation. Since the Tampur is the oldest sediment within the North Sumatra Basin

and the pre-Tertiary sequences are thought to be metamorphosed, hydrocarbon accumulations within this formation are almost certainly sourced fiom the younger sediments.

Petroleum generation aspects in the North Sumatra Basin have been described by many authors, such as Kingstone (1978), Pranyoto et a1 (1990), Subroto et a1 (1992), who designates the Lowermost Baong Formation, Belumai (Peutu) Formation and Bampo Formation as possible source rocks in term of their organic richness and maturity. These stratigraphic horizons, however, could not be regarded as very exellent sources, since total organic carbon (TOC) content are rarely exeeds 1 %. The kerogen type is a mixture of humic and amorphous material, which is believed to generate condensates under certain depth and temperature conditions. Davis and Stanley (1982) report that this effect may be enhanced by the catalytic effect of the high smectite content of the shales.

Stratigraphically the Tampur reservoirs are older and generally deeper than the Lower Baong, Belumai and Bampo shales which are regarded as having source potential. This setting is not very favorable for charging the Tampur. However, under certain conditions where the Tampur is structurally high, hydrocarbons could migrate into the Tarnpur, as is schematically depicted in Figure 8.

A good example for this is shown in the Salem-1 well, where an uneconomic accumulation of oil is present in Tampur dolomites (Figure 9). The short oil column within this reservoir is thought to be a result of relatively thin source rock in this area and the imperfect nature of the trap. Geochemical studies of the oil phase in the Salem-1 we11 indicate that it was generated from an oil prone source rock, which in this setting could only be the upper part of the Lower Baong shale. Regionally, hydrocarbons from the Lower Baong and Belumai shales as well as the black shale of Bampo Formation could charge the Tampur Form ation.

Source Rock Evaluation

As has been mentioned above, hydrocarbon source rocks in the North Sumatra Basin consist of Lower Baong shale, Belumai and Bampo black shales.

However, one or all of those sources may not act as an effective source rock in particular area. The Baong shales are not considered as source rock for oil in the Mobil NSB area. However, to the west in the Pertamina, Japex and Asamera areas, the Baong has good source potential aand is an important source rock for the oil produced from the Lower Keutapang and Middle Baong Sands. Measurement of TOC in the lower part of the Baong Formation from wells and surface samples collected throughout the Tertiary sections in the study area indicate value ranging from 0.55 % to more than 1.5 %. The HI versus 0 1 and HI versus Tmax cross-plots (Figure lo), and visual examinations of organic matter present from samples both in wells and outcrops indicate type IIAII kerogen (lipid, mixed humic) and almost all the samples contain a mixture of terrestrial and marine type of organic matter that are interpreted as oil and gas prone.

The character of the oils and source rock suggest that the Baong Formation source rock contain re-worked organic matter, with an original environment of deposition in the coastal plain. This organic matter is derived from non-marine algae and resinous higher plants, and oil generation has occurred at about middle maturity.

The HI versus 0 1 cross-plot for the Belumai Formation (Figure 11) clearly indicates that almost all the samples have less HI value and hence grouped as type I11 kerogen (gas prone). The kerogen composition contains a mixture of lipid and mixed humic type.

Measurement of TOC in samples of the Bampo black shale from very limited wells combined with surface samples collected in the Pertamina acreage, indicate values ranging from low (0.1 %) in DRU-1 well to a maximum of 1.55 % in surface samples. This formation, in term of its maturity, is mature to post- mature over most of the area analysed. From surface data analyses, it is known that the VR value could exceed 1.2 % Ro and the value of Tmax above 450°C, particularly in the lower part of the formation (Figure 12). As subsidence and codking continued, the rocks became overmature for oil , and the oil begins to degrade to gas. The Bampo black shale (and Peutu) is an important source rock for the gas in the Arun field.

Hydmcahon Generation and Migration

The oil produced from the North Sumatra Basin is characteristically parafinic, with high gasoline content and high gravity typically in range 45 - 65' API. Most of the oil fields produce some associated gas.

Lopatin analyses conducted on a number of wells in the Aru, Aru Offshore, Rantau and Asamera Block "A" indicate that hydrocarbon expulsion from the Bampo shales began in Early Miocene (1 1 MYBP) or earlier, while the Belumai and Lower Baong shales have been matured since the Late Miocene - Pliocene (starting from 8 MYBP).

Maturity increases rapidly with depth, showing above average to very high gradients, so that the average onset of oil generation occurred at 1500 m. In many of the analysed wells, the top oil window is reached at the depth of 1000 - 2200 m, and the transition to post-maturity at which source rocks generate condensate and gas, is expected between 2500 to 4500 m depth. Dry gas and metamorphosed hydrocarbon occur at more than 4500 m.

By considering a number of factors such as the geothermal gradient, heatflow, overburden thickness, kerogen type as well as "cooking time" of the Bampo and Belumai shales, the most likely type of hydrocarbon generated is thought to be gas. The Baong shale will tend to generate oil/condensate and minor gas.

According to analyses of oil to source correlation in the Salem-1 well, it is suspected that oils in the Tampur are sourced from the Lower Baong shales. This is supported by the fact that the Bampo facies does not develop in this area. Occurrences of gas in the, Sembilan A-1, Lemuru-1 and Glagah-1 wells are thought to have migrated from Bampo shales that are structurally juxtaposed against the Tampur.

Traps and Seals

Structural and stratigraphic traps may exist in the Tampur Formation: Reef buildups could be expected to occur along the Tampur shelf margin adjacent to the Lokop-Kutacane fault line. Tampur reefal buildups that occur in outcrop at Simpang Kanan River are apparently located near this shelf edge. The fractured and/or karstic debris of the Tampur carbonates located

on highs might contain porosity and permeability that could make them viable reservoirs. The Bampo or younger shales could provide effective seals. Compressional tectonism, which took place since the Late Miocene in the North Sumatra Basin, may have folded the Tampur as well as younger sediments into four way dip anticlinal traps.

As mentioned above, the shales of the Bampo Formation are expected to act as effective seals for the Tampur traps. In general, the Bampo can be devided into three parts. The lower part consists of massive dark gray to black claystone and siltstone and is locally calcareous, poorly bedded, micaceous, pyritic and with traces carbonaceous material. The middle part is composed of dark gray micaceous shale with marl streaks and calcite veins, while the upper part is composed primarily of dark gray to gray shales and partly calcareous claystone.

Relationship between the Tampur and CO, Distribution

The most common problem associated with deep drilling objectives in the North Sumatra Basin is the occurrence of CO, and H,S, mixed with hydrocarbons that may cause drilling hazards, corrosion of production facilities and reduce the economic value of prospects. Previous writers (Alfian and Manik, 1993; Caughey and Wahyudi, 1993) assumed that the occurrences of those non- hydrocarbons gases are caused by thermal decomposition from the pre-Miocene carbonate rocks, and therefore downgrading the Tampur as a drilling objective. Current technology can only treat up to about 20 % CO,, (i.e., the Arun gas quality).

In this paper, no attemp is made to discuss further the origin of CO, and H,S within the North Sumatra Basin. However, contrary to previous hypotheses, there is no direct correlation between the occurrence or concentration of CO, and H,S in reservoirs and the presence of Tampur Formation carbonates (Table 1). For example, in the Kuala Langsa-1 well the very high content of CO, in the Peutu carbonate reservoir (82 %) is present above a basement of pre-Tertiary metasedimentary rock, while in the Kuala Muku-1 well CO, content within the same reservoir is low (6.5 %) although it is underlain by the Tampur carbonates. From the above examples we can only conclude that the origin of CO, remains unclear.

IDENTIFICATION OF THE TAMPUR ON SEISMIC

Identification of the Tampur reflector on seismic is another element of risks in in exploring for it as an objective since its seismic characteristic is difficult to distinguish from the "true" pre-Tertiary basement. It is common, particularly on seismic data not designed for deep targets, that at depth below the Peutu the data quality begins to deteriorate and horizons cannot be traced with confidence across the whole area. Control from deep wells is very limited. Once away from areas of direct well control tracing the Tampur reflector becomes very tentative due to very poor seismic definition.

On good quality seismic sections, the Tampur carbonates can be recognized by the existence of fairly continuous and parallel reflectors above the accoustic basement. Undisturbed shelfal carbonates often shows strong amplitude on the top of formation. To avoid misinterpretation, it is suggested to use seismic data that specially designed for deep objectives and data processing should be done with close attention to velocity picking and multiple attenuation.

PLAY CONCEPT

At least three proposed exploration plays exist within the Tampur Formation : 1) Reefal buildups; 2) Fractured anticlines; and 3) Karstic debris.

Although no Tampur buildups have yet been found in the existing deep wells, according to surface data it could be expected to exist in the subsurface particularly along the Tampur Platform shelf margin. Study into the mechanism of Tertiary structuring will be beneficial in localizing the area where the Tampur carbonates were intensely fractured. Karstic debris of the Tampur could exist both on reefal and fractured Tampur carbonates. These plays only work where the Tampur is surrounded and blanketed by shales that could provide source rock and seal.

Considering these mentioned factors, suitable areas for the Tampur exploration could be localized around the western part of the Asamera Block "A", the Rantau area, Langsa Bay and the northwest of Gebang Block.

HYDROCARBON OCCURRENCES

No commercial production has yet been found in the Tampur carbonates, but this is probably due largely to the fact that it has not specifically been targeted as a drilling objective. Gas has been tested from the Tampur dolomite in a number of wells, i.e. Alur Siwah-8, Peulalu-2, Lemuru-1 (Caughey and Wahyudi, 1993) and Sembilan-Al. The gas from Alur Siwah and Lemuru contains H,S and CO,.

Three wells in Pertamina-Japex "Gebang Block", the Aru Bay-1, Gebang Offshore (G0S)-1A and 2-A, encountered the Tampur, but only Aru Bay (ABY)-1 evaluated this section throgh testing. Three RFT's were run recovering up to 2134 m3 of gas and 300 cc of water. The test contained up to 50 % CO, and 4200 ppm H,S. Two wells, Glagah-1 and Salem-1, to the east of north respectively of the Gebang Block, both yielded significant recoveries of hydrocarbon from DSTs of the Tampur carbonates. The tests in both wells, unfortunately covered the overlying zones as well, and therefore it is unclear how much of the hydrocarbons flow was from the carbonate section alone. The DST's from the Glagah-1 well recovering 337 m3 condensate per day (52.2 API), 25,768 m3/day gas and contain 12 % CO,. From Salem-1 well, results where 551,615 m3/day gas and 6.04 m3/day condensate.

CONCLUSIONS

From the above discussions the conclusions could be drawn :

The Tampur Formation carbonate is the result of the marine shelfal deposition during the Late Eocene - Early Oligocene time and is the oldest sediment in the North Sumatra Basin. This formation is widely distributed in the eastern part of the basin now known as the Tampur Platform.

Although most of existing well data reveal tight formation, under certain conditions the Tampur carbonate is expected to develop good reservoir qualities. Where structurally high, it should be included as an exploration target, at least as an additional objective beneath the overlying Peutu objective.

Significant quarttitles of gas within the Tampur

can be expected and are probably sourced from the mature finer clastics located in lows west of the Lokop-Kutacane fault system and/or local lows in the Tampur Platform which have been formed since the Paleogene.

4. The source of high content of CO, and H,S within the Peutu reservoir equivalent is so far unclear, and there seems to be no direct correlation between the presence of these non- hydrocarbon gases and the existence of an underlying Tampur carbonate section.

ACKNOWLEDGMENTS

We wish to thank the management of PERTAMINA for their approval to publish this paper. Special gratitude is expressed to our colleagues for their support for the inception and publication of this paper.

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TABLE 1 C 0 2 CONTENT IN THE PEUTU RESERVOIR EQUIVALENT.

TOTAL DEPTH WELUFlELD I (,,,,

Salem-1 2931

Semblkn A-1 3720

Tertpang-I 2327

South Lho Sukon-1 2604

BOTTOM HOLE

EMPERATURE

('c)-

191.3

168.7

113.8

168.6

170.6

161.9

1 e5.s

201.2

124.8

146.5

141.4

170.1

107.7

145.4

160.1

187.2

186.1

C02

CONTENT

(W

3 0

I1

4

2 6

7 .a

2 .9

62

45

3 1

1

21 .8

44.6

60

0.4

20

4

14.6

SUBSTRATE

B8umeW. Phyllno

B88ement. Llma8tone

Tampur, Dolomko

Baummnt, Onalto

Unknown (not n8ch.d)

Tampur, Oolomhe

rampur Dolomite

T8npur. Dolomne

B8e*ment, Met.-greyweeke

Tampur. Oolomhm

Unknown (not n8ek.d)

*) BHT 1s c&xhtsd by u8lng tormu* : (TO x gooIherul pndlent) + 12. C

..) R U I data 1. unknown, 4.CCI100m I0 averago value In Lhe NSB.

TABLE 2 INTERVAL VELOCITY OF SEDIMENTS IN THE C-1, D-1 AND E-1 WELLS

(PEUSANGAN AREA)

FORMATIONS

Quatornary

Julu Rayeu (U)

Julu Rayeu (L)

Sourufa

Keutap~ng (U)

Koutapang (L)

Baong

Peutu (U)

Peutu (L)

Bruksah

Tampur

Baoe mont

OEPTH (M)

-

INTERVAL VELOCl7-v FOOT PER SECOND

6530 (C-1)

METER PER SECOND

1 990

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Two Way Time (Seconds)