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IPA05-G-039

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION Thirtieth Annual Convention & Exhibition, August 2005

THE PETROLEUM SYSTEMS AND FUTURE POTENTIAL OF THE SOUTH SUMATRA BASIN

David Ginger* Kevin Fielding**

ABSTRACT This review is based on analysis of field and well data, palaeogeographic mapping, and seismic-based studies of structural history, maturity, migration pathways and trapping mechanisms. The mapped distribution and quality of source, reservoir and seal are reviewed to determine the critical factors constraining the basin’s petroleum systems. Play-based creaming curves are used to estimate remaining potential. The South Sumatra Basin contains a mixed terriginous, volcaniclastic and carbonate fill. Five plays account for the majority of discoveries to date. These are found in; Pre-Tertiary fractured basement, Oligocene to Early Miocene (Lower Talang Akar Formation) fluvio-deltaic sandstones, Early Miocene (Batu Raja Formation) carbonates and Early Miocene (Gumai Formation) and Middle Miocene (Air Benakat Formation) shallow marine sandstones. Oligocene-Early Miocene age lacustrine and deltaic source rocks are recorded or implied by discovered oil characteristics. Source-rock type and distribution has influenced the distribution of hydrocarbons while in some areas hydrocarbon generation predates structure formation. The pinch-out of Oligocene and Miocene regional seals limit prospectivity on the eastern side of the basin. Cumulative oil production has exceeded 2 BBO from an estimated original reserve of almost 3 BBO. Original gas reserves are estimated at 22 TCF, with less than 6 TCF produced to date. An estimated 6 to 10 TCF of gas and 0.2 to 0.5 MMB of oil remain to be discovered in proven plays. * Amerada Hess Malaysia ** Amerada Hess Limited

Historically oil production dominated with associated gas being flared. More recently gas has been exported to Central Sumatra and Singapore. These new markets helped to stimulate exploration activity in the 1990’s. Local markets are developing although considerable stranded gas remains to be exploited. Securing further gas markets will revive exploration activity. INTRODUCTION Analysis of a basin-wide data set has allowed the generation of a sequence of palaeogeographic maps for each commercial reservoir horizon in the South Sumatra Basin. A regional analysis of source rocks and oil types and the timing and distribution of hydrocarbon migration has helped determine critical factors for successful petroleum systems. For the first time an overview of the basin as a whole has been assembled, providing a better understanding of its petroleum systems. The exploration and discovery history of the basin is analysed to estimate future potential. DATA BASE Approximately 18,000 km of seismic 2D data and several 3D seismic data volumes were reviewed as part of this study. In addition, well data of variable quality were incorporated from approximately 250 wells, constraining the distribution of major stratigraphic units as well as palaeogeographic and facies variations. A fields and discovery data base was generated from industry and proprietary sources covering some 275 fields, although pre-1920 fields were poorly represented due to a lack of reliable data. Oil geochemistry data used for this study were derived from GeoMark’s 1993 Far East Oil Study and

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their Reservoir Fluid Database, the related paper by Schiefelbein and Cameron (1997) and a separate study by Rashid et al (1998) on 40 oils from the south of the basin. STRUCTURAL HISTORY The history of the basin can be divided in the three tectonic megasequences described below and illustrated in Figure 1. The key structural elements in the basin are shown in Figure 2. See Longley (1997) for a discussion of the plate tectonic events controlling the structural history of the South Sumatra Basin. Syn-Rift Megasequence (c. 40 – c. 29 Ma) As a result of subduction along the West Sumatran Trench, the continental crust in the South Sumatra area was subjected to a major extensional event from Eocene to Early Oligocene times. This extension resulted in the opening up of numerous half-grabens whose geometry and orientation was influenced by basement heterogeneity. Initially, extension appears to have been orientated east-west producing a sequence of north-south horsts and grabens. South Sumatra has been rotated by approximately 15 degrees clockwise since the Miocene according to Hall (1995) resulting in a present day north-northeast south-southwest graben orientation. Post Rift Megasequence (c. 29 – c. 5 Ma) Rifting ceased approximately 29 Ma ago, however, the thinned continental crust under the South Sumatra Basin continued to subside as lithospheric thermal equilibrium was re-established. In parts of the basin, such as the Central Palembang Sub-basin, this megasequence reaches thicknesses in excess of 13,000 ft. High subsidence rates and high relative sea level resulted in a long-lived transgression of the basin which reached its maximum extent approximately 16 Ma ago with flooding of virtually the entire basin. Slowing subsidence rates and/or increased sediment input into the basin from 16 Ma to 5 Ma resulted in a pronounced regression. There is no evidence that local tectonic activity was a significant influence in this regression.

Syn-Orogenic/Inversion Megasequence (c. 5 Ma – Present) A widespread orogenic event, the Barisan Orogeny, occurred across South Sumatra from 5 Ma to present, although there is some evidence for local uplift as early as 10 Ma (Chalik et al, 2004). Elongate northwest-southeast orientated transpressional folds of varying magnitude were formed across the basin and cut across much of the underlying syn-rift fabric. Numerous hydrocarbon-bearing structural traps in the centre of the basin were formed at this time, though in some areas existing petroleum accumulations were exposed and breached. Beyond the elongate transpressional folds, basin subsidence continued as sediment input in to the basin was enhanced by erosion of the newly formed Barisan Mountains to the south and west. STRATIGRAPHIC OVERVIEW A chronostratigraphic scheme, employed to overcome the limitations of the different lithostratigraphic nomenclature used by different oil companies in the South Sumatra Basin, is shown in Figure 1. Pre- and Early Tertiary Basement The complex intercalation of igneous, metamorphic and sedimentary rocks which forms the basement to the South Sumatra basin has been simplified into a number of NW-SE basement slices each of variable composition and age (Figure 3). The oldest, least deformed basement, considered part of the Malacca Microplate, underlies the northern and eastern portions of the basin. Further south lie the heavily deformed remains of the Mergui Microplate, possibly representing a weaker continental fragment. The Malacca and Mergui Microplates are separated by the Mutus assemblage, deformed fragments of material acquired during northerly transport and collision. Heavily deformed granite, volcanic and metamorphic rock (of late Cretaceous and Tertiary age) underlies the remainder of the South Sumatra Basin. This basement morphology is believed to have influenced the Eo-Oligocene rift morphology, location and extent of Plio-Pleistocene inversion/strike-slip, local high carbon dioxide content in hydrocarbon gas, and the extent of fractures in basement.

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Late Eocene to Middle Oligocene (Lemat/Lahat Formations) Deposition in the South Sumatra Basin commenced during the Eocene to early Oligocene (De Coster, 1974). Drilled sections consist of a tuffaceous, coarse clastic sequence or granite wash (the Kikim Member) conformably overlain by shale, siltstone, sandstone, and coal deposited in lacustrine and marginal lacustrine environments (the Benakat Member). The section is thin or absent at the graben margins and on intra-graben highs and up to 1000m thick in the South and Central Palembang sub-basins. Owing to the very limited number of penetrations of the Lahat/Lemat Formations, the palaeogeographic map for this interval (Figure 4) is considered speculative. Late Oligocene to Earliest Miocene (Talang Akar Formation) During the late syn-rift to early post-rift thermal sag phase of tectonic evolution of the South Sumatra Basin, widespread fluviatile and deltaic deposition occurred across the basin. A trend from “proximal” sand-rich braid-plain to “distal” sand-poor meander belt and overbank sediments coincided with progressively more marginal marine and marine influences on sedimentation as subsidence continued. The section is often very thick in the basin centres and pinches out onto intra-basinal highs and at the basin margins. Figure 5 is a summary diagram showing the distribution of depositional environments during Oligocene times, equivalent to the Lower Talang Akar Formation (Figure 1). In the earliest Miocene, fluviatile conditions were replaced by deltaic, marginal marine and shallow to deep marine conditions over much of the South Sumatra Basin by a pronounced transgressive event. Figure 6 is a summary diagram showing the distribution of facies belts at this time, equivalent to the Upper Talang Akar Formation. Early Miocene (Batu Raja Formation) Marine transgression continued in the Early Miocene with deeper marine shale deposition over the graben areas, and shallow marine conditions over intra-

basinal highs and much of the eastern side of the basin. Carbonate production flourished at this time and resulted in the deposition of limestones both on the platforms at the margins of the basin, and as reefs on subtle intra-basinal highs. High quality carbonate reservoirs are common in the south of the basin, but are rarer in the Jambi sub-basin to the north. This is due to increased sediment input northwards and more pronounced exposure of bioherms enhancing secondary porosity to the south and east. Figure 7 shows the distribution of these facies during this period in the Early Miocene. Early to Middle Miocene (Gumai Formation) Continuing marine transgression during the latter part of the Early Miocene resulted in the deposition of marine shales, siltstones and sandstones (named the Gumai Formation) with rare carbonate deposition over the crests of basement highs. During the peak of the transgression, deposition of open marine, glauconitic Gumai shales dominated the whole basin creating the most widespread regional seal. Later, progradation of deltaic sediments across the basin occurred and transitional and then shallow marine sediments gradually replaced open marine shales. Platform areas to the east and north-east dominated sediment input, although by this time some volcaniclastic sediment was being sourced from isolated exposed volcanic islands to the west. Figure 8 illustrates the distribution of facies at the beginning of the Middle Miocene and shows the maximum extent of Early Miocene regression. The maximum extent of the preceding transgression is shown in Figure 9. Middle Miocene (Air Benakat Formation) The deep marine conditions prevalent in the latest Early Miocene were gradually replaced by shallower marine and then marginal marine conditions as a result of continued sediment input from the margins of the basin. With a few exceptions at the basin centre, high-quality shallow marine reservoir sandstones of Middle Miocene age are widespread over the South Sumatra Basin. At the basin margins, marginal marine to coastal plain conditions prevailed (Figure 10).

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As a result of the igneous activity in the Barisan Mountains, many of these sandstones have significant volcaniclastic content. This is especially true in the west, where reservoir quality is severely degraded. Late Miocene (Muara Enim Formation) The Late Miocene sediments within the South Sumatra Basin record a period of increased volcanism and the emergence of the Barisan Mountains, to the west, as the major source of sedimentary input into the basin. In the majority of wells, fluvial-deltaic and coastal swamp sediments form the majority of the Muara Enim interval, with no evidence for any regionally extensive marine shale seals. Pliocene – Pleistocene (Kasai Formation) During the Pliocene, major volcanism in the Barisan Mountains led to further increases in volcaniclastic component and further regression resulted in continental conditions being established over all of South Sumatra. The sediments are tuffs, continental claystones and volcaniclastic sandstones. Sedimentation had become patchy by Pleistocene times, with rapid uplift and erosion over inversion features coinciding with further deposition between folds to produce the current structural morphology. SOURCE ROCKS AND HYDROCARBON MIGRATION Talang Akar Formation Source Rocks The Talang Akar Formation is believed to be the dominant source for commercial hydrocarbons in the South Sumatra basin. Talang Akar intervals drilled at the graben margins contain only poor quality gas-prone source rocks whilst both paralic shales and coal horizons have significant source rock quality in thicker sections within the Central Palembang sub-basin, the Benakat Gully (Sarjono and Sarjito, 1989; Kamal, 1999; Argakoesoemah and Kamal, 2004) and wells from the Jambi sub-Basin. In Senyerang-1, for example, in the north of the basin, TOC values within the Upper Talang Akar section are variable, but can be as high as 36% with Hydrogen Index (HI) values of between 200 and 350 mgHC/g. In the Benakat Gully area shales have been reported with TOC values of 5% and HI values ranging from 110 to 400 mgHC/g, while coals are reported with HI values of 400-470 mgHC/g. These source rocks are similar to

the D/E type using the Pepper and Corvi (1995) classification. Lemat/Lahat Source Rocks The Lemat/Lahat Formation of Eocene-Oligocene age is described by Todd et al. (1997) as a lacustrine to paralic source rock. Some wells in the Bentayan field have penetrated shales with TOC values in the range 1 to 3% and are interpreted to be Class C algal oil source rocks (Pepper and Corvi, 1995) deposited in a shallow lacustrine environment. However, most drilled Lemat Formation sections have little or no source rock potential and therefore the significance of this sequence as a source rock remains questionable. Gumai Potential Source Rocks Source potential is locally found in Gumai Formation marine shales, generally towards the base of the section close to the maximum flooding surface for the basin as a whole. In some wells in the north of the basin TOC's up to 8% and HI's up to 350 mgHC/g have been recorded. These source rocks, although immature where penetrated, would form effective source kitchens if present in the deepest parts of the Central Palembang Depression and Lematang Deep. There little evidence for migration of significant hydrocarbons from this source rock, although an oil characterisation study by Rashid et al. (1998) suggested that a marine shale source rock had been the source for four oils within a restricted area of the south of the basin. Characteristics of Migrated Oils The analysed oils from the South Sumatra basin can be divided into three main types: (a) Oils derived from terrestrial Type D/E kerogens

(equivalent to Group (iii) of Schiefelbein and Cameron (1997) and the Resinitic/Oleanic oils of Rashid et al, 1998)

(b) Oils derived from Lacustrine Type C kerogens

(equivalent to the Group (i) of Schiefelbein and Cameron (1997) and the Aquatic oils of Rashid et al, 1998)

(c) Oils derived from mixed Type D/E and Type C

kerogens (equivalent to Group (ii) of

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Schiefelbein and Cameron (1997) and the Deltaic oils of Rashid et al, 1998).

The oils derived from marine Types A and B source rocks identified by Rashid et al, 1998 are additional oil types within a restricted area and are not observed elsewhere in the basin. Figure 11 is a plot of pristane: phytane ratio versus nC17: pristane ratio for oils in the South Sumatra basin. There is a clear trend from terrestrial sourced oils to aquatic (Lacustrine) sourced oils. The oil families described above have been identified based on their geochemical data. Known terrestrial oils from Mahakam and Ardjuna basins have also been plotted for comparison as well as known lacustrine oils from the Sunda and Central Sumatra basins. Figure 12 is a plot of the δC13 isotope values for the same oils with the same subdivision of oil types. The oil groups derived from the geochemical data also have a spatial relationship (Figure 13). Oils derived from terrigenous source rocks are found in the north-east and south-east, while lacustrine oils appear to be prevalent to the west and in particular the southwest part of the basin. The oils derived from a mixed terrigenous/lacustrine source lie on the eastern central area of the basin. The regional distribution of oil types may be explained by reference to the Lahat and Talang Akar Formation palaeogeographic maps (Figures 4 to 6). During the Oligocene and Early Miocene the areas of highest sediment input were the fluvio-deltaic systems in the north-eastern and south-eastern parts of the basin, resulting in a dominance of terrestrially-derived kerogen in source material in these locations. Between these two delta systems, and towards the centre of the basin, lower sediment input allowed the formation of localised non-marine and marginal marine lakes and swamps and thus mixed kerogen composition. Further to the west, terrestrial input was negligible, and lacustrine kerogens thus dominate. CARBON DIOXIDE Variable carbon dioxide contents in hydrocarbon gas have been encountered across the basin, in some cases at concentrations sufficient to delay or prohibit commercial development (i.e. greater than 50%). Although there are exceptions, moderate to low carbon dioxide content dominates in Talang Akar

Formation reservoirs and δC13 data indicate that age equivalent thermally immature coals (75 – 120oC) are the principal source. At slightly deeper levels (>150ºC), carbon dioxide is produced by low temperature carbonate metamporphism and where the Batu Raja Formation is deeply buried, such as at Singa Field, this may explain the higher carbon dioxide content. Metamorphic mineral reactions continue to greater depths (350ºC and beyond) with carbonates, granites and calcareous shales producing further carbon dioxide with a characteristic δC13 signature - this is the major source of carbon dioxide in South Sumatra, especially above deep basins where carbonates exist within the Pre-Tertiary basement (e.g. under the Jambi Central Basin, as also discussed by Suklis et al, 2004). MATURATION AND MIGRATION PATHWAYS Maturity Modelling Figure 14 is a maturity map on basement derived from well-based burial history models from across the basin and based on seismic mapping modifying earlier regional work by BEICIP (1985) and Pertamina-BPPKA (1997). Geothermal gradients were calculated from corrected bottom-hole temperatures (BHT). Either Type C lacustrine source rock, Type D/E oil-prone coal source or a mixture of the these kerogens representative of what was believed to be the source potential of Talang Akar sediments at that particular part of the basin were used in the modelling. In the majority of modelled areas an estimation of the amount of uplift and erosion within the last 2-5 Ma has been required (Figure 15). The estimates are based upon seismic and well data, with considerable sediment thicknesses removed in the majority of wells located on relatively recent inversion structures. Models for each basin area were calibrated to well-derived vitrinite reflectance data. This was a difficult task as in most cases modelled vitrinite profiles based on BHT data and standard LLNL vitrinite kinetics (Burnham et al, 1987) generated higher (hotter) profiles than implied by observed vitrinite data. The explanation for this apparent “vitrinite suppression” lies in the use of LLNL vitrinite kinetics which are inappropriate for Tertiary-age vitrinite. In Southeast Asia, vitrinite from Tertiary sediments often contains high levels of desmocollinite and is described as

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perhydrous vitrinite. Custom kinetics representing this type of vitrinite were used to achieve a generally better match and support the heatflow derived from BHT data. Talang Akar Formation source rocks (and underlying Lemat/Lahat where present) are either currently mature or were mature prior to inversion over virtually the whole of the South Sumatra Basin (Figure 14). Source rock immaturity is only an issue in certain small graben and intermediate terrace areas at the margins of the basin. For the majority of the basin, maximum expulsion of hydrocarbons was taking place at, or immediately before the time of Plio-Pleistocene inversion. This coincidence of timing resulted in migration of hydrocarbons into these inversion trends, in addition to a degree of remigration of previously expelled hydrocarbons. There is a timing problem for hydrocarbon entrapment in the deep western parts of the basin (e.g. Central Palembang Trough) where maturation and expulsion of hydrocarbons were essentially complete prior to the commencement of formation of Plio-Pleistocene inversion structures. The marine Gumai Formation source rock is calculated to have reached maturity prior to inversion over large parts of the Central Palembang and Jambi Central sub-basins. However, there is no evidence that the Gumai has source potential in these areas. RESERVOIR Pre-Tertiary Basement Where drilled to date basement reservoirs consist of fractured granites, carbonates, conglomerates and sandstones with low porosity (< 10%) and minimal matrix permeability. Hydrothermal activity and karstification of carbonate basement has provided some locally developed secondary porosity (Chalik et al, 2004). Shale-prone Pre-Tertiary rocks are generally non-reservoir. Permeability (and thus deliverability) is fracture controlled and good gas flow rates are achieved where extensive fracture systems are present. Chalik et al., 2004 conclude that the principal control on the development of fractures in the Sumpal field was the latest tectonic event characterised by regional folding and uplift. A number of granite basement sections have flowed water at high rates, the highest to date being the Pulau

Gading-1 well on the Merang High at 1800 bwpd. In general, however, reservoir quality is to date insufficient to allow significant oil flow (flow rates of <100 bopd from Beringen wells are the only current oil production). Lemat Formation The sandy Benakat Member of the Lemat Formation is a proven commercial reservoir in the Benakat Field. Lemat/Lahat sediments have also been reported as reservoirs in the Puyuh (Maulana et al, 1999; Tarazona et al, 1999) and Ibul fields. Porosities in these sandstones and conglomerates are highly variable though good porosity and permeability have been reported by Maulana et al, 1999. Over most of the basin Lemat sediments, where present, are beyond reach of the drill bit. Talang Akar Formation The Lower Talang Akar Formation reservoirs consist mainly of channel-fill, crevasse splay and point bar sandstones of fluvio-deltaic origin in the north, and delta-plain channel, delta-front, river mouth-bar and marine barrier-bar environments in the south. However, the regional variations related to proximity to the open ocean are modified by local effects related to rate of subsidence and proximity to sediment source. The non-marine succession (alluvial fans, braid-plain and meander systems) shows a vertical proximal to distal progression with time which equates to the marine transgression seen further south at Raja (Hutapea, 1981). Reservoir quality sands are concentrated within braid-plain and meander channels. There is a spatial relationship between fluvial facies with respect to both time from inception of rift topography and distance from sediment source. Reservoir quality is poor in poorly sorted, proximal alluvial sediments and distal deltaics, with porosities in the region of 10-15% (depending on depth) and permeabilities in the 1-50 mD range. In contrast, reservoir quality is good within sediments deposited far enough away from the sedimentary source area to have moderate to high textural and mineralogical maturity, but still within high energy environments. Here, porosities are concentrated in the 15-29% range, with permeabilities from 100-3000 mD.

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Figure 16 summarises the trends and environments seen in Lower Talang Akar reservoirs. In the west of the basin an increase in volcanic content results in a limited drop in porosity and a marked degradation in permeability due to the blocking of pore throats by authigenic clays. The best quality sandstones therefore lie in the east, away from the contemporaneous island arc volcanics, where flow rates ≤ 3000 bopd are recorded. Batu Raja Formation Outcrops at Batu Raja comprise a mixed succession of wackestones, packstones, grainstones and true framework reef rocks (Hadi and Simpolon, 1976). Well data show that Batu Raja Formation porosity is generally secondary in origin, the result of phreatic exposure soon after deposition and prior to burial (e.g. Clure and Fiptiani, 2001). However, high porosity layers within the Batu Raja are related to depositional as well as diagenetic processes and the extent of potentially porous clean carbonates is influenced by original depositional facies. Average porosity in producing fields is 21%. Down to 8000 ft there is no clear relationship between porosity and depth and commercial gas flow rates have been achieved from 11,700 ft in the Singa field (Crawley and Ginger, 1998). In the Pulau Gading field a gas flow rate of 17.7 mmscfd and 630 bcpd was achieved from a Batu Raja reservoir with average porosity of 11%. Reservoir permeability in producing fields ranges from 25 mD to 3.8 Darcys, although commercial flow normally only occurs after acidisation (Musi field being an exception) and flow rates up to 4300 bopd and 33 mmscfd have been achieved. Air Benakat/Gumai Formation The best reservoir sandstones are generally between 5 and 40m thick and found within the shallow marine or coastal deltaic environments. They have high porosities (generally > 20%) but variable permeability (10 mD to 3 Darcys), with 16-18% representing an effective reservoir cut-off in most fields (k < 5mD). This high cut-off is ascribed to a volcaniclastic component in the sandstones, and high clay contents due to low to moderate energy depositional environments. Flow rates are generally only moderate (< 3,000 BOPD) despite relatively thick net

pay in many wells due to a combination of low reservoir energy and relatively poor permeability. SEALS Regional Seal The Early to Middle Miocene open marine shales provide the highest quality seal on a regional scale (Upper Talang Akar, Batu Raja equivalent and Gumai formations). The depostional limit of this sealing facies during the history of the Early Miocene transgression (equivalent to each formation age) is shown on Figure 9. The Upper Talang Akar Formation seal is most effective in the central parts of the basin where it is draped over basement highs and has been proven to seal gas columns of over 500 m. The only area where the lower Gumai Formation is not an effective seal is in the west close to or within the Barisan Mountains where coarse tuffaceous sediments were deposited during Gumai times, and in five wells in the extreme east close to clastic input from the Sunda Shield. Intraformational and Lateral Seals Batu Raja Formation non-reef platform carbonates, although not effective as a seal on a regional scale, do appear able to trap hydrocarbons on a field-wide scale. Examples of this trapping are seen at Kaji, Semoga and Sungai Kenawang fields (Hutapea, 1998 and Clure and Fiptiani, 2001). Local sealing capacity is common within the cyclical sedimentation in the Talang Akar, Gumai and Air Benakat Formations and has resulted in numerous examples of stacked pay within fields in the basin. PETROLEUM SYSTEMS DISCUSSION Pre-Tertiary Basement Play The precise extent of the basement play fairway is poorly defined due its low maturity. Three proven areas of the play exist, two in the Jambi Sub-Basin (the Corridor/Jambi Selatan "B" PSC's and northern part of UEP II Jambi Barat) and one in the South Palembang Sub-Basin (the Beringen area). The critical factors for the play are reservoir effectiveness (brittle pre-Tertiary lithologies must be intensely fractured by recent inversion to provide effective hydrocarbon flow rates), gas charge of variable carbon dioxide content (causing commercial problems

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and occasionally technical failure e.g. Hallintar-1), and seal (a key control in the east of the basin as thick, continuous shale is required to support the large, connected gas columns required for significant reserves). Lower Talang Akar Formation (and Lemat/Lahat) Play The main fairway for oil lies in the north and as a strip along the eastern side of the basin, with gas potential in the central parts of the basin. The critical factors for the play are reservoir presence/ effectiveness (high quality sandstones are concentrated along the eastern margin of the basin close to sediment input points, with poor reservoirs containing high volcaniclastic content to the west and thin sandstones in the basin centre), migration/timing of trap formation (interpreted to be the cause of failure for certain wells on the Hari Terrace, and a control on the play fairway in the east away from proven source kitchens as well as in the deep western parts of the Palembang Sub-basin where generation preceded structuration) and source (the interpreted lack of source rock in the extreme southwest of the basin is thought to limit the play fairway in this direction). Batu Raja Formation Play The proven area of the Batu Raja Formation play fairway lies in the east and south of the basin. The critical factors for the play are reservoir presence/effectiveness (high porosity carbonate reservoirs are concentrated in the east and south of the basin with too much sediment input to the north and a lack of secondary porosity enhancement to the west) and seal (with failed Batu Raja tests on the extreme eastern side of the basin, at the limit of the Gumai Formation seal). Gumai Formation Play The Gumai Formation play fairway lies in the north and east of the basin. The critical factors for the play are reservoir presence/effectiveness (clean, high porosity sandstone reservoirs are concentrated in the north-east within the high energy shallow marine environment and close to the sediment input from the Sunda Platform) and seal (controlling the eastern play limit).

Air Benakat Formation Play The Air Benakat Formation play fairway lies in a central strip of the basin. The critical factor for the play is seal, with source, migration and reservoir presence all low risk across the fairway. Intra-formational seals are present in the lowermost part of the Air Benakat section over the centre of the basin but are absent higher in the succession. Seal is therefore both the stratigraphic and areal limit to the play fairway. EXPLORATION AND LICENCE HISTORY Since the discovery of oil in 1896 within the Kampung Minyak surface anticline there have been four major peaks of exploration activity in the basin (Figure 17): 1928 - 1940: Pre-war success for the Shell-led

BPM consortium using modern exploration seismic and drilling techniques for the first time.

1968 - 1975: Successes resulting from the

introduction of the PSC system in South Sumatra, with western oil companies again active in the basin.

1984 - 1988: Release of the best Pertamina

reserved acreage to the industry 1994-Present: Recent successes related to the switch

from solely oil exploration to an emphasis on gas.

Since the first discovery, over 100 fields have produced oil and gas, with over sixty of these fields still producing today. Cumulative oil production of 2.3 BBO has been achieved to date from recoverable reserves of some 3.1 BBO. In addition, cumulative gas reserves discovered in the basin has reached approximately 22 TCF with less than 6 TCF produced. Figure 18 shows the cumulative discovery curve for the South Sumatra Basin split by hydrocarbon type and by play. The Talang Akar Formation sandstones have historically been the most volumetrically

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significant play followed by the basement and Batu Raja Formation plays. The Talang Akar Formation discovery history (Figure 19a) shows some indications of a resurgence of gas discoveries in recent times (e.g. North East Betara and Gemah), which may continue, but for oil the Talang Akar play is clearly mature. Total reserves discovered to date are 1918 MMBO and 5.8 TCF gas, a ratio of 66% oil versus 34% gas. The average field size is 41 MMBOE with the largest field being Talang Akar itself at approximately 415 MMBOE recoverable. The Pre-Tertiary fractured basement play was only proven to be volumetrically significant with the discovery of the Dayung Field in 1991 (Figure 19b). Since then, however, some 8.5 TCF of gas has been discovered in a relatively restricted area of the basin. The majority of exploration wells have been successful, although a number have encountered hydrocarbon gas with high associated carbon dioxide. The play is clearly under-explored and significant future discoveries can be expected. Total reserves discovered to date are 50 MMBO and 8.5 TCF gas (96% gas). The average field size is 62 MMBOE with the largest field, also the largest in the basin, being Suban at approximately 5 TCF (850 MMBOE) recoverable. Batu Raja exploration in the South Sumatra Basin has had a long history stretching back to the 1930's. Despite this, Figure 19c illustrates that it is a relatively immature play. This surprising combination can be explained by the initial discoveries being gas-dominated structural closures (of little or no commercial interest at the time), whilst recent deeper or stratigraphically controlled features have been found using improved seismic acquisition and processing. Total reserves discovered to date are 590 MMBO and 4.2 TCF gas a ratio of 46% oil versus 54% gas. The average field size is 31 MMBOE with the largest field being Musi at approximately 184 MMBOE recoverable. Overall, volumes discovered in Air Benakat and Gumai Sandstones in South Sumatra are approximately 850 MMBO and 1.2 TCF (Figures 19d and 19e). This represents a ratio of 80% oil and 20% gas, the most oil-prone of all the South Sumatra plays. The ratio may be distorted by the past allocation of small gas discoveries as dry holes. These plays are

essentially mature though the low gas to oil ratio could indicate some future gas potential. The mean field size derived from the full population of South Sumatra fields is relatively small at less than 30 MMBOE, although the mean post-war oil field size is 36 MMBO, with a P10 (high side) field size of 58 MMBO. For gas, the mean field size to date is smaller at 135 BCF (22.5 MMBOE), with a P10 field size of over 272 BCF (45 MMBOE). Figure 20 is a graphical representation of discoveries made in the South Sumatra Basin between 1988 and 2005. Approximately 2.4 BBOE have been discovered during this time about 27% of the total estimated ultimate recoverable reserves for all fields discovered to date. Of these discoveries over 83% of the reserves were gas and 60% of the reserves were discovered in fractured basement. During the same period the rate of reserve additions was significantly higher than before reflecting a move to exploration in under-explored, stratigraphically older and structurally deeper reservoirs. In contrast, contemporaneous exploration in four way dip closed Air Benakat/Gumai structures in the centre and on the western margin of the basin resulted in failure or only the discovery of sub-commercial reserves. Pinchout plays at the margins of the basin at a number of stratigraphic levels were also tested without success. However, pinchout plays within the central parts of the basin remain an attractive target. FUTURE EXPLORATION POTENTIAL Given the long exploration history and generally benign operating environment of the South Sumatra Basin, it is unsurprisingly a relatively mature oil province. It is anticipated that few oil fields containing reserves in excess of 25 MMBO will be drilled on long-established play fairways, although some significant oil finds to 100 MMBO may be made in new or emerging play types. Extrapolating recent trends indicates that predicted oil reserve additions will be in the range of 200 to 500 MMBO. In contrast to the basin's mature oil status, the South Sumatra Basin is under-explored for gas, and contains good remaining gas potential in both new and existing successful plays. Extrapolation of recent trends in the basement, Talang Akar and Batu Raja discovery histories indicates that a further 6 to 10 TCF gas could be discovered.

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The last 15 years have seen some of the most successful exploration in the history of exploration in the South Sumatra Basin. This can be explained by the switch in emphasis from oil to gas exploration spurred on by the development of the Singapore gas market in the late 1990’s as well as improvements in seismic acquisition and processing. The remaining potential of the South Sumatra Basin is heavily dominated by gas. The exploration for these yet to be found reserves relies on the continued development of gas markets with Sumatra and West Java. The demand for gas in these areas is well documented as is Indonesia’s need to reduce fuel oil usage for power generation and to bolster declining oil production. Yet there is currently at least 4 TCF of uncontracted gas in the South Sumatra Basin. It is therefore critically important that current stranded gas reserves are brought to the Sumatra and West Java markets as soon as possible and that there is open and fair access to these markets for all. ACKNOWLEDGEMENTS The original work for this paper was undertaken at Amerada Hess in London by Kevin Fielding in 1999, with contributions from David Ginger and Steve Meadows. The authors would like to thank BPMigas and Amerada Hess for permission to publish this paper and Alasdair Duncan for comments on an early draft. REFERENCES Argakoesoemah, R. M. I. and Kamal, A., 2004. Ancient Talang Akar Deepwater Sediments in South Sumatra Basin: A New Exploration Play: Indonesian Petroleum Association, Proceedings, Deepwater and Frontier Exploration In Asia & Australasia Symposium, p. 251-268. BEICIP, 1985. Hydrocarbon Potential of Western Indonesia, p. 93-113. Burnham, A.K., Braun, R.L., Gregg, H.R. and Samoun, A.M., 1987. Comparison of Methods for Measuring Kerogen Pyrolysis Rates and Fitting Kinetic Parameters: Journal of Energy & Fuels, Vol. 1, No. 6, p. 452-458 Chalik M., Pujasmadi B., Fauzi M. and Bazed M., 2004. Sumpal Field, South Sumatra - Case History of

the Delineation and Production of a Fractured Basement Reservoir: Indonesian Petroleum Association, Proceedings, Deepwater and Frontier Exploration In Asia & Australasia Symposium, p. 199-224. Clure J. and Fiptiani N., 2001. Hydrocarbon Exploration in the Merang Triangle, South Sumatra Basin: Proceedings Indonesian Petroleum Association, 28th Annual Convention, p. 803-824. Crawley, M. and Ginger, D., 1998. Depth Prediction Ahead of the Bit: A Case Study from the Singa-1 Discovery Well, South Sumatra: Proceedings Indonesian Petroleum Association, 26th Annual Convention, p. 251-264. De Coster, G.L., 1974. The Geology of the Central and South Sumatra Basins. Proceedings Indonesian Petroleum Association 3rd Annual Convention, p. 77-110. GeoMark Research Inc., 1993. Far East Oil Study, fifteen volumes. Hadi. T. and Simbolon, B., 1976. The Carbonate Rocks of the Batu Raja Formation in its Type Locality, Batu Raja, South Sumatra: Indonesian Petroleum Association Carbonate Symposium, p. 67-78. Hall R., 1995. Plate Tectonic Reconstructions of the Indonesian Region: Proceedings Indonesian Petroleum Association, 24th Annual Convention, p. 71-84. Hutapea, O.M., 1981. The Prolific Talang Akar Formation in Raja Field, South Sumatra: Proceedings Indonesian Petroleum Association, 10th Annual Convention, p. 250-267. Hutapea, O.M., 1998. The Semoga-Kaji Discoveries: Large Stratigraphic Batu Raja Oil Fields in South Sumatra: Proceedings Indonesian Petroleum Association, 26th Annual Convention, p. 313-329. Longley, I.M., 1997. The Tectonostratigraphic Evolution of SE Asia. In Fraser, A.J., Matthews, S.J. and Murphy, R.W., eds., 1997, Petroleum Geology of Southeast Asia, Geological Society Special Publication No. 126, p. 311-339.

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Kamal, A., 1999. Hydrocarbon Potential in the Pasemah Block, a Frontier Area in South Sumatra: Proceedings Indonesian Petroleum Association, 27th Annual Convention, p. 49-63. Maulana, E., Sudarsana A. and Situmeang S., 1999. Characterization of a Fluvial Oil Reservoir in the Lemat Sandstone (Oligocene), Puyuh Field, South Sumatra Basin: Proceedings Indonesian Petroleum Association, 27th Annual Convention, p. 83-104. Pepper A. S. and Corvi P.J., 1995. Simple Kinetic Models of Petroleum Formation Part 1: Oil and Gas Generation from Kerogen. Marine and Petroluem Geology Volume 12 No. 3, p. 291-319. Pertamina-BPPKA, 1997. Petroleum Geology of Indonesian Basins: Principles Methods and applications, Volume X, South Sumatra basin, Pertamina BPPKA, 81p Rashid, H., Sosrowidjojo, I.M. and Widiarto, F.X.,1998. Musi Platform and Palembang High: A new look at the Petroleum System: Proceedings Indonesian Petroleum Association, 26th Annual Convention, p. 265-276 Sarjono, S. and Sardjito, 1989. Hydrocarbon Source Rock Indentification in the South Palembang Sub-

basin: Proceedings Indonesian Petroleum Association, 18th Annual Convention, p. 427-467. Scheifelbein, C. and Cameron, N., 1997. Sumatra/Java Oil Families from Fraser, A.J., Matthews, S.J. and Murphy, R.W., eds., 1997, Petroleum Geology of Southeast Asia, Geological Society Special Publication No. 126, p. 143-146. Suklis, J. Ames A. and Michael E., 2004. CO2 in South Sumatra – Observations and Prediction: Indonesian Petroleum Association, Proceedings, Deepwater and Frontier Exploration In Asia & Australasia Symposium, p. 269-278. Tarazona, C., Miharwatiman, J. S., Anita, A. and Caughey C., 1999. Redevelopment of Puyuh Oil Filed (South Sumatra): A Seismic Success Story: Proceedings Indonesian Petroleum Association 27th

Annual Convention, p. 65-82 Todd, S.P., Dunn, M.E. and Barwise, A.J.G., 1997. Characterising Petroleum Charge Systems in the Tertiary of SE Asia from Fraser, A.J., Matthews, S.J. and Murphy, R.W., eds., 1997, Petroleum Geology of Southeast Asia, Geological Society Special Publication No. 126, p. 49-76.

78

Figu

re 1

- A

sim

plifi

ed c

hron

ostra

tigra

phic

sche

me

for t

he S

outh

Sum

atra

bas

in.

79

Fi

gure

2 -

Key

st

ruct

ural

el

emen

ts

of

the

Sout

h Su

mat

ra

basi

n,

show

ing

Eo-O

ligoc

ene

age

(nor

thea

st-s

outh

wes

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rifts

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ss c

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re 3

- Pr

e-

and

Early

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rtiar

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sem

ent

terr

ains

of

so

uthe

rn

Sum

atra

.

80

Figu

re 5

- In

terp

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d La

te O

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(Low

er T

alan

g A

kar F

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atio

n)

pala

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phy.

Figu

re 4

- In

terp

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d La

te E

ocen

e to

Mid

dle

Olig

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e (L

emat

/Lah

at

Form

atio

ns) p

alae

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grap

hy.

81

Figu

re 7

- E

arly

Mio

cene

(Bat

u R

aja

Form

atio

n) p

alae

ogeo

grap

hy.

Fi

gure

6 -

Inte

rpre

ted

Earli

est

Mio

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(U

pper

Ta

lang

A

kar

Form

atio

n) p

alae

ogeo

grap

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82

Figu

re 9

- In

terp

rete

d pa

laeo

geog

raph

y at

m

axim

um

trans

gres

sion

w

ithin

the

ear

ly M

ioce

ne (B

atu

Raj

a Fo

rmat

ion

equi

vale

nt)

and

Mid

dle

Mio

cene

(G

umai

For

mat

ion)

and

the

exte

nt o

f ef

fect

ive

regi

onal

seal

.

Figu

re 8

- In

terp

rete

d M

iddl

e M

ioce

ne

(Gum

ai

Form

atio

n)

pala

eoge

ogra

phy

– m

axim

um re

gres

sion

.

83

Figu

re 1

1 -

A p

lot

of p

rista

ne:

phyt

ane

ratio

ver

sus

nC17

: pr

ista

ne

ratio

for

oils

in

the

Sout

h Su

mat

ra b

asin

, sh

owin

g th

e su

bdiv

isio

n of

oils

in to

gro

ups

deriv

ed fr

om te

rrig

enou

s, la

cust

rine

and

mix

ed k

erog

ens.

Figu

re 1

0 -

Int

erpr

eted

M

iddl

e-La

te

Mio

cene

(A

ir B

enak

at

Form

atio

n) p

alae

ogeo

grap

hy.

84

Figu

re 1

3 -

Dis

tribu

tion

of

disc

over

ed

oil

char

acte

r w

ithin

th

e So

uthe

rn S

umat

ra b

asin

, sho

win

g th

e sa

me

sub-

divi

sion

of

oil

grou

ps a

s in

Figu

res 1

1 an

d 12

.

Figu

re 1

2 -

A P

lot

of δ

C13

iso

tope

val

ues

for

oils

in

the

Sout

h Su

mat

ra b

asin

, sh

owin

g th

e su

bdiv

isio

n of

oils

in

to

grou

ps d

eriv

ed f

rom

ter

rigen

ous,

lacu

strin

e an

d m

ixed

ke

roge

ns.

85

Figu

re 1

5 -

An

estim

ate

of m

inim

um u

plift

and

ero

sion

from

5m

a to

pr

esen

t day

acr

oss

the

Sout

h Su

mat

ra b

asin

, bas

ed u

pon

a co

mbi

natio

n of

m

issi

ng

sect

ions

at

dr

illed

w

ell

loca

tions

and

seis

mic

inte

rpre

tatio

n.

Figu

re 1

4 -

Pre

sent

day

mat

urity

map

on

top

base

men

t.

86

Figure 16 - Lower Talang Akar Formation reservoirs – type section and interpreted environment of deposition.

Figure 17 - Exploration history of the South Sumatra basin.

87

Figu

re 1

8 - C

umul

ativ

e di

scov

ery

curv

e fo

r the

Sou

th S

umat

ra b

asin

split

by

play

and

hyd

roca

rbon

type

88

Figure 19 - Discovery history curves for: (a) Talang Akar Formation; (b) Pre-Tertiary basement; (c) Batu Raja

Formation; (d) Gumai Formation and (e) Air Benakat Formation.

89

Figure 20 - A Graphical representation of discoveries made in the South Sumatra basin between 1988 and

2005. Approximately 2.4 BBOE have been discovered during this time about 27% of the total estimated ultimate recoverable reserves for all fields discovered to date.