TRAP TYPES
Northwest to southeast trending anticlines were the first traps explored and remain the most important traps in the South Sumatra basin (van Bemmelen, 1949). Oil and gas reserves found in anticlines total 3.1 BBOE ultimate recoverable reserves (Petroconsultants, 1996). These fields have primarily sandstone reservoirs with some limestones and calcareous sandstones and include every producing formation in the basin (Petroconsultants, 1996). The anticlines formed as a result of compression that began as early as the Miocene but was most pronounced between 2—3 Ma (Fig. 6) (Courteney and others, 1990). Stratigraphic pinch-outs and carbonate buildups locally combine with folds and anticlines to enhance the effectiveness of the primary trap type. Recoverable reserves of 178 MMBOE are found in bioherms and carbonate buildup type traps and 688 MMBOE in fault traps (Petroconsultants, 1996). Drape, facies-change, and stratigraphic traps are also important and may be attractive future targets.

RESERVOIR ROCK
Basement Rocks
Uplifted areas and paleohighs of Mesozoic and Eocene fractured and weathered basement granite and quartzite are effective reservoirs, with up to 7% porosity, in ten fields in South Sumatra with gas reserves totaling 106 MMBOE ultimate recoverable reserves (Sardjito and others, 1991; Petroconsultants, 1996).

Lahat (Lemat, Old Lemat, Young Lemat) Formation
The Eocene to Oligocene Lahat Formation (Fig. 4) is composed of synrift deposits that are as much as 1,070 m thick. Although locally absent, this formation, is in most locations, more than 760 m thick (Hutchinson, 1996). The formation was deposited in continental, lacustrine, and brackish lacustrine depositional settings (Hutchinson, 1996). This reservoir accounts for nearly 88 MMBOE of ultimate recoverable reserves (Petroconsultants, 1996).

The Kikim Tuffs, also known as Old Lemat, are tuffaceous sandstones, conglomerates, breccias, and clays, of locally derived provenance, deposited in faulted and topographic lows (Hutchinson, 1996). The Kikim is interpreted to by Late Cretaceous to Paleocene in age and occurs in outcrop and at depth in the southern region (Hutchinson, 1996).

The oldest facies of the Young Lemat is granite wash overlain by coarse clastic deposits that consist of sandstones and breccias with abundant rock fragments, claystones, coals, and tuffs (Hutchinson, 1996).

The Benakat Member is a grey to brown shale with tuffaceous shale, siltstone, sandstone, coal, carbonate stringers and glauconitic sandstones that occurs in the deep portion of the half-graben basins (Hutchinson, 1996). This member was deposited in fresh to brackish water lakes and conformably overlies the coarse clastics of the lower Lemat Formation (Hutchinson, 1996).

Talang Akar Formation
The late Oligocene lower Talang Akar Formation is also referred to as the Gritsand Member and the Oligocene to early Miocene upper Talang Akar Formation as the Transition Member (Sitompul and others, 1992; Tamtomo and others, 1997). The Talang Akar Formation is as much as 610 m thick (Hutchinson, 1996). It is a late synrift to post-rift formation that is thick where the underlying Lahat Formation is thickest (Fig. 3). The Talang Akar Formation unconformably overlies the Lahat Formation. It onlaps the Lahat and the basement, extending farther outside of the depositional basins than the depositional limits of the Lahat Formation (Hutchinson, 1996). This reservoir consists of quartzose sandstones, siltstones, and shales deposited in a delta plain setting that changed basinward, generally to the south and west, into marginal marine sandstones and shales (Adiwidjaja and de Coster, 1973; Hutchinson, 1996; Eko Widianto and Nanang Muksin, 1989). Specific depositional environments that have been identified include open marine, nearshore, delta plain, delta, distributary channel, fluvial, and beach (Hutapea, 1981). Talang Akar Formation sandstones, which were deposited during marine transgressions and regressions, form important stratigraphic traps (Tamtomo and others, 1997). These shoreline sands are generally aligned east to west, are supplied with sediment from the Sunda Shelf to the north and the Palembang High (Lampung High) to the east, can be laterally restricted, and thicken and thin in response to topography at the time of deposition (Adiwidjaja and de Coster, 1973; Hamilton, 1979; Hutapea, 1981; Sitompul and others, 1992). Other shoreline sandstones that surround basement highs are productive reservoirs for several fields (Tamtomo and others, 1997). Here the quality of the reservoir depends on the type of basement rock eroded to provide the clastics.

The Talang Akar Formation reservoir accounts for more than 75% of the cumulative oil production in South Sumatra (Tamtomo and others, 1997). Approximately 2 BBOE ultimate recoverable reserves have been found in Talang Akar reservoirs (Petroconsultants, 1996). Porosity of this reservoir rock ranges from 15—30 % and permeability is as much as 5 Darcies (Tamtomo and others, 1997; Petroconsultants, 1996). Porosity of the Gritsand Member is primarily secondary and averages 25% (Sitompul and others, 1992). Porosity of the Transitional Member is also primarily secondary and caused by the dissolution of grains and detrital clays. This cleaner and more mature sandstone has 25% average porosity (Sitompul and others, 1992). Clays in both members include smectite, illite, and abundant kaolinite (Sitompul and others, 1992).

Batu Raja Limestone
The early Miocene Batu Raja Limestone is also known as the Basal Telisa Limestone (Hutchinson, 1996). The formation consists of widespread platform carbonates, 20—75 m thick, with additional carbonate buildups and reefs, from 60—120 m thick (Hutchinson, 1996; Hartanto and others, 1991). The Basal Telisa is shale and calcareous shale deposited in deeper water as the carbonates were being developed on the platforms and highs (Courteney and others 1990). At outcrop the Batu Raja is 520 m thick in the Garba Mountains area of the Barisan Mountains (Fig. 2) (Hutchinson, 1996).

Discoveries in Batu Raja limestone and sandy limestone total over 1 BBOE ultimate recoverable reserves, with gas comprising just over half of that amount (Petroconsultants, 1996). Oil gravity ranges from 26—61° API (Petroconsultants, 1996). Reservoir porosity ranges from 18—38% and reservoir permeability is as much as 1 Darcy (Petroconsultants, 1996). Porosity has been enhanced in the upper parts of the formation due to subaerial exposure late in the early Miocene, at approximately 17.5 Ma, and also because of only partially cemented fractures (Courteney and others, 1990; Hartanto and others, 1991; Sitompul and others, 1992).

Gumai Formation
The Oligocene to middle Miocene Gumai Formation, also known as the Telisa Formation, is composed of fossiliferous marine shales with thin, glauconitic limestones that represent a rapid, widespread maximum transgression (Fig. 4) (Hartanto and others, 1991; Hutchinson, 1996). The transgression was toward the northeast, and water depths were shallow in the northeast and bathyal in the southwest (Hamilton, 1979). Fine-grained sandstones and siltstones occur on the basin margins (Hutchinson, 1996). The thickness of the Gumai Formation varies and is as much as 2,700 m thick in basins. The formation thins at basin margins and across highs (Hartanto and others, 1991; Hutchinson, 1996).

The Gumai Formation is the regional seal for the Batu Raja Limestone in South Sumatra but also contains some reservoir intervals. These carbonates contain 130 MMBOE ultimate recoverable reserves (Petroconsultants, 1996). These reserves average 33—52° API gravity and are found primarily in shoreline and shallow marine sandstones with 20% porosity, however, Hartanto and others (1991) have used well logs to identify turbidites and suggest that these sands could be exploration targets in the basins. Thee turbidites suggest that a rapid drop in sea level occurred at the end of Gumai deposition in middle Miocene time (Hartanto and others, 1991).

Air Benakat Formation
The middle Miocene Air Benakat Formation, also known as the Lower Palembang Formation, was deposited during the regression that ended deposition of the Gumai Shale. The Air Benakat Formation changes upward from deep marine to shallow marine conditions. Marine glauconitic clays decrease in frequency and marine sands increase (Hartanto and others, 1991). The formation ranges from 1,000—1,500 m thick (Hutchinson, 1996). Coal beds mark the upper contact with the overlying Muara Enim Formation (Hutchinson, 1996). Ultimate recoverable reserves discovered in shallow marine and deltaic sandstone reservoirs within the Air Benakat Formation total 647 MMBOE (Petroconsultants, 1996). The average porosity of the sandstone is 25%. The reservoirs contain oil with average 47° API gravity and some gas (Petroconsultants, 1996).

Muara Enim Formation
The late Miocene to Pliocene Muara Enim Formation, also known as the Middle Palembang Formation, was deposited as shallow marine to continental sands, muds, and coals. The formation thins to the north from a maximum of 750 m in the south (Fig. 4) (Hutchinson, 1996). Oil reserves of 179 MMBOE ultimate recoverable are located in Muara Enim sandstone reservoirs with 30% average porosity (Petroconsultants, 1996). Uplift of the Barisan Mountains provided source terrains for clastics from the south and southwest during deposition of the Muara Enim Formation (Hamilton, 1979).

Kasi Tuff
Continental tuffaceous sands, clays, gravels, and thin coal beds of the Kasi Tuff, also known as the Upper Palembang Formation, are found in valleys and synclines formed during deformation of the Barisan Mountains. These sediments are derived primarily from these mountains (Courteney and others, 1990; Hutchinson, 1996).

SEAL ROCK
The Gumai Formation represents the maximum highstand transgression following development of Batu Raja carbonates (Fig. 3 and 4) (Hartanto and others, 1991). Shales of this regional formation seal carbonate reservoirs and locally seal a series of stacked sandstone reservoirs of the Talang Akar Formation (Martadinata and Wright, 1984; Hartanto and others, 1991). Hydrocarbons that are found above the regional seal either have migrated there due to faults that broke the seal during the compression phase or were generated by the Gumai Formation shales in local areas where this formation might be mature. Intraformational seals within the Talang Akar consist of shallow marine and overbank shales that are important seals that compartmentalize the sandstones (Courteney and others, 1990).

UNDISCOVERED PETROLEUM BY ASSESSMENT UNIT
One assessment unit, the South Sumatra assessment unit (38280101), is recognized in the Lahat/Talang Akar-Cenozoic petroleum system (Fig. 1). The primary exploration targets in the South Sumatra Basin have been anticlines and carbonate buildups. This play is fairly mature. Although the basin as a whole has had a similar depositional history, there is a great deal of local variation within and around the half-grabens and half-graben complexes that could yield many targets for exploration. Future exploration targets would include smaller traps associated with more subtitle structures, stratigraphic traps associated with lowstand fan deposits, shoreline onlap onto basement highs, and synrift clastic fluvial, deltaic, and possibly deep-water deposits deeper in the half-grabens. Basin inversion could form traps in some of these synrift deposits. Due to the complex and varied nature of the province numerous prospects may remain to be explored.