Petroleum exploration in South Sumatra has been primarily guided by surface anticlines, sometimes found by digging trenches (in the absence of outcrop) to map dips (Ford, 1985). Therefore the early distribution of fields follows the trend of the anticlines. The same compression that formed the inverted rift-basin anticlines reversed the motion of many normal faults resulting in monoclines and anticlines over keystone type fault blocks (Moulds, 1989). These structures, as well as stratigraphic pinchouts and onlaps trapped hydrocarbons that migrated from mature source rocks in adjacent lows (Courteney and others, 1990). The earliest fields were discovered in shallow Air Benakat and Muara Enim reservoirs and located near the Gumai and Barisan mountain fronts (Moulds, 1989; Ford, 1985; Zeliff and others, 1985). Later discoveries occurred further away from the mountains in older and deeper reservoirs (Ford, 1985).

Fields in the carbonate reservoirs of the Oligocene to Miocene Batu Raja Limestone (Fig. 4) are also aligned generally northwest to southeast since these buildups are located on basement highs or fault-block relief associated with the rifted basins (Zeliff and others, 1985).

Much of the oil in the basin is paraffinic and low in sulfur content (Petroconsultants, 1996; ten Haven and Schiefelbein, 1995). Both lacustrine and terrigenous facies on the margins of lacustrine environments have been interpreted as sources for the oils in the South Sumatra Basin. An additional carbonate source rock is suggested by one oil sample (ten Haven and Schiefelbein, 1995). Gravity of oil and condensate produced from sandstone reservoirs is reported to range from 21—55° API with gas to oil ratios (GOR) ranging from less than one hundred to more than 55,000 (Petroconsultants, 1996). CO ₂ content of the natural gas can be as much as 90 % (Courteney and others, 1990). Batu Raja Limestone reservoirs contain oils and condensates with gravity from 27—58° API and GOR ranging from approximately 200 to more than 88,000 (Petroconsultants, 1996). Oil gravity, from more than 30 Talang Akar sandstone reservoirs in the Raja Field alone, ranges from 15° to 40° API (Hutapea, 1981). Oils analyzed by GeoMark from the South Sumatra Basin are plotted with oils from the Northwest Java area (Fig. 5). Oil samples from the adjoining Northwest Java Basin Province separate into two geochemical clusters, 1) lacustrine, 2) coaly and mixed regions, that agree with the literature on the origins of oils in this region (Bishop, 2000 figure 6). By comparison, South Sumatra Basin oil samples show data points transitional between the terrestrial coal/coaly shale and lacustrine clusters of Northwest Java (Fig. 5).

Hydrocarbon migration occured along carrier beds updip from the deep rift basins, where the source rocks are mature, and then along faults to overlying anticlines that form the majority of traps (Sarjono and Sardjito, 1989). Migration may have begun in late middle Miocene in the South Palembang sub-basin (Fig. 2 and Fig. 6) (Sarjono and Sardjito, 1989). Fault breaches in the Gumai Formation regional seal, allowed hydrocarbons to migrate into middle and late Miocene reservoirs (Sarjono and Sardjito, 1989).

SOURCE ROCK
Hydrocarbons in South Sumatra Province, Lahat/Talang Akar-Cenozoic (382801) TPS (Fig. 6), are derived from both lacustrine source rocks of the Lahat Formation and terrestrial coal and coaly shale source rocks of the Talang Akar Formation (Sarjono and Sardjito, 1989; Todd and others, 1997; Katz, 1991; Sladen, 1997; Suseno and others, 1992; Schiefelbein and others, 1997; Schiefelbein and Cameron, 1997; Sosrowidjojo and others, 1994). The lacustrine source rocks were deposited in a complex of half-grabens whereas the subsequent coal and coaly shales were deposited in and extended beyond the limits of the half-grabens (Fig. 3). The Batu Raja Limestone and the Gumai Formation shales may also be mature and have generated hydrocarbons in local areas (Sarjono and Sardjito, 1989).

The middle to late Eocene through early Oligocene Lahat or Lemat Formation, in the south Palembang area, includes the Benakat Shale with oil prone Type I and II kerogen and gas prone Type III kerogen depending on its locale (Suseno and others, 1992). The Benakat Shale Member is found in the deep portions of the basins and consists of grey-brown shales with tuffaceous shale, siltstones, sandstones, and coals (Hutchinson, 1996). The depositional environment is described by Hutchinson (1996) as brackish water. Total organic carbon (TOC) content of the Lahat Formation varies from 1.7—8.5 wt% (Sarjono and Sardjito, 1989) and locally as much as 16.0 wt% (Suseno and others, 1992). Hydrocarbon index (HI) values are 130—290 mg hydrocarbon (HC)/g TOC (Suseno and others, 1992). Thermal maturity of the Lahat Formation ranges from 0.64—1.40% R_o (Suseno and others, 1992). The Lahat Formation generated oil in most locations and oil and gas where more deeply buried (Sarjono and Sardjito, 1989).

Organic material in the late Eocene through middle Miocene Talang Akar Formation contains oil- and gas-prone Type I, II and III kerogen, identical to the Lahat Formation, and very similar to the Talang Akar source rocks of the Northwest Java Ardjuna area (Suseno and others, 1992). The Gritsand Member of the Talang Akar is described by Cole and Crittenden (1997) as deposited in intramontane lacustrine, lowland marine-influenced lacustrine, and fluvial-lacustrine-lagoonal settings and contains oil-prone Type I kerogen with the addition of Type II due to local facies changes. The Talang Akar Formation has good to very good source rock potential with a TOC range of 1.5—8 wt% in areas of the South Palembang sub-basin (Sarjono and Sardjito, 1989) ranging locally up to 50.0 wt% (Suseno and others, 1992). The range of HI is 150—310 mg hydrocarbon (HC)/g TOC (Suseno and others, 1992). Thermal maturity of the upper Talang Akar in the South Palembang sub-basin ranges from 0.54—0.60 R_o and from 0.82—1.30 R_o in the lower Talang Akar (Suseno and others, 1992).

The general temperature gradient in South Sumatra is 49° Ckm^-1 (Hutchinson, 1996). This gradient is lower than in Central Sumatra and consequently the oil window is deeper (Hutchinson, 1996).

The Oligocene to Miocene Batu Raja Limestone and the Oligocene to Miocene Gumai Formation are mature to early mature for thermal gas generation in some of the deep basins and therefore may contribute gas to the petroleum system (Sarjono and Sardjito, 1989). Gas at MBU-1 field has been attributed to mature Gumai Shale source rocks in the adjacent low (Fig. 2) (Sarjono and Sardjito, 1989).

In the Bandar Jaya Basin area (Fig. 2) several grabens contain rich Lahat source rocks (Williams and others, 1995). The lacustrine source rocks are oil prone Type I and II kerogen and the coaly lake margin and deltaic source rocks contain Type III kerogen (Williams and others, 1995). Several wells have tested reservoirs and source rocks in some of these half-grabens, encountering gas and oil shows but without commercial success (Petroconsultants, 1996). Analyses of these source rocks indicate that they are just entering the oil window (Williams and others, 1995).