Petroleum Occurrence
     The Sunda/Asri assessment unit consists of two offshore basins, the Sunda basin that includes several half grabens and the Asri basin that is made up of one half-graben (Fig. 1,  Fig. 2 and  Fig. 5).  These basins have been combined in petroleum system 382401 because of the lacustrine nature of the source rocks in both, although each basin has a somewhat different structural style, depositional history, and age.  The concession area that includes these basins is just over 11,000 km2 (Wight and others, 1997) and water depth is from 70—90 ft (21—27 m) (Wicaksono and others 1992).  As of 1997, cumulative production from these two areas was 800 MMBO at an average rate of 90,000 barrels of oil per day (BOPD) (Wight and others, 1997).

     Eleven dry holes were drilled in the Asri Basin before the Widuri-1 well, drilled in 1988, encountered a net oil column of 170 ft (51 m) in the upper Talang Akar Formation sandstone at -3,735 ft (-1135 m) subsea (Young and others 1991).  Production of high pour point, low sulfur, 31° API gravity oil from Widuri began in 1990 (Fig. 5) (Young and others, 1991).  Reserves were estimated in 1997 at 260 MMBO from six sandstone reservoirs (Wight and others, 1997).

     The Sunda Basin has been in production for 25 years with approximately 74 % of the oil of the Sunda Basin produced from Oligocene late synrift sandstone reservoirs of the Talang Akar Formation (Fig. 4).  Approximately a quarter of the hydrocarbons, 26 %, are produced from Batu Raja reef carbonate reservoirs (Petroconsultants, 1996; Wight and others, 1997).  The oils are 22—38° API gravity, low sulfur, low asphaltenes, high wax, paraffinic crudes (Wicaksono and others, 1992; Pertamina, 1996; Noble and others, 1997).  The oils show pronounced similarities in a cross plot of stable carbon isotope composition of the saturate hydrocarbon fraction (13Cs) plotted against the pristine to phytane ratio (Pr/Ph) and source rocks are interpreted to be predominantly lacustrine shales (Fig. 6) (GeoMark, 1998).  Variations occur that are attributed to lateral facies changes in the amount of terrestrial material in the source rock (Wicaksono and others, 1995).  Gas found in middle Miocene and older reservoirs is associated with oil or is derived from oil (Noble and others, 1997).  Carbon dioxide content is generally below 5% (Noble and others, 1997).

     Vertical migration is suggested as the mechanism to fill reservoirs over the limited areal extent of mature source rock, and both vertical and lateral migration are probably involved in the sourcing of reservoirs located updip and away from the areas of mature source rock (Wicaksono and others, 1992).  Lateral migration took place through several zones of sandstone and weathered basement conduits.  The pre-Tertiary basement rocks at Ambar (Fig. 5) form a hydrocarbon reservoir as much as 200 ft (60 m) thick (Pertamina, 1996).  This zone of weathered basement rocks is also thought to provide an important path for hydrocarbons generated in the half-graben to migrate updip into younger reservoirs (Pertamina, 1996).

     The Widuri Field in the Asri Basin (Fig. 5) is bounded by a fault that trapped petroleum, generated by mature Banuwati source rock in the deep half graben, migrating up-dip along the shoaling margin of the Asri half graben.  The occurrence of this field indicates lateral migration of over 18 miles (30 km) (Wicaksono and others, 1992).

     Considerable lateral migration is also suggested in the Sunda Basin by the locations of numerous accumulations away from known locations of mature source rock (Fig. 5).  In the southeastern part of this basin there is oil production from shallow marine and carbonate platform limestones in the lower Miocene Batu Raja Formation and Gumai Formation (Wicaksono and others, 1995).  Although seven fields in this combined carbonate play have produced 250 MMBO, poor reservoir quality, limited trap size, and low recovery factors have limited the success of discoveries in this play (Wicaksono and others, 1995).  Fields that produce oil and gas from carbonate reservoirs in the Sunda Basin are distributed as far north as Dita Field and are generally located on the western and southern edges of the Sunda Basin (Park and others, 1995).  Migration from the mature Banuwati shales was initially upward out of the main half-graben along faults and laterally as much as 28 miles (45 km) into these carbonate reservoir traps (Wicaksono and others, 1995).

Source Rock and Maturation
     Late Eocene to early Oligocene Banuwati lacustrine shale in the Sunda and Asri Basins was deposited in anoxic, lake environments (Fig. 4) (Wicaksono and others, 1992; Pertamina, 1996; Noble and others, 1997).  This shale represents the greatest extent of the lakes late in the period of Banuwati Formation deposition. These lakes occupied several contemporaneous half-graben and connected half-graben systems throughout the province.  Two eastward tilted and one westward tilted half-grabens were depocenters for the Banuwati Shale in the Sunda Basin where basement is 12,000—16,000 ft (3,648—4,864 m) deep (Wicaksono and others, 1992).  One eastward tilted half-graben was the site of deposition of the Banuwati Shale in the Asri Basin (Wicaksono and others, 1995).  This dark brown to black shale is more than 400 ft (121 m) thick in the deepest part of the Sunda Basin half-graben, but thins to 100 ft (30 m) at the shoaling margin (Wicaksono and others, 1992; Pertamina, 1996).  This shale is an oil-prone (Type I) source rock and seal for intraformational sandstones (Wicaksono and others, 1992).  The lacustrine source-rock shales have total organic carbon (TOC) values of 1.87—8.0 wt%, and hydrogen index (HI) of 573—637 milligrams hydrocarbon/gram TOC (mg HC/g) (Pertamina, 1996).  Modeling suggests that these oil-prone source rocks reached the main phase of oil generation when buried at depths between 9,500 ft (2,888 m) (Wicaksono and others, 1992) and 11,800 ft (3,587 m) (Pertamina, 1996) from 15—8 MA.  Discoveries of 1.2 billion barrels of oil (BBO) recoverable and 65 BCFG are attributed to this source rock (Aldrich and others, 1995).

     Coals and overbank shales and shallow lacustrine shales of the Zelda and Gita Members of the Talang Akar Formation would be good source rocks if mature.  The Gita coals are thick with TOC values of 3.7—25 wt% (Pertamina, 1996).  Marine shales and marls of the Batu Raja and Gumai Formations might generate hydrocarbons if buried deeply enough to be mature (Pertamina, 1996).

Traps
      Five of the six fields described by Petroconsultants (1996) in the Asri Basin are trapped in anticlines; the largest field, Widuri, is described as a fault trap.  More than 55% of the fields in the Sunda Basin are fault or structural traps (Petroconsultants, 1996).  Almost 63% of the oil equivalent reserves in the assessment unit are trapped by faults, fault blocks, or other structural settings, whereas more than 36% of the reserves are trapped in anticlines (Petroconsultants, 1996).  Carbonate reefs and buildups account for the remainder, which is mainly gas (Petroconsultants, 1996).