Reservoir Rocks
     The Oligocene Talang Akar Formation, including the Zelda and Gita sandstones, is the most important hydrocarbon reservoir in the Sunda and Asri Basins, containing more than 80% of the oil equivalent reserves in the assessment unit (Fig. 4) (Petroconsultants, 1996).

Banuwati Formation
      The Banuwati Formation, of Eocene to Oligocene age, is primarily a source rock but sandstone reservoirs are present beneath and within the source rock interval (Fig. 4).  These synrift, coarse clastic deposits represent early rift-fill alluvial and fluvial environments and later marginal-lacustrine, fluvial, deltaic, and turbidite settings (Aldrich and others, 1995; Pertamina, 1996).  The Sunda Basin Janti and Yani fans prograded into deep water where lacustrine source-rock facies were being deposited.  These fans resulted in sandstone reservoirs with 5—15% porosity in sections as much as 700 ft (212 m) thick (Pertamina, 1996).  The Janti-3 well IP at 2,450 BOPD and Yani-1 and -2 wells at 1,000 BOPD and 100 BOPD (Fig. 5) (Pertamina, 1996).  Porosity is reduced due to compaction and cementation but secondary solution porosity occurs.  Similar fan deposits might be expected in the Asri Basin and other half-grabens.

Talang Akar Formation
      The Talang Akar Formation in the Sunda/Asri area is divided into the Oligocene Zelda Member and the Miocene Gita Member (Fig. 4).  In the Asri Basin the Gita Member is coeval with the lower Batu Raja Formation.

     Stacked sandstones of braided stream, distributary, and point bar facies show an overall coarsening-upward trend from discrete fluvial channels in the lower part of the Zelda Member to amalgamated channels in the upper part (Pertamina, 1996).  The channels range from 5—25 ft (1.5-6 m) thick with 20—30% porosity and several Darcies of permeability (Pertamina, 1996).  The Zelda Member is a producing reservoir and also serves as a migration conduit for the underlying Banuwati Formation lacustrine source to overlying Batu Raja carbonate reservoirs (Aldrich and others, 1995; Pertamina, 1996).  Diagenetic kaolinite occludes pore throats at increased burial depths below 8,000 ft (2,432 m) (Pertamina, 1996).  Risma-1,2,3 produce oil from this interval and IP at 1,245-4,500 BOPD (Fig. 5) (Pertamina, 1996).

     The Gita Member in the Asri Basin is younger than the Gita in the Sunda Basin to the south, the marine transgression having occurred later toward the north.  It is the primary reservoir at Widuri and Intan fields in Asri Basin with 60% of the field’s reserves (Fig. 5) (Petroconsultants, 1996).  The Asri Basin was tested in 1988 and Widuri-1, drilled to -3,735 ft subsea (1,135 m), found 170 ft (51 m) of net oil in the upper Talang Akar Formation in 6 stacked reservoirs (Young and others, 1991).  Delineation drilling confirmed an oil field of approximately 5,000 acres (2,020 hectares) (Young and others, 1991).  Production began in 1990.  The field is a combination structural and stratigraphic trap considered a three-way fault closure (Young and others, 1996).  The fault is an Oligocene fault reactivated in early Miocene time (Young and others, 1991).  The Gita Member in the Asri Basin consists of distributary channel sands as much as 56 ft (17 m) thick in channels 2,000—4,000 ft (608-1,216 m) wide (Pertamina, 1996).  Porosity is 25—35%, permeability is 1—30 Darcies and IP is 2,000—6,000 BOPD (Pertamina, 1996).  The entire section generally fines upward and becomes increasingly marine.

Lower Batu Raja Formation
      The Lower Batu Raja carbonates were developed over a paleotopography of hills and incised valleys in a shallow shelf setting (Fig. 4) (Park and others, 1995).  A series of Batu Raja Formation reefs and lagoonal carbonates fringe pre-Tertiary igneous and volcanic islands (Wight and Hardian, 1982).  The Cinta-Rama complex of fields is located around the Cinta Arch and the Krisna and Yvonne Fields rim paleohighs (Fig. 5) (Park and others, 1995).  The Krisna oil field, discovered in 1976, is located at the Krisna high, the largest of these paleoislands (Fig. 3 and  Fig. 5) (Wight and Hardian, 1982).  The Batu Raja is absent on the crest of the Krisna high and thickens away from the high to a maximum of 250 ft (76 m) (Wight and Hardian, 1982).  Some reservoirs within this unit exceed 100 ft (30 m) in thickness and 25% average porosity (Wight and Hardian, 1982).  IPs in wells with net pay of 40—100 ft (12—30 m) were measured at 3,000—8,000 BOPD with water drive (Wight and Hardian, 1982).  The oil/water contact is 150 ft (45 m) lower on the northern side of the field (Wight and Hardian, 1982).  High secondary porosity was developed in reef facies and ordinarily tight lagoonal facies due to leaching of aragonitic skeletal material in freshwater phreatic environments as a result of repeated lowstand subaerial exposure (Wight and Hardian, 1982).  Fracturing and basement weathering zones add to permeability and the development of migration pathways (Wight and Hardian, 1982).

     In the southeastern portion of the Sunda Basin, the Lower Batu Raja Formation unconformably overlies shales and coals of the Gita Member of the Talang Akar Formation (Wicaksono and others, 1995).  The 240 ft (73 m) thick section is composed of four cycles of varying thickness that represent development in 65 ft (20 m) water depths to subaerial conditions (Wicaksono and others, 1995).  Porosity was enhanced by meteoric dissolution but subsequently infilled by calcite cement, resulting in generally poor porosity (Wicaksono and others, 1995).  Porosity ranges from 5—35% with permeability less than 10 mD and mostly less than 1 mD (Wicaksono and others, 1995). Carbonates of the Lower and Upper Batu Raja and the Gumai Limestone in this location were developed on a north plunging platform that was alternately flooded and exposed (Wicaksono and others, 1995).

Upper Batu Raja Formation 
      In the southeastern Sunda Basin the Upper Batu Raja consists of limestones more than 200 ft (61 m) thick developed during a highstand on a shallow, interior platform where water circulation was restricted (Wicaksono and others, 1995).  In Nora and Yuli wells the Upper Batu Raja consists of six 20—40 ft (6-12 m) thick sequences of wackestones changing to overlying packstones and rudstones with branching coral debris and decreasing clay content (Wicaksono and others, 1995).  The upper section of each sequence displays increased porosity.  Minor to major subaerial exposure is indicated at the top of each sequence and vadose diagenetic features appear at the top of the member at the contact with the overlying Gumai Formation (Wicaksono and others, 1995). Secondary porosity of 20—30% is a result of aragonite dissolution produced by repeated exposure and calcite cement dissolution from major exposure at the end of the early Miocene (Wicaksono and others, 1995).  Permeabilities are generally <10 mD with local areas of 100 mD (Wicaksono and others, 1995).  Initial production (IP) following acidization of Nora-1 was reported at 2,275 BOPD (Wicaksono and others, 1995).

     In the Asri Basin, the Upper Batu Raja consists of thin, shallow marine shales and poorly developed limestone and sandstone with some non-commercial shows of oil and gas.

Gumai Formation 
      The lower Miocene Gumai Formation in the Sunda Basin represents a period of transgression ending with deposition of a regional shale seal (Fig. 4) (Wicaksono and others, 1995).  The Gumai Limestone Member is present as localized carbonate buildups in the southeastern area of the basin.  It is composed of four cycles of deep to shallow marine rocks, only the oldest of which shows evidence of subsequent subaerial exposure (Wicaksono and others, 1995).  Wicaksono and others (1995) describe an extensive dissolution phase caused by flushing of the carbonate platform with meteoric water before the end of carbonate deposition. 
 

Seals
      The Gumai Shale Member is an effective regional seal in the Sunda/Asri area (Pertamina, 1996) overlying both the Batu Raja Formation and the Gumai Limestone Member in the southeastern area of the Sunda Basin (Wicaksono and others, 1995).  It is described as a deep-water transgressive claystone (Wicaksono and others, 1995) and is as much as 900 ft (274 m) thick (Pertamina, 1996).  Clayey sediments continued to be deposited during middle Miocene, and strata of this age are known as the Air Benakat claystone (Fig. 4).  The claystones seal Batu Raja reservoirs that developed on the carbonate platform and carbonate buildups that developed on and around paleohighs (Fig. 4) (Wicaksono and others, 1992).  The Krisna Field is sealed by Batu Raja shale, which drapes the carbonate reservoir and onlaps basement (Wight and Hardian, 1982).  In the Asri Basin, the Gumai is present generally as shale without the carbonate component (Wicaksono and others, 1995; Aldrich and others, 1995).  Within the basin, the shales of the Batu Raja Formation form seals (Wicaksono and others, 1992), and shales at the top of the Talang Akar Formation seal clastic reservoirs (Wight and others, 1997).  The Gumai is overlain by the Cisubuh Formation, which in some places consists of alluvial sandstone and volcanics of late Miocene-Plio-Pleistocene age and in other places is a marine shale of Miocene to Pliocene age (Fig. 4) (Pertamina, 1996).  The Cisubuh locally acts as a seal where the Gumai shale is either absent or has been transected by faults (Pertamina, 1996).