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Petroleum Systems of the Northwest Java Province, Java and Offshore Southeast Sumatra, Indonesia

by Michele G. Bishop

Open-File Report 99-50R



Reservoir Rocks
     Almost 58% of the oil and gas in the Ardjuna Basin portion of the assessment unit is from the Main and Massive Formations and 23% is from the Talang Akar Formation and Batu Raja carbonates (Gresko and others 1995).  The oldest reservoir is within a weathered or karstified basement limestone remnant of middle Eocene age (Pertamina, 1996).  This reservoir is found in KLS-1 (Fig 7) and is thought to be sourced by rocks in the downdip, deeply buried Talang Akar Formation (Pertamina, 1996).

Jatibarang Formation
     The Eocene to Oligocene synrift Jatibarang Formation is known from the north edge of the Bogor Trough across central Java, east to Bogor and north to Jakarta.  This formation is thick in subbasins, being particularly well developed in the Jatibarang subbasin.  It probably occurs within the half grabens of the Ardjuna basin, but is thin or missing on structural highs (Gresko and others, 1995).  The formation overlies pre-Tertiary basement, which is granite to the northeast and low-grade schist to the northwest (Nutt and Sirait, 1985) and is time equivalent to the Banuwati Shale of the Sunda Basin (Fig. 4) (Pertamina, 1996).  The Jatibarang strata in the Jatibarang field area were folded, faulted and eroded prior to deposition of the subsequent Talang Akar Formation (Kalan and others, 1994).  This erosional unconformity is recognized in the Ardjuna subbasin (Gresko and others, 1995).

     The Jatibarang Formation consists of andesite lavas at the base and dacite basaltic lavas interbedded with clays, sandstone, conglomerate, and pyroclastics in the upper parts (Nutt and Sirait, 1985).  Andesitic volcaniclastic flows and tuffs and reworked volcanics and basement-derived sediments have also been described (Pertamina, 1996).  Clastic facies change rapidly both vertically and laterally and are mostly fluvial in origin (Adnan and others, 1991).  The formation is more than 3,900 ft (1,200 m) thick in the onshore Jatibarang field and thins to the west (Adnan and others, 1991).  Depth to the top of the formation ranges from 9,00013,000 ft (2,7004,000 m) (Pertamina, 1996).

     Effective porosity is due to fractures with some intergranular and vessicular porosity (Nutt and Sirait, 1985).  Porosity in some of the best producing intervals is as much as 20% (Kalan and others, 1994) as measured by well logs.
Oil and gas are produced from the Jatibarang Formation in the Jatibarang field (Courteney and others, 1989) and several non-commercial hydrocarbon accumulations have been tested in the offshore area (Pertamina, 1996).

Talang Akar Formation
     The Talang Akar Formation of Oligocene age (Talangakar, Lower Cibulakan Formation) overlies the Jatibarang Formation and basement rocks. The formation is characterized as synrift to late rift continental style deposition (Pertamina, 1996).  The lower part represents continental deposition and the upper part represents an increasing marine transgression (Gresko and others, 1995; Pertamina, 1996).  The formation has also been divided into three units:  in ascending order, Talang Akar Grits, Deltaic Talang Akar, and Marine Talang Akar (Kaldi and Atkinson, 1993).  The basal unit is generally of poor reservoir quality, the deltaic interval contains both the source rock and good reservoirs, and the marine interval contains good reservoir rocks.  For example, the Talang Akar in the Jatibarang Basin area includes carbonaceous shales in the lower unit that contain TOC of 0.52.0 wt% and alternating shales and limestones in the upper unit that produce oil, gas, and condensate (Adnan and others, 1991).

     The lower Talang Akar in the Ardjuna area is time equivalent to the Zelda of the Sunda Basin (Fig. 4).  It is relatively confined to subbasin areas that had developed during deposition of the Jatibarang Formation (Gresko and others, 1995).  Paleodepositional maps published by Ponto and others (1988) illustrate an eroding Sunda Plate occupied by lake-filled grabens of the Ardjuna area, and an east to west shoreline related to a marine transgression along the Bogor Trough (Suria and others, 1994) that ran from Semarang to Cirebon and on to south of Jakarta during earliest Talang Akar deposition.  The lower Talang Akar is dominated by continental deposits, which are immature, fine- to coarse-grained, lithic-rich, and poorly sorted (Gresko and others, 1995; Pertamina, 1996).  They consist of sandstones, mudstones, minor coals, and tuffs of alluvial to deltaic origin that total an average thickness of 1,500 ft (450m) with local thickness estimated at 2,000 ft (600 m) (Gresko and others, 1995).  The sandstone reservoir is mostly poor and highly variable in quality (Gresko and others, 1995; Pertamina, 1996).  Carbonate cement reduces porosity along with authigenic kaolinite and compaction of the immature igneous and metasedimentary rock fragments that make up the clastics (Gresko and others, 1995; Pertamina, 1996).  Porosity ranges from 728% with poor permeability (Pertamina, 1996).

     The Upper Talang Akar Formation consists of nonmarine to deltaic and marginal marine to shelf sediments deposited during late Oligocene to early Miocene time (Ponto and others, 1988).  Paleodepositional maps published by Ponto and others (1988) show the migration of the shoreline toward the north to a position offshore of the modern shoreline between Semarang and Cirebon, and to a later position closer to the modern shoreline between Cirebon and Jakarta during the next stage of deposition.  Embayments extended north across the Jatibarang subbasin depositing shoreline facies and across the Ardjuna subbasin where major delta complexes and shoreline facies were deposited (Ponto and others, 1988).  The Jatibarang subbasin, Ardjuna subbasin, and the low subsiding area located offshore of the city of Jakarta, continued to be the focus of marine incursion and deposition throughout deposition of the Talang Akar Formation (Ponto and others, 1988).

     Reservoir facies that have been identified include estuarine and distributary channels, distributary mouth bars/tidal bars, and delta front bars (Kaldi and Atkinson, 1993; Suria and others, 1994; Pertamina, 1996).  The formation may be as much as 1,000 ft (300 m) thick, with interbedded shale, limestone, coal, and sandstone in an overall transgressive sequence where flooding surfaces and channel-fill have been identified using seismic data (Suria and others, 1994).

     The best reservoir quality is in 4060 ft (1218 m) thick estuarine distributary channel sandstones interpreted as incised valley fill (Pertamina, 1996).  These widely distributed, stacked sandstones have porosity of 2228% and permeability of 13 Darcies (Pertamina, 1996).  Sandstones interpreted as delta lobe switching distributary channels are 2030 ft (612 m) thick, locally cemented by kaolinite, limited in extent, and have 2228% porosity (Pertamina, 1996).

     Sandstone reservoirs deposited as distributary mouth bars are 315 ft (15 m) thick and cemented by quartz overgrowths, illite, and kaolinite (Kaldi and Atkinson, 1993; Pertamina, 1996).  Reservoir quality is considered to be good with 2125 % porosity and 20526 mD permeability (Pertamina, 1996).

     Burrowed delta front sandstones are generally poor reservoirs depending on diagenesis (Kaldi and Atkinson, 1993; Pertamina, 1996).  These 15 ft (less than 1.5 m) thick sandstones are cemented with dolomite and kaolinite resulting in porosity of 614% and permeability of 0.020.4 mD (Pertamina, 1996).  Wave dominated, delta front sand bars were subjected to early marine ferroan dolomite cementation that reduced porosity to 5% and resulted in poor quality reservoir sandstones (Pertamina, 1996).

Batu Raja Formation
     As the early Miocene marine transgression continued, and tilting of the Sunda Plate submerged sources of clastics, carbonate development increased in the marine member of the Talang Akar Formation.  This formation was eventually conformably overlain by the lower Miocene Batu Raja Formation (Lower Cibulakan Formation) (Ponto and others, 1988).

     In the Ardjuna Basin, the Talang Akar Formation consists of well-developed limestones on the Seribu platform, along fault-controlled basement highs, and around basement highs (Pertamina, 1996).  The best reservoirs are reef buildups around basement highs that were exposed during sea-level lowstands where secondary moldic porosity resulted from leaching of aragonite grains (Pertamina, 1996).  The reefs vary in thickness from 100150 ft (3045 m).  The main pay zones are from 525 ft (28 m) thick with porosities of 3136% and permeabilities of 1001,000 mD (Pertamina, 1996).  In the Jatibarang Basin area, the limestone with shale and marl interbeds of the Batu Raja Formation reaches 165 ft (50 m) in thickness and produces oil and gas with high CO2 content (Adnan and other, 1991).  These rocks contain approximately 5% of the identified oil equivalent reserves (Petroconsultants, 1996).

Upper Cibulakan Formation
      The lower to middle Miocene Upper Cibulakan Formation was deposited in inner to outer shelf and deltaic environments and is divided into the Massive, Main and Pre-Parigi units.  It is equivalent to most of the Gumai Formation and some of the Air Benkat Formation in the Sunda Basin (Fig. 4) (Butterworth and others, 1995; Reksalegora and others, 1996).  The Main and Pre-Parigi intervals are major hydrocarbon reservoirs in the Ardjuna assessment unit; sandstone reservoirs contain 58% of the known oil equivalent reserves with the majority of the reserves in the Main interval (Petroconsultants, 1996).  Limestone reservoirs within these intervals contain 10% of the known reserves (Petroconsultants, 1996).

     The Massive and Main intervals of the Upper Cibulakan Formation consist mainly of sandstones and limestones.  Deposition was on a marine shelf that occupied the area of the Ardjuna Basin east of the Seribu Platform (Fig. 2) (Purantoro and others, 1994; Reksalegora and others, 1996); marine waters transgressed from the south and clastic sediments were derived from the north.  The shoreline trended northwest to southeast offshore of the modern coastline (Purantoro and others, 1994; Pertamina, 1996).  Multiple sea-level highstands and lowstands have been recognized in this generally transgressive succession (Purantoro and others, 1994).

     The Main interval consists of approximately 2,300 ft (700 m) of interbedded shales, sandstones, siltstones, and limestones (Butterworth and others, 1995; Reksalegora and others, 1996).  Two distinct sandstone geometries that occur within this interval are discussed by Reksalegora and others (1996): (1) north to south elongate, discrete sandstone bodies, interpreted as filling lowstand erosional features; and (2) extensively distributed cleaning-up sandstones interpreted as shoreface deposits.

     The strata interpreted by Purantoro and others (1994) as lowstand sandstones and valley fill within the Main interval are quartzose and highly burrowed.  Stacked sandstones are as much as 50100 ft (165330 m) thick and are separated by as much as 200 ft (60 m) of highstand tuffaceous marine shales (Butterworth and others, 1995).  These reservoir sandstones have porosity of 1633% and permeability of 73,000 mD (Purantoro and others, 1994).  Strata interpreted as transgressive sandstones are glauconitic and highly burrowed with local calcite cement (Purantoro and others, 1994).  The porosity of these reservoir sandstones varies from 2136% and permeability ranges from 22,000 mD (Purantoro and others, 1994).  Strata interpreted as highstand sandstones are described as calcareous with siderite cement (Purantoro and others, 1994).  Reservoir quality is poor to moderate with porosity of 1230% and permeability from 0.2800 mD (Purantoro and others, 1994).

     Carbonates in the middle part of the Main interval are north- to south-oriented build-ups on basement highs and on the Seribu Platform (Pertamina, 1996).  This interval reaches 340 ft (100 m) in thickness with secondary solution porosity ranging from 1632% in pay zones that are as much as 92 ft thick (28 m) (Pertamina, 1996).

     The Pre-Parigi interval of the Upper Cibulakan Formation consists of localized carbonate bioherms formed in middle to late Miocene and distributed over a large area northeast of Jakarta (Yaman and others, 1991; Pertamina, 1996).  It is composed of partially dolomitized wackestone to grainstone that grade laterally into claystone with limestone stringers (Pertamina, 1996).  In well-developed areas these strata are as much as 700 ft (210 m) thick, and the bioherms are oriented north to south on shallow marine platforms with structural control of basement highs or prior Batu Raja carbonate buildups (Yaman an others, 1991; Carter and Hutabarat, 1994; Pertamina, 1996).  Reservoir quality is excellent, with preserved porosity averaging 30% and permeability of 2 Darcies (Yaman and others, 1991).  The reservoir gas, 98% methane, is dry; (Yaman and others, 1991).

Parigi Formation
     The late Miocene Parigi Formation developed on structurally stable shallow marine platforms as bioherms associated with paleohighs but not necessarily basement highs (Fig. 4) (Yaman and others, 1991).  It is widespread, being distributed onshore and offshore across an area overlapping the eastern portion of Pre-Parigi distribution and continuing to the east (Yaman and others, 1991).  Offshore, north- to south-oriented Parigi bioherms are more than 400 ft (120 m) thick (Yaman and others, 1991; Pertamina, 1996).  Separated from this trend, to the south in both onshore and offshore areas, are northeast- to southwest-oriented Parigi bioherms that are as much as 1,500 ft (450 m) thick (Yaman and others, 1991; Pertamina, 1996).  The orientation of the bioherms is interpreted to be the result of a combination of paleogeographic features and paleocurrent directions; the separation of the two trends may have been caused by a deeper water reentrant from the east (Yaman and others, 1991).  Bioherms in the northern trend are composed of skeletal-foraminiferal packstone with little coral and generally no framework whereas bioherms in the southern trend are composed of coral-algal reefs (Yaman and others, 1991).  In the Jatibarang Basin area, the Parigi consists of buildups composed mostly of reef limestone that reach a thickness of approximately 490 ft (150 m) (Adnan and others, 1991).

     Reservoir quality varies from tight to very good, due to cementation by calcite and development of secondary porosity (Yaman and others, 1991).  Porosity is as much as 30% and permeability 2 Darcies (Yaman and others, 1991).  This reservoir has tested from 14.5 million cubic feet of gas per day (MMCFGPD) to 58.94 MMCFGPD (Pertamina, 1996).  Oil is produced in wells JTB-43 and -45 (Adnan and others, 1991).

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U. S. Geological Survey Open-File Report 99-50R