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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



Source Rock and Maturation
     The major source rocks in the Ardjuna assessment unit are deltaic carbonaceous shales and coals in the upper Talang Akar Formation of late Oligocene age that were deposited in a late synrift to post-rift tectonic setting (Noble and others, 1997; Gordon, 1985; Nugrahanto and Noble, 1997; Haposan and others, 1997; Gresko and others, 1995; Ponto and others, 1988).  This source rock is type II and III and is oil- and gas-prone with TOC of 4070 wt% in the coals and 0.59 wt% in the shales (Ponto and others, 1988), and HI of 200400.  An estimate of expelled hydrocarbon from Talang Akar source rocks is 64 billion barrels (Ponto and others, 1988).  Minor source rocks are represented by lacustrine strata of the lower Talang Akar Formation (Noble and others, 1997; Nugrahanto and Noble, 1997; Haposan and others, 1997) and possibly from the Jatibarang Formation in the Jatibarang subbasin (Fig. 6) (Gresko and others, 1995; Noble and others, 1997).  Hydrocarbon generation may have begun as early as 25 Ma for lower units of the Talang Akar and as late as 1 Ma for later units (Fig. 7) (Pertamina, 1996).

     Several grabens with thick sections of Talang Akar Formation are considered to contain mature source rocks (Noble and others, 1997).  These subbasins are combined into one petroleum system comprised of coaly, oil-prone source rock, although differences in the oils migrated from these source areas may allow separation into several high-resolution petroleum systems (Noble and others, 1997).  The westernmost area of mature source rock is Ciputat where the Talang Akar Formation is thin and mostly marine influenced (Fig. 3) (Noble and others, 1997).  Oils in fields to the west and north have been traced to this source rock (Noble and others, 1997).  The Kepuh and Pasir Bungur areas of mature source rock contain thick coals of the Talang Akar Formation (Fig. 8) (Noble and others, 1997).  Hydrocarbons migrating from these mature areas charge clastic reservoirs of the Talang Akar Formation and carbonate reservoirs of the Mid-Main in both onshore and offshore fields to the north (Fig. 3 and Fig. 4) (Noble and others, 1997).  Migration of oil from the Cipunegara area of mature Talang Akar source rocks is also primarily to the north to both onshore and offshore fields (Fig. 3) (Noble and others, 1997).

       The areas of mature source rock that are located offshore include the South and Central Ardjuna subbasins (Fig. 3 and Fig. 8).  Seismic data across the Central subbasin indicate fault throws of greater than 3,000 ft (912 m) at depth and 200 ft (60 m) in shallow horizons (Carter and Hutabarat, 1994).  More than 100 ft (30 m) of coal source rock occurs in the South subbasin and sources Main and Massive clastic reservoirs and some Talang Akar clastic reservoirs in surrounding fields (Noble and others, 1997).  Hydrocarbons generated in the Central subbasin migrate to fields to the south and may have charged as yet undiscovered accumulations to the north (Noble and others, 1997).

     Transgression during the early Miocene continued as subsidence in the individual and connected basins decreased.  Carbonates of the Batu Raja Formation were developed over the Talang Akar source rocks on a shallow carbonate platform and reefs developed on paleohighs (Fig. 4).  Mixed clastic and carbonate deposits overlie the Upper Cibulakan Group (Haposan and others, 1997).  Biostromal and biohermal limestones of the Parigi Formation were developed across the entire province, followed by deposition of claystone with sandstone, conglomerate, and limestone of the Cisubuh Formation (Haposan and others, 1997).  The late Miocene to Plio-Pleistocene Cisubuh Formation coarsens and shallows up representing regression to the south with sediment input from the east and west (Pertamina, 1996).

      Anticlines are the most numerous traps that have been drilled to date in the Ardjuna assessment unit, making up almost 65% of the fields and containing almost 50% of the oil equivalent reserves (Petroconsultants, 1996).  The productive reservoirs in most of these anticlines are sandstones of the Cibulakan Formation although some carbonate reservoirs are involved (Petroconsultants, 1996).  Fault blocks and other structural traps account for almost 40% of the equivalent reserves in the unit (Petroconsultants, 1996).

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