The Central Sumatra Basin is bound to the southwest by the Barisan Mountains geanticlinal uplift and volcanic arc, to the north by the Asahan arch, to the southeast by the Tigapuluh high, and to the east by the Sunda craton (Heidrick and Aulia, 1993).
The Central Sumatra basin represents one of a series of present day, back-arc basins which are present along the eastern regions of Sumatra island and West Java. These basins represent the most prolific, hydrocarbon-productive, Tertiary basins in Indonesia with exception of the Mahakam Delta of East Kalimantan. In the Central Sumatra Basin, oil and gas are trapped in sandstones of Miocene and Pliocene ages in mostly structural closures, which were created during the latest structural episode between the Late Miocene and Pleistocene. Geochemical analyses reveal that the hydrocarbons were generated from organic-rich shales which were deposited in a lacustrine environment extensional rift systems during Eocene-Oligocene times (Williams et al., 1985 in Soeryowibowo et al., 1999).
The Paleogene sediments were deposited during the development of an extensional phase (F1) that created a graben system oriented generally north-south. There is no precise dating on the initial formation of the graben but regional correlations would suggest that it began during Eocene times (Heidrick and Aulia, 1993).
Fluvial/lacustrine-related sediments characterize the Paleogen stratigraphy of the Central Sumatra Basin. Lithostratigraphically, they are recognized as, from older to younger, the Lower Red Bed, Brown Shale and Upper Red Bed formations. The Lower Red Bed Formation consists predominantly of fluvial sandstones, siltstones and claystones and alluvial fan conglomerates, the latter of which were developed along graben-bounding faults (Yarmanto et al., 1995 in Soeryowibowo et al., 1999).
The Brown Shale Formation has been described as a lacustrine deposit. It consists of dark brown, organic-rich shales to very fine-grained sandstones. The Upper Red Bed Formation comprises coarse to fine grained sandstone, interbedded red, mottled siltstones and claystones (Soeryowibowo et al., 1999).
The development of the extensional rift system waned during the Late Oligocene and was followed by regional transgression in the Early Miocene, depositing thick, marine sandstones and shales that filled in the grabens and covered the basement platforms. The contact between the synrift and the unconformity along hinge margines and is locally refered to as sequence boundary 25.5 Ma. Towards to the graben centers this contact grades into a paraconformity (Soeryowibowo et al., 1999).
A right-lateral wrench system developed between F1 (Eo-Oligocene) and F2 (Lower to Middle Miocene) followed by a compressional phase (F3) Middle Miocene to present (Heidrick and Aulia, 1993). Stratigraphically, commencing from the Early Miocene the entire Central Sumatra Basin is covered by marine, clastic deposits consisting of interbedded sandstones, siltstones and claystones (Mertosono and Nayoan, 1974). Tectonostratigraphically, the Neogene is divisible into two stages, i.e., Sihapas and Petani groups (Yarmanto et al., 1995 in Soeryowibowo et al., 1999). The Sihapas Group has been the target for most hydrocarbon exploration activities. It contains over ninety percent of the oil and gas reserves in the Central Sumatra Basin (Soeryowibowo et al., 1999).
In general, the synrift is characterized by sub parallel seismic reflector dips towards the border faults. The internal reflectors often show transparent, discontinuous character in deeper portions of the graben and do not indicate a sharp change of reflection from basement to the synrift section. Mapping of the basement was, therefore, accomplished with great difficulty. Towards the upper portion of the graben fill strong, subparallel reflectors were recognized. The most continuous, strong amplitude reflector was mapped as a horizon that is equivalent to the Brown Shale event of Late Oligocene age, in the South Aman Graben (Soeryowibowo, 1999).
Daly et al. (1991), on the other hand, thought that Indonesian, back-arc basins were generated due to subduction rollback. These basins were created during the Middle to Late Eocene (40 Ma), which is coincident with collision between the Indian subcontinent and the Eurasian margin, as indicated by an abrupt decreasing in India’s northward rate of movement. Heidrick and Aulia (1993) suggested similar timing and kinematics for the formation of the Bengkalis Trough. They suggested that geometric and kinematic considerations of the left-stepping, graben doglegs indicate that the minimum horizontal principal stress (S3) was oriented predominantly E-W during the rift formation (Soeryowibowo, 1999).
Eo-Oligocene grabens in western Indonesia play a major role in the petroleum systems by providing world-class-quality source rocks (Davies, 1984 in Soeryowibowo et al., 1999). The source rocks were mainly deposited in lacustrine environment during the syn-rift development.
In the Central Sumatra Basin, several reservoir rocks had been deposited since Oligocene to Middle Miocene. The most prolific reservoirs are sands in the Menggala (mostly fluvial sand) and Bekasap (fluvial to marine/deltaic sand) formations. The Sihapas Group mineralogy composed of quartz grain with lesser amount of feldspars. Other reservoirs such as Bangko sands, Pematang sands and fractured basement occasionally also produce hydrocarbon.
Extensional tectonics, compressive tectonics, strike-slip, and inversion faulting since 28 Ma to the present have formed effective traps in the basin, while the last 5 Ma tectonic was the most active structuring for the trap formation.
Three different types of structural closures trap significant quantities of hydrocarbons within the Central Sumatra Basin including: 1) high-to moderate-relief double-plunging F3 anticlinal culminations bearing N10-25oW parallel to compressional oblique-slip faults; 2) high-relief F0 anticlinal folds juxtaposed along F3 restraining fault bends; and 3) low-relief F2/F3 pop-up structures and minor footwall uplift closures within or flanking N-NNE-trending belts of transtensional deformation.
The Bangko and Telisa Formations consists of transgresive marine shale, which form effective top seals. Locally, the interstratified calcareous sands within Telisa shale also produce hydrocarbon. In deeper parts of the Pematang trough the Brown Shale also become an effective seal.
Hydrocarbon generation, migration and accumulation
The process of hydrocarbon generation, migration and accumulation have commenced since 26 Ma and continued to present day. The maximum hydrocarbon generation in the deeper trough occurred at about 11 Ma to 3 Ma. In the shallower part of the basin the peak generation is younger, post dating the 5 Ma structural formation. The time of Telisa deposition coincide with the start of the peak hydrocarbon generation time at about 16 Ma. This age is a critical moment for the Central Sumatra Basin petroleum system.
The discovery of Duri Field at 600’ depth by Caltex in 1941, and the discovery of Minas Field at 2000’ depth by the apanese occupation army in 1944, indicated a major new shallow oil province. In fact, the Central Sumatra Basin has proven to be the most prolific free-world petroleum province between California and the Middle East. One reason the Central Sumatra Basin is so prolific is because of its very high heat flow. Good quality reservoir sands, derived from quartzitic and granitic terrain, occur within the Menggala, Bekasap and Duri formations. The very high heat flow has caused the rich Tertiary shales in the section to generate large volumes of hydrocarbons. The average of geothermal gradient in the Central Sumatra Basin is 3.43oF/100’. The very high heat flow in the basin results from magmatic intrusions and associated mantle waters penetrating the shallow Pre-Tertiary basement to within a few miles of the surface, exposing the Tertiary sedimentary cover to high temperatures (Eubank and Makki, 1981).