Petroleum systems of the Northern Malay Basin

Abstract

The Northern Malay Basin petroleum province, offshore Peninsular Malaysia, comprises a central/basinal gas-rich area, flanked on both sides and to the south by mixed oil/gas zones. Non-associated gas fields in the central zone (Cakerawala to Bujang Trend) are found mainly in groups D and E reservoirs, in anticlinal traps formed by basin inversion during late Miocene times. This distribution may be biased by the depth of well penetrations in the basin centre due to the onset of overpressure. Oil occurs in faulted traps along the Western Hinge Fault Zone (Kapal to Beranang Trend), and is especially abundant on the NE ramp margin (Bunga Pakma-Raya Trend) where a separate kitchen may be present. Oil geochemistry reveals three main types of source rocks for the oils: lower coastal plain, fluvial marine and lacustrine source rocks. Most of the oils and condensates in the basin centre and on the Western Hinge Fault Zone are lower coastal plain oils, indicating charge from the basin centre. Lacustrine oils are restricted to the Bunga Pakma-Raya Trend on the NE flank, indicating charge from the basin centre as well as input from a small sub-basin to the northeast. Marine influence was found in oils from the most central position in the basin (Cakerawala-Bumi area). Vitrinite reflectance and basin modelling indicate that hydrocarbons were generated from source rocks within two main stratigraphic intervals: Group H and Group I, which are presently in the peak oil generation and gas generation stages, respectively. The basin-centre gas fields are charged from directly underneath, i.e. from the Group I kitchen, and from the post-mature shales in the older units (e.g. groups J and K). Vertical migration, assisted by deep-seated faults, is the dominant process in the basin centre. The enormous volume of thermogenic gas generated at the basin centre appears to have largely flushed out much of Group H oil that might have filled the D and E reservoirs initially. As a result, oil is more likely to have re-migrated and be trapped along the faulted basin margins, such as in the Western Hinge Fault Zone, away from the basin-centre gas kitchen. Limited oil accumulations may still exist in the basin centre where gas flushing is less effective. Oil could also be present below the regional overpressure seal (Group F) in the basin centre. The gases in the Northern Malay Basin contain varying amounts of CO 2. High CO 2 concentrations (>50 mol%) are typical of reservoirs in groups I and older and are mainly derived from inorganic sources. Low CO 2 concentrations (<6 mol%) are more typical of the reservoirs in groups D and E, and are derived from organic sources (thermal degradation of kerogen). The inorganic CO 2 distribution appears to be governed by proximity to deep-seated faults that act as conduits for fluid migration.

Fluid inclusions in quartz: Implications for hydrocarbon charge, migration and reservoir diagenetic history of the Penyu Basin and Tenggol Arch, offshore Peninsular Malaysia

“…These strata, which are currently in the oil/gas window, are found mainly in Groups H and I. They tend to be overmature in the basin centre but are at peak oil-to-gas maturation at the basin flanks (Madon et al, 2006). Abdullah (2014) has shown that some coals that are thermally labile can yield significant amounts of oil at lower vitrinite reflectivity (maturity) than commonly expected.…”

“…The petroleum system in the Malay Basin is relatively well-known from the hundreds of wells and studies carried out by PETRONAS and other operators since the late 1960's. Reviews have been made by , Madon et al (2006) and Tan (2009). There appears to be two main, spatially overlapping, petroleum systems; namely an Oligocene-Miocene lacustrine system, often characterised by low gravity with a paraffinic signature, and a Miocene system with oil and gas derived from lipid-rich coals.…”

“…There are indications, particularly in the south-eastern area of the Abu-Bubu and Penaga Field cluster, that there is an even older Eocene-Oligocene lacustrine system, restricted to isolated pods located in the centre of this and other individual syn-rift grabens. The Groups L and K source beds are believed to have charged reservoirs from Groups M up to H. In the northern part of the basin (overlap area with Vietnam), lacustrine source rocks have been inferred from the oil geochemistry to be present in isolated half-grabens (sub-basins) on the basin flanks to the northeast (Madon et al, 2006). (ii) Fluvio-deltaic system.…”

“…However, there remain questions as to how much these coal-derived hydrocarbons may have migrated laterally, given the likely channelized nature of the conduits, and equally likely 'imperfect' clay seal frequently incised by meandering channel systems. Deep-seated faults appear to have acted as major conduits for vertical migration of gases from the Group I and older source rocks in the central parts of the basin (Madon et al, 2006). According to Bishop (2002), more than half of the total estimated oil reserves (68 %), 45 % of the gas reserves and 43 % of condensate reserves in the Malay Basin are derived from the older, lacustrine beds (of Groups K, L, M).…”

Organic facies variation in lacustrine source rocks in the southern Malay Basin

“…It has been well documented that the oils and condensates of the Malay Basin are being generated by two main source rocks -lacustrine and fluviodeltaic, with varying degrees of mixing between them (EPIC, 1994;McCaffrey et al, 1998). However, a recent study on the petroleum systems of the northern part of the Malay Basin has also shown that fluvial marine source rocks could also generate these oils (Madon et al, 2006). The gradual change from lacustrine, through parallic and fluviodeltaic, to open marine in the source rock successions reflects the sedimentary evolution of the basin.…”