Petroleum systems of the Northern Malay Basin

Author : Mazlan Madon, Jiu-Shan Yang, Peter Abolins, Redzuan Abu Hassan, Azmi M. Yakzan & Saiful Bahari Zainal
Publication : Bulletin of the Geological Society of Malaysia
Page : 125-134
Volume Number : 49
Year : 2004

Bulletin of the Geological Society of Malaysia, Volume 49, April 2004, pp. 125 – 134

Petroleum systems of the Northern Malay Basin


1Petronas Research & Scientific Services Sdn Bhd, Lot 3288-3289, Kawasan Institusi Bangi, 43000 Kajang, Malaysia

2CS Mutiara Petroleum Sdn Bhd, Level 52, Tower 2, PETRONAS Twin Towers, Kuala Lumpur City Centre, 50088 Kuala Lumpur, Malaysia


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 CO2. High CO2 concentrations (>50 mol%) are typical of reservoirs in groups I and older and are mainly derived from inorganic sources. Low CO2 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 CO2 distribution appears to be governed by proximity to deep-seated faults that act as conduits for fluid migration.