Following the intense Palaeocene-Early Eocene Sarawak Orogeny (around 40-36 Ma), the South China Sea engulfed the northern shore of Borneo in present-day NW Sarawak, enveloping both the Luconia/Tinjar terrains and also rimmed the recently emerged and eroding Rajang Group hinterlands on the northern Borneo shore. With prevailing inner neritic depositional environment at that time, benthic foraminiferal limestone banks and ramps developed on sheltered shoals, separated from each other by clastic fairways with turbiditic channel deposits. By Early-Middle Oligocene times, carbonate deposition slowed as a consequence of increased subsidence and or, less likely, of a strongly global rising sealevel. After a pause in which clastics dominated the area, a second carbonate system formed during the Early-Middle Miocene times. These carbonates contain the first hard evidence of small bioherms, mainly corals and coralline algae. However, in the study area, there is not a single outcrop or well which shows an uninterrupted carbonate sequence from the Palaeogene to the Neogene. In addition, it is believed that the palaeo-edge of the platforms today lies somewhat masked by tectonic events, in particular, by a Late Miocene to Early Pliocene fold and thrust belt. Consequently, we believe, that both the Eo-Oligocene and Early-Middle Miocene carbonate systems are independent, not linked or vertically interconnected. Arguably, the presence of carbonates in two distinct systems points to a deepening, and later shallowing in a mega cycle. Within the mentioned hypothesis, the Eo-Oligocene carbonate system was formed during the deepening of the NW Borneo foredeep, whereas the Lower-Middle Miocene carbonates originated as the foredeep shallowed. The latter eventually disappeared with the establishment of a shallow, clastic shelf.

The young terraces fringing the Miri coastline from Miri to Bekenu are formed by lignitic sands, fossil wood, and conglomeratic beds that contain reworked quartz pebbles derived from the older Tukau Formation. The sequence can be subdivided into four sub-units: I. Basal Conglomerate, II. Sandstone with fossil wood and Ophiomorpha, III. Crossbedded lignitic sandstone, and IV. Bleached and weathered palaeosol. These sediments are indicative of a transgressive near-shore, fluvial to marginal marine depositional environment, as water energy peaked in cross-bedded sandstone of Subunit III. Radiometric C-14 based age determination in ten coastal locations indicates an age range from Late Pleistocene to Early Holocene (28,570 + 230 to 8,170 + 50 years BP). Given the terraces were formed in the same environment, but are now located at different elevations and appear to be block-faulted, it might imply significant tectonic movements in the Holocene.

Natural gas hydrates (NGHs), sometimes referred to as “flammable ice”, are crystalline solids, consisting of hydrocarbon gases with low molecular weight, such as methane, ethane and propane, bound with water molecules within cage-like lattices. The water molecules and low molecular weight NGH lattices are stable within a specific range of temperatures and pressures, and the source of the gases can be biogenic or thermogenic in origin. NGHs are common in the upper hundreds of metres of sub-seafloor sediments on the continental margins at water depths greater than about 500 m. Seismic reflection profiles and wireline well logs are common indicators used to identify the presence of NGHs, which are often encountered during offshore deepwater exploration drilling. They may cause geohazards such as slope instability, expulsion of the seafloor, shallow water flows and shallow gas if the stability of penetrated NGHs is disturbed and starts to dissociate. Methane gas hydrates represent a significant potential energy resource, as illustrated in this case study from offshore NW Sabah and may represent one of the world’s largest reservoirs of carbon-based fuel, with some estimates suggest that the hydrocarbons bound in the form of NGHs may rival the total energy resources contained in other conventional hydrocarbon sources. Methane can be extracted from NGHs through three methods: depressurization, inhibitor injection and thermal stimulation. However, risk associated with NGHs extraction can contribute to environmental concerns such as global warming and a decrease in microbial communities associated with methane hydrate ecosystem. Presently, in many countries, national programs exist for the research and production of natural gas from NGH deposits. As a result, hundreds of deposits have been discovered, with a few hundred wells drilled and kilometres of NGH cores studied. Hence, in the future (pending improved gas price and extraction technology), methane gas hydrates could be a vast source of natural gas supply.

The onshore portion of Baram Delta petroleum province in northern Sarawak is largely covered by the Block SK333 exploration permit, most recently operated by JX Nippon. It contains a complete sedimentary succession ranging in age from Mid Eocene to Holocene. A sequence-stratigraphic investigation of the area, based on 2009 2D seismic, integrated with recent biostratigraphic analyses conducted in 2010-2011, suggests that the sedimentary section has been affected by three major episodes of deformation which are: (1) Late Cretaceous to Eocene (79.5-36Ma) block faulting, (2) Late Oligocene to Mid Miocene (30-20.5Ma) wrench movement and related folding, followed by (3) Mid Pliocene to Holocene (4.0-0Ma) uplift and compressional folding. These tectonic episodes have resulted in a subdivision of the Block SK333 area into two major anticlinal trends: the Engkabang-Karap Anticline in the south, and separated by the large Badas Syncline, the northern Miri-Asam Paya Anticline.This configuration resulted in two distinct petroleum systems and respective hydrocarbon zones: (i) A southern overmature gas system sourced probably from deeply buried and carbonaceous Eo-Oligocene basinal shales containing reworked terrestrial organic matter, which charged wrench induced traps such as at the Engkabang-Karap Anticline that were later overprinted by compressional folding. The surface expression of this petroleum system is manifested by an active mud volcano on the western Engkabang-Karap Anticline axis, which emits thermogenic C 1 gas. Burial history modelling indicates that an earlier oil charge probably occurred during deep Oligocene burial, preceding basin reversal during the Pliocene-Holocene inversion episode, with the wrench-induced anticlinal closure which subsequently has been charged by late gas. (ii) A block-wide oil and gas system sourced from peak mature Mid-Late Miocene carbonaceous shales and coals in the synclines, charging inversion and compressional fold structures along the northern Miri-Asam Paya anticlinal trend, and also the Miocene section at the Engkabang-Karap Anticline. Expulsion and charge to traps commenced during the Late Miocene and is continuing to the present-day. Although the exploration results of the southern Eo-Oligocene carbonate play have been disappointing to date, the onshore Baram Delta still contains a number of attractive, both untested and partially tested plays that are yet to be fully explored. Lowstand delta and turbidite plays, a highstand delta shoreface play in the Miri-Asam Paya anticlinal area and a moundform stratigraphic play in the southern limb of the Badas Syncline are among the untested play identified in the study area.

A review of clastic sandstone reservoirs in the Penyu Basin and Tenggol Arch area, adjacent to the south-western flank of the Malay Basin revealed that most deep reservoirs are affected by diagenetic alteration of reservoir mineral components. Furthermore, fluid inclusions in quartz are seen at distinct stratigraphic reservoir levels. These inclusions occur in Oligocene reservoirs in Groups L and M and in Miocene reservoirs of Groups K and H. However, to-date no oil inclusions have been found in Groups I and J. There appear to be two distinct populations of fluid inclusions in the so-called 'oil quartzes': (i) oil inclusions in allochthonous, detrital quartz grains. These inclusions are thought to be of the primary type, formed when oil was incorporated in growing quartz crystals, and oil is seen encapsulated in 'loose' quartz grains. There is no evidence of destructive diagenesis or cementation in these relatively shallow (Miocene) host reservoirs, and oil migration is not confirmed by other indicators such as bitumen, which is often found in deeper carrier beds together with oil quartzes. The origin of these oil quartzes is somewhat controversial, and cannot be determined with certainty. They were probably shed into the basin from eroded granitic basement horsts and ridges.(ii) in situ oil inclusions in quartz cement. The occurrence of oil encapsulated in quartz cement (secondary or tertiary inclusions) indicates oil migration had preceded quartz cementation. So-far, oil-bearing inclusions attributed to fractures could not be confirmed with certainty. Assuming a relatively constant temperature gradient in the basin during the Miocene, quartz cementation will have started at a palaeo-depth of ca. 2000 m or at 105 0 C, and porosity was mostly destroyed by a depth of ca. 3000 m and 130 0 C. Occasionally overpressures are observed. According to this model, oil had migrated into and percolated within reservoirs during the Miocene, but became locked in closed pores as quartz cement invaded pore spaces under increasing overburden and temperature. Consequently, fluid inclusions in quartz for this model suggest that depths of greater than 3000 m below mud line (BML) are likely to encounter sandstones with deteriorating reservoir properties in the study area.