[Section 1] [Section 3] [Section 4] [Entire Document (60Kb)] PETROLEUM GEOLOGY The largest prospective offshore basin is Bligh Water Basin covering some 9500kmē. Shallow water depths combine with sediment thicknesses in excess of 5000m and favourable geology to make this the most prospective basin in Fiji (Figure 7). Water depths are mostly less than 100m in the western half of the basin, whilst most of the eastern half is between 200 and 600m deep (Figure 1). Bad Waters Basin is the offshore extension of the Rewa Basin. The shallow-water area (less than 500m water depth) is restricted to a nearshore zone some 25km wide with an area of 1600kmē. Water depth increases dramatically eastwards to over 2000m. Sediment thicknesses reaching over 4000m and promising geology make this the second most prospective basin in Fiji. Other areas have either excessive water depth or unsuitable geology rendering them unattractive for hydrocarbon exploration. The Baravi and Suva Basins to the south of Viti Levu have water depths in excess of 2000m. The Great Sea Reefs and Yasawa Platforms have insufficient sediment thicknesses to generate hydrocarbons, whilst uplift and erosion of the Lau Ridge has generally exposed the potential Tertiary reef reservoirs at the surface (Ref. 1). The potential of arc-related basins to accumulate source rocks and generate oil and gas is conclusively demonstrated by the basins of Southeast Asia. Source rocks containing Type II and Type III kerogen, and with TOC in the range 0.5-2% generate waxy crudes and gas found in oil fields of Sarawak and Sabah. Malaysia, Indonesia and the Philippines. Source rock data from Fiji indicate that similar source rocks are present in the offshore Fiji basins. Furthermore, oil seeps and source rocks elsewhere in the Southwest Pacific region indicate that carbonate algal source rocks are also present in island-arc basins. Biomarker analysis of oil seeps in neighbouring Tonga indicate these to be derived from a marine carbonate source rock, probably from kerogen Type II (Ref. 11). In Vanuatu, algal-derived carbonate source rocks with Type II kerogen have been sampled, containing 1.4-1.8% TOC (Ref. 12). In Fiji, hydrocarbon source rocks ranging in age from Oligocene to Pleistocene crop out on Viti Levu and have been encountered in exploration wells (Figures 2 and 4). Defined by having a total organic content (TOC) which exceeds 1%, the source rocks are dominated by kerogen Types II and III and thus may generate oil and gas. Late Oligocene to Middle Miocene source rocks in the Wainimala Group were encountered by well Bligh Water-1 in Bligh Water Basin (Table 1). TOC is in the range 1-2.2%. During this period, prior to the break-up of the Outer Melanesian fore-arc basin, the vast regional extnt of the fore-arc basin (Figure 3) may have favored widespread deposition of individual source rock intervals. Consequently, the source rocks found in well Bligh Water-1 (Figure 2) may be regionally extensive. Source rocks of Late Miocene to Pliocene age occur in the Medrausucu Group and the Cuvu, Nadi and Verata Sedimentary Groups on Viti Levu, and in Bligh Water Basin and Bau Waters Basin. Average TOC's for these Groups are in the range 1.3-2.7% (maximum is 8.20%) with kerogen Types II and III. Individual coal-rich layers in the Nadi Sedimentary Group have up to 54.4% TOC. Following the break-up of the Outer Melanesian Arc in the Late Miocene, deposition occurred in a number of small, often fault-bounded basins. Such basins may have been silled, with the resulting anoxic conditions giving rise to excellent potential for the accumulation of source rocks. Oil and gas shows and seeps provide conclusive evidence that hydrocarbons have been generated in Fiji's offshore basins. A large pentane anomaly in sea-bottom sediments occurs in the south of Bligh Water Basin (Figure 8, Ref. 13). Preliminary geochemical analysis indicates that the oil has migrated from mature source rocks (Ref. 14). Strong gas shows were recorded throughout the Pliocene sections drilled by Bligh Water-1 and Yakuilau Island-1 (Figure 2). In Bad Waters Basin there were strong oil and gas shows in the Pliocene section drilled by Cakau Saqata-1. A bright spot on seismic line D-23 coincides with a small structural lead (Figure 9). Maturity modelling of source rocks shows that sediment thicknesses in both Bligh Water and Bad Waters Basins are sufficient to generate oil and gas, and that substantial Pliocene and Miocene kitchens could exist (Figure 10). Well Bligh Water-1, situated on the flank of a major structural high in Bligh Water Basin, encountered Middle and Late Miocene source rocks which were immature. Seismic correlation and maturity modelling predict that, deeper in basin centres to the north, east and west, these source rock intervals could reach the top of the oil window at 1750m below sea floor, whilst peak oil generation could occur at 2600m (Figure 11). Hydrocarbon generation could be continuing today. Pliocene source rocks are buried deep enough to be in the oil window in depocentres in the south and west of Bligh Water Basin where thicker Pliocene sections are developed (Figure 10). In Bad Waters Basin, Early Pliocene source rocks in Maumi-1 (Figure 2) situated on the edge of the basin are immature. However, these source rocks could reach the oil window in the deeper, offshore parts of the basin (Figure 12). The top of the oil window is predicted at 1800m below sea floor and maximum oil generation at 2700m. Should Miocene source rocks be present, as in Bligh Water Basin, these would have reached peak oil generation. There are two general prospective intervals of reefal limestone yet to be drilled in Fiji: Early to Middle Miocene and Late Miocene to Early Pliocene. Both intervals are well exposed onshore and exhibit numerous leads identified on seismic data in the offshore basins. Early to Middle Miocene reefal and platform limestone were developed on an arcuate, east-west trending palaeo-shelf edge across Viti Levu, which formed part of the Outer Melanesian fore-arc basin (Figure 13). The coral-algal Qalimare Limestone is the best exposed example (Figure 6). The limestone reefs and platforms coincide with ecstatic sea-level highstands at 18 and 16 Ma (Figure 14). High-stands are known to be generally conducive to reef growth and platform development (ref. 15 and 16). It is likely, therefore, that these limestone intervals may be regionally extensive, as is supported by the occurrence of Early to Middle Miocene reefal and platform limestone in the Yasawa islands. The characteristic mounded geometry of the reefal mounds is easily detected on seismic data, making them the most attractive exploration targets. Platform limestones, which include grainstones and packstones, are also good potential reservoirs. Reservoir porosity is likely to be good, judging from Pasca and Pandora Fields in offshore Papua New Guinea where average porosities of similar Miocene reef limestone reservoirs are 10 and 27% respectively (Ref. 17). In Fiji, karstification and leaching of the Middle Miocene limestones occurred during uplift in the Middle to Late Miocene (Figure 4) and sea-level lowstands at 16.5 and 15.5 Ma (Figure 14). This may have further enhanced porosity and permeability. Redeposited turbidite limestones provide another potential reservoir. These may form either fore-reef taulus deposits, or be the result of tectonic uplift and sea-level lowstands when the exposed shelf sediments are eroded. Massive fore-reef limestones form the island of Sawa-i-Lau in the Yasawa islands (Figure 15), whilst the Middle Miocene Qaraqara Member provides an excellent example of a lowstand limestone turbidite (Figure 14). It is possible that such deposits may be widespread in Bligh Water Basin. Late Miocene to Pliocene reefal and platform limestones constitute the second prospective interval (Figures 4 and 13). These shallow-water limestones developed around structural highs formed during the Late Miocene Colo Orogeny. Periods of reefal and platform limestone development coincide with sea-level highstands at 6.8, 5.8, 5 and 4 Ma (Figure 14) and may be widespread in the offshore basins. This is supported by many reefal anomalies identified on seismic data in Bligh Water and Bad Waters Basins (see Plays and Prospective Areas). Pliocene limestone drilled off-structure in well Maumi-1 had porosites of 20-25%. Most of the reef and platform limestones exposed onshore have unconformities at their tops, marked by leaching and karstification which has further improved their reservoir potential. Deep-water turbidite limestones provide additional reservoirs for this stratigraphic interval. Stratigraphic column abounds in potential seals ranging from shales and fine grained volcaniclastics to extrusive volcanic rocks (Figure 4). Most importantly, all the potential reef and limestone-burbidite reservoir objectives are overlain by sealing lithologies. The thick, massive nature of the sealing lithologies means that they may provide effective lateral seals for combination structural-stratigraphic traps, and cross-fault seals for faulted traps. Several decades of exploration has established Tertiary reefs as one of the major petroleum producing reservoirs in Southeast Asia. Reefs of Miocene and Pliocene age produce oil and gas in the Philippines, Malaysia, Indonesia and in Papua New Guinea. Figures 16 and 17 show that the same Tertiary reef play extends from the producing oil fields of Irian Jaya, Indonesia, through the gas/condensate fields of easten offshore Papua New Guinea and continues through the island-arc basins of the Southwest Pacific, as attested by outcrops on the islands themselves. Regionally, the Miocene reefs are the most extensive productive for oil and gas, but the Eocene and Pliocene reefs are also important. Oil seeps in Fiji and Tonga, together with the presence of source rocks on Fiji and through-out the Southwest Pacific, provide conclusive evidence that oil is present and that the arc-related basins are prospective for oil and gas. The reservoirs, seals and source rocks in Fiji, outlined above give rise to two distinct plays in the offshore basins of Fiji (Figure 18). Neither of the plays has been tested by drilling. Miocene-Pliocene Reef Play During periods of tectonic quiescence and/or sea-level highstands, reef growth may have been widespread throughout the offshore basins in favourable shallow-water conditions. Typically, these would have been located on structural highs and near shelf edges. Onlapping and overlying shales and volcaniclastics would have provided effective seals to create traps. During burial, hydrocarbons generated from basinal and/or lagoonal Miocene and Pliocene source rocks deeper in the basin may have migrated into the reefal traps. There are two main prospective intervals of reef development in Fiji: the Early to Middle Miocene and the Late Miocene to Pliocene (Figure 2). Twenty Late Miocene to Pliocene reefal leads have been identified on the existing seismic data in Bligh Water Basin and two in Bad Waters Basin (Figures 19 and 20). There is additional scope for this play in the deeper Early to Middle Miocene interval. However, this cannot be resolved at present due to the poor quality of seismic data and lack of seismic coverage in certain areas, e.g. central and eastern Bligh Water Basin. In southwest Bligh Water Basin, reefal leads with mounded geometries typical of patch reefs occur at the edge of a palaeo shelf (Figures 21 and 22). Elsewhere in Bligh Water Basin, reefal leads are situated on structural highs and show evidence of progradation characteristic of reefal platforms (Figure 23 and 24). Figure 25 shows an example of a similar lead in Bau Waters Basin. The interpretation of these features as reefs is supported by their location on shelf edges or structural highs. Furthermore, the leads coincide with sea-level highstands at 6.8 and 5Ma (Figure 14). Such highstands are generally known to be conducive to reef growth (Refs 15 and 16). All of the reefal leads are true structural traps with mapped structural closures. However, additional trap volume may exist due to lateral seals below the structural spill-point (eg. Figure 23), giving rise to combined structural-stratigraphic trapping. Estimates of potential unrisked recoverable reserves for typical reefal leads are about 270 million barrels of oil (mmbo) per structure (Table 2). If stratigraphic trapping occurs, the larger reefal leads could contain upward of 1 billion barrels recoverable per trap. Particularly attractive is the fact that the leads are often clustered (Figure 19) such that development and production facilities may eventually be shared by several fields, and thus significant cost economies could be made. The gross rock volumes are determined from mapped structural closures for structural leads. Lateral seals give rise to much greater vertical closures and trap areas for structural-stratigraphic traps. Potential unrisked reserves are estimated from likely average reservoir parameters (ranges are shown in parentheses in Table 2). Miocene-Pliocene Limestone Turbidite Play During tectonic uplift and/or sea-level lowstands exposure and erosion of the reefal and platform carbonates occurred. The eroded sediment would have been redeposited as deep-water turbidite lobes and mounds at the base of slope to form potential reservoirs (Figure 18). Onlapping and overlying basinal shales and volcaniclastics could provide effective seals. During burial, hydrocarbons generated from Miocene and Pliocene source rocks within the basin may have migrated into the turbidite traps. Such deep-water limestone turbidites form oil and gas reservoirs in several major petroleum provinces worldwide, including Abu Dhabi and Oman in the Middle East, the UK North Sea and the Philippines. In Fiji there are good examples of deep-water limestone turbidites exposed onshore (see Reservoirs). Three limestone turbidite leads have been identified in western Bligh Water Basin (Figure 19). They form elongate mounds situated down-slope of a palaeo-shelf edge (Figures 21 and 22). These are thought to be turbidite lobes derived from erosion of reefal mounds situated on the palaeo-shelf edge, an interpretation which is supported by the coincidence of the lobes with a sea-level lowstand at 3.8 Ma (Figure 14). Such lowstands are known to favour deposition of reef derived turbidite lobes (Ref. 15). The turbidite leads have estimated unrisked recoverable reserves of about 100 mmbo per structure. This could be increased to over 200 mmbo if combined structural-stratigraphic trapping occurs (Table 2). As with the reefal leads, the clustering of structures may result in ultimate cost economies at the development/production stage. For both the reef play and the turbidite play, key factors of hydrocarbon charge and timing are favourable. In central and eastern Bligh Water Basin, the Late Miocene to Pliocene reef and turbidite leads could have been charged from Oligocene and Miocene source rocks (Figure 10 and Table 1). In western Bligh Water Basin and in Bad Waters Basin, the Pliocene sequence is buried to depths in excess of 2000m, sufficient for Pliocene source rocks to provide oil and gas charge in addition to the Oligocene and Miocene intervals. The timing factor is favourable, since both the reefal and turbidite traps formed in the Late Miocene to Pliocene and could have been subsequently charged by oil and gas from the late Miocene to present (Figures 11 and 12). [Section 1] [Section 3] [Section 4] [Entire Document (60Kb)] |
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