The Bureau of Mineral Resources (BMR) collected 1430 line-km of bottom-water Direct Hydrocarbon Detection (DHD) data during a survey aboard R.V. Rig Seismic in the Durroon Sub-basin, the Otway Basin, the Torquay Sub-basin, and the Gippsland Basin, during late September and early October of 1991. No significant bottom-water anomalies were detected in the Durroon Sub-basin. Anomalous concentrations of light C2+ hydrocarbons were detected in the eastern Otway Basin. The anomalies were not extensive, comprising only a few data points representing a few kilometres in extent. One anomaly (of methane, ethane and propane) was accompanied by high levels of the biogenic hydrocarbons, ethylene and propylene, suggesting in-situ biogenic activity in the water column. However, anomalous concentrations of C7 and C8 hydrocarbons were also found here and at three other locations, and are from an unknown 'source'. A weak bottom-water anomaly was detected in the Torquay Sub-basin in the same location as an anomaly detected during an earlier survey (Rig Seismic Survey 89), two years previously. The weakness of the anomaly prevents a confident interpretation of the potential 'source' of the hydrocarbon anomaly, but the data suggests it is derived from a gas/condensate, or dry thermogenic gas 'source'. Several strong bottom-water anomalies were detected in the Gippsland Basin. Bottomwater anomalies were found near the Sunfish and Tuna oil/gas accumulations, in similar locations to anomalies found on Rig Seismic Survey 89, two years earlier. However, another previously-detected anomaly (near Barracouta) was not reproduced. Additional anomalies were found near Flathead, and to the west of Wahoo. The anomaly west of Wahoo was weak and in a similar area to that detected on Survey 89. The composition of most bottom-water hydrocarbon anomalies in the Gippsland Basin are indicative of a liquid-prone hydrocarbon 'source', while one anomaly in the northern sector of the survey area is indicative of a gas/condensate 'source'.

As part of its geochemical research program, the Marine Geoscience and PetroleumGeology Group (Australian Bureau Of Mineral Resources) is evaluating the usefulness ofthe Direct Hydrocarbon Detection (DHD) method. The data for this DHD program wereacquired during a co-operative high resolution seismic reflection program with WoodsidePetroleum Pty Ltd in the Dampier Sub-Basin. The data acquisition phase took placebetween October 22-28, 1990, with a total of 531 km (25 lines) of DHD data beingcollected between the Angel gas field in the north-east and the Madeleine 1 well in thesouth-west of Woodside Petroleum exploration permit WA-28-P in the Dampier Sub-Basin, on the North-West shelf, Australia. No significant hydrocarbon anomalies were detected on any of the lines, in spite of the factthat many lines traversed known oil and gas accumulations, such as the Wanaea, Cossackand Angel accumulations. The lack of anomalies indicates that the major reservoirhorizons in this part of the Dampier Sub-Basin are well-sealed, and that little opportunityfor the vertical migration of hydrocarbons exists. While no significant anomalies were detected, very minor increases in total hydrocarbonwere, however, observed over some of the wells/fields. The largest increase in THC wasobserved over the Montague 1 well location, where the value increased from abackground level of 16ppm to a high of 22.8ppm. There was no increase in any of thelight hydrocarbon gases.

The Mentelle Basin is a large (36 400 m2) frontier basin lying less than 100 km to the west of the oil and gas producing Perth Basin. The basin was formed during Jurassic extension which preceded the breakup between Australia and Greater India in the Valanginian. The breakup was accompanied by significant volcanism with extensive lava flows overlying the Valanginian unconformity. The Mentelle Basin comprises two structurally different depocentres. The eastern depocentre lying in shallow water (less than 500 m) is a large complex half-graben with up to 8 km of sediments, most of which are synrift section. The Western Mentelle depocentre lies between 2000 to 3300 m water depths and contains up to 7 km synrift and 2.5 km postrift section. The Mentelle Basin has never been drilled. Seismo-stratigraphic correlations are made to the DSDP well 258 on the Naturaliste Plateau and to the exploration wells in the Southern Vlaming Sub-basin. However direct correlations are possible only for the Late Cretaceous to recent part of the section. Recent Geoscience Australia studies involving structural restoration of the margin have shown that major tectonic and accommodation cycles are the same for both basins. The ages of the synrift sequences in the Mentelle basin therefore have been interpreted using the new Vlaming Sub-basin tectonostratigraphic framework. Seismic facies analysis was then used to define potential source rock intervals and correlate them to the known source rocks in the Vlaming Sub-basin. To test petroleum potential of this frontier basin 2D burial history analysis has been performed for the three regional lines. For each line three different scenarios with varying source rock characteristics reflecting end member possibilities have been explored. The potential effect of heat flow variations and intrusive volcanics on the maturation history have also been assessed. The modelling results suggest that source rocks in the deepest part of the synrift section are overmature, while uppermost Berriasian source rocks are immature. Source rocks that are currently within the maturation window are Middle Jurassic to Early Cretaceous shaly and coaly intervals, which commenced generation in the Late Jurassic. The erosion of significant sedimentary thickness in the Eastern Mentelle during continental breakup slowed down and in some cases stopped hydrocarbon generation. As this part of the basin has less that 1 km of postrift section only source rocks with sufficient overburden are still generating. In the Western Mentelle the same source rocks are buried much deeper and continued to generate throughout the Tertiary and up to the present. In the Eastern Mentelle oil generation and migration was roughly synchronous with the development of most structures whereas in the western Mentelle more source rock intervals continued generating after the major structuring. The main risk in the Mentelle Basin is the presence of good quality seals at the right stratigraphic level. Existing seismic coverage is insufficient for detailed structural interpretation needed to define potential traps. Provided suitable structures are found in the Mentelle Basin it may have similar petroleum potential to the Vlaming Sub-basin.

In October/November 1990 the Australian Bureau of Mineral Resources (BMR) carried out an 18 day combined water column geochemical and high resolution seismic survey on the Vulcan Sub-basin region of the Timor Sea. This report presents the results of the water column geochemical (direct hydrocarbon detection or DHD) aspects of that program. During the program, 2730 km of DHD data were obtained along 44 lines over the Vulcan Sub-basin, the Ashmore Platform and the Londonderry High. Ten water bottom hydrocarbon anomalies were detected during the program. Seven of these anomalies fell into two distinct groupings, which were associated with: - the Skua field and surrounding fault blocks, - the intersection of the NE-trending Vulcan Sub-basin/Londonderry High Boundary Zone with a prominent NW-trending transfer fault zone. The composition of the hydrocarbon anomalies within the Skua grouping was generally consistent with them having an oil-prone, Late Jurassic source,, and is thus compatible with the known composition of the hydrocarbons in the Skua accumulation. The composition of the other grouping was more consistent with a gas/condensate source; they may have originated from more gas prone Permo-Triassic source rocks on the edge of the Londonderry High. The remaining anomalies were all very weak, and may have been due to biogenic activity. The data indicate that the DHD technique can be useful at a prospect level within the Timor Sea (for example, it did remotely detect the Skua accumulation). The types of accumulations which are most easily detected using DHD are those with a significant gas cap, a relatively shallow (<2000 m) reservoir, and faulting which extends from the reservoir horizon to near the seafloor. Furthermore, the data suggest that transfer fault zones provide important pathways for hydrocarbon migration in this region.

This study undertook geochemical and isotopic analyses on a wide selection of oil stains from the Thorntonia Limestone, Arthur Creek Formation and the Arrinthrunga Formation and its lower Hagen Member in order to define geochemical inter-relationships between the oils, characterize their source facies and to determine the extent of post-emplacement alteration. Oil stains were collected from BHD-4 and -9, Elkedra-2 and -7A, Hacking-1, MacIntyre-1, M13 PD, NTGS99/1, Owen-2, Randall-1 and Ross-1 over a depth range from 91 to 1065 m and were analysed for bulk, molecular (biomarkers) and carbon isotopic compositions. Gas chromatograph of the saturated hydrocarbon fraction clearly showed biodegradation as the main alteration process in the shallow reservoirs. Unaltered oil stains show a dominance of medium weight n-alkanes with a maximum at n-C15. Biodegradation results in a progressive loss of the lighter hydrocarbons and an accompanying shift in n-alkane maximum to C27, to finally a complete loss of n-alkanes and a large unresolved complex mixture (UCM). The absence of 25-norhopanes suggests a mild level of biodegradation. The low ratio of saturated hydrocarbons/aromatic hydrocarbons (<1, down to 0.42) compared to high ratios (up to 4.35) for oils with abundant lower molecular weight n-alkanes is consistent with biodegradation. However, low ratios are also seen for otherwise pristine oils, suggesting a complex charge history of initial biodegraded and subsequent re-charge with n-alkane-laden oil. The level of biodegradation is not too severe as to overtly affect the distribution of the biomarkers C19 - C26 tricyclic terpanes, C24 tetracyclic terpane, C27 - C35 hopanes, C30 triterpane (gammacerane) and C27- C29 desmethylsteranes, enabling their use in oil-oil correlation and definition of oil populations. To clarify the inter-relationships among the Georgina Basin oil stains multivariate statistical analysis was used involving a wide range of biomarker ratios that are source-specific and environmental indicators. Resulting oil populations showed a strong correlation with their reservoir unit across the basin, suggesting juxtaposition of source and reservoir within the same stratigraphic unit. Oil-source correlation based on biomarker, bulk carbon isotopes of saturated and aromatic hydrocarbons and n-alkane-specific carbon isotopes identified Thorntonia(!), Arthur Creek(!) and Hagen(.) Petroleum Systems. The latter petroleum system is characterised by relatively high gammacerane, indicating an evaporitic depositional environment. Alternatively, an evaporatic organic facies from an Arthur Creek Formation source may have sourced the Hagen Member oil stains, considering that other oil stains reservoired within the Arrinthrunga Formation show a close affinity with oil stains from the Arthur Creek(!) Petroleum System, suggesting an inter-formational Arthur Creek-Hagen Petroleum System at Elkedra-2. An Arthur Creek-Hagen(!) petroleum system is evident at Elkedra-7A while there is a mixed Thorntonia Limestone and Arthur Creek source contribute to the oil stain at Ross-1.

Legacy product - no abstract available

Legacy product - no abstract available

Legacy product - no abstract available

The objectives of Project 121.19 were: To understand the deep crustal architecture, the structural reactivation processes and the mechanisms of hydrocarbon generation, migration and entrapment within the Vulcan Sub-Basin, Timor Sea. To achieve the aims of the project, two surveys (Vulcan I & II) were conducted between October and December 1990. This report summarises the results of the Vulcan Sub-Basin I Survey (Survey 97), which focussed on the high resolution seismic and geochemical component of Project 121.19 (i.e. the structural reactivation, hydrocarbon generation and migration theme). The Timor Sea program achieved most of its objectives. The seismic data should, when processed, allow a much better understanding of the nature of the fault reactivation processes in the area. In addition, strike lines run along the Londonderry High show that near-vertical faults appear to correspond with the position of transfer faults which have been inferred from our interpretation of BMR's Timor Sea aeromagnetic data. The geochemical program identified a number of significant hydrocarbon anomalies in the area. The anomalies fell predominantly into two groups. One group was located over, and to the north-east to south-east of the Skua Field, while the other group was associated with transfer faulting, and a major aeromagnetic high, on the edge of the Vulcan Sub-Basin, south-east of Montara 1.

This publication is the successor to Oil and Gas Resources of Australia 2004 and continues as the definitive reference on exploration, development and production of Australia's petroleum resources. OGRA 2005 provides the background for much of the advice on petroleum resources given to the Australian Government. The data are presented in categories that will allow the user to rapidly access specific data they are after. The categories are: - Well data - Seismic Data - Discoveries - Reserves - Production and Development - Expenditure - Titles - Coalbed Methane