A recent Geoscience Australia sampling survey in the Bight Basin recovered hundreds of dredge samples of Early Cenomanian to Late Maastrichtian age. Given the location of these samples near the updip northern edge of the Ceduna Sub-basin, they are all immature for hydrocarbon generation with vitrinite reflectance - 0.5% RVmax, Tmax < 440oC and PI < 0.1. Excellent hydrocarbon generative potential is seen for marine, outer shelf, black shales and mudstones with TOC to 6.9% and HI up to 479 mg hydrocarbons/g TOC. These sediments are exclusively of Late Cenomanian-Early Turonian (C/T) in age. The high hydrocarbon potential of the C/T dredge samples is further supported by a dominance of the hydrogen-rich exinite maceral group (liptinite, lamalginite and telalginite macerals), where samples with the highest HI (> 200 mg hydrocarbons/g TOC) contain > 70% of the exinite maceral group. Pyrolysis-gas chromatography and pyrolysis-gas chromatography mass spectrometry of the C/T kerogens reveal moderate levels of sulphur compounds and the relative abundances of aliphatic and aromatic hydrocarbons predict the generation of a paraffinic-naphthenic-aromatic low wax oil in nature. Not enough oom for rest of Abstract

The 50 major Australian source rock units can be grouped according to age into 15 intervals comprising Late Neoproterozoic, Middle Early Ordovician, late Early Ordovician, Middle to Late Devonian, Early Carboniferous, Early to early Late Permian, late Late Permian, Early to Middle Triassic, Early to Middle Jurassic, Middle to Late Jurassic, Late Jurassic, latest Jurassic to Early Cretaceous, Early Cretaceous, Late Cretaceous, latest Cretaceous to Eocene. Only marine source rocks are known older than Permian, while both marine and nonmarine source rocks are known from Permian and younger intervals. As expected, the marine source rocks are more common where there is a greater degree of continental inundation, while nonmarine source rocks are present only when the continent was at higher palaeolatitudes and when there was at least a moderate amount of continental inundation.

During April and May 1991 the Bureau of Mineral Resources conducted a combined deep crustal seismic and Direct Hydrocarbon Detection (DHD) survey (Rig Seismic Survey 100; Figure la) in the Bonaparte Basin, which is located in the Timor Sea off northwestern Australia. This survey is one of three combined seismic and DHD surveys (Surveys 97, 99 and 100) which have been conducted in the Timor Sea (Figure lb). Survey 100 collected approximately 2540 line-km of DHD, together with approximately 2100 line-km of deep crustal seismic, gravity, and magnetic data. The DHD data from this survey complements that obtained in the same general area during Survey 99 (Bickford et al., 1992). Several bottom-water light hydrocarbon anomalies were detected during the survey, mostly in the Petrel Sub-basin. The strongest anomalies were detected over the Petrel gas/condensate accumulation, in the vicinity of the Petrel-1 wellhead. Weak but aerially extensive anomalies were associated with the Tern gas/condensate accumulation. The Petrel anomalies differed in character from those found over Tern, in that they were strong, up to two orders of magnitude above background, and were confined to a small area. In contrast, the Tern anomalies were weak, generally less than two-fold above background, but extended over a large area. A cross-plot model of percent hydrocarbon wetness versus methane has been used as a tool to predict the potential 'source' (oil prone, gas/condensate or dry gas) of bottomwater anomalies. The data from the anomalies detected over the Petrel and Tern gas/condensate accumulations show wetness trends from background (less than 1%) to levels of about 3.4%, with increasing methane concentrations up to 272 ppm (over Petrel). The crossplot model trends are consistent with the hydrocarbon compositions in these gas/condensate accumulations. Several other hydrocarbon anomalies were detected away from exploration wells. These anomalies were typically weak, and usually of gas or gas/condensate 'source' (according to the crossplot model). However, one strong anomaly, detected in the southern Petrel Subbasin, had a maximum percent hydrocarbon wetness value greater than 16%, and an oilprone 'source' according to the crossplot model.

During February-March 1990 the BMR conducted a combined seismic and DHD (Direct Hydrocarbon Detection) survey in the Arafura Sea of northern Australia. This survey was the second to employ the 'geochemical sniffer' (DHD) aboard Rig Seismic, and represented the first deployments of the geochemical equipment from amidships Rig Seismic. The purpose of these deployments were to develop the capability to collect underway, bottom-water geochemical data simultaneously with seismic reflection, gravity and magnetic data. The bottom-water geochemical data hence would complement existing remote sensed methods to aid in offshore exploration for hydrocarbons, and to provide new insights into concepts of hydrocarbon generation and migration. As such, the deployment of the equipment amidships Rig Seismic was successful and will become a permanent installation. However, some mechanical (deployment) and data collection difficulties resulted in some gaps and artefacts in the bottom-water DHD, and these are noted in the text. Some parts of the data have been heavily edited.

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.

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.

"An audit of petroleum exploration wells in the Bass Basin, 1966-1999" provides reasons for the success and failure of previous exploration drilling in the Bass Basin. It highlights the risks and uncertainties of exploration drilling and offers insights into prospectivity for future exploration. The CD-ROM provides information on structure, petroleum systems elements, maturity, hydrocarbon shows, and an assessment of the validity of each of the 32 wells in the Bass Basin. It also contains images of seismic ties and composite logs for each well.

This report is an annual report which provides information and statistics on Australia's oil and gas resources. The statistics in this report include data for the calendar year 1999.

The molecular composition of fluid inclusion (FI) oils from Leander Reef-1, Houtman 1 and Gage Roads-2 provide evidence of the origin of palaeo-oil accumulations in the offshore Perth Basin. These data are complemented by compound specific isotope (CSI) profiles of n-alkanes for the Leander Reef-1 and Houtman-1 samples, which were acquired on purified n-alkane fractions gained by micro-fractionation of lean FI oil samples, showing the technical feasibility of this technique. The Leander Reef-1 FI oil from the top Carynginia Formation shares many biomarker similarities with oils from the Dongara and Yardarino oilfields, which have been correlated with the Early Triassic Kockatea Shale. However, the heavier isotopic values for the C15-C25 n-alkanes in the Leander Reef-1 FI oil indicate that it is a mixture, and suggest that the main part of this oil (~90%) was sourced from the more terrestrial and isotopically heavier Early Permian Carynginia Formation or Irwin River Coal Measures. This insight would have been precluded when looking at molecular evidence alone. The Houtman-1 FI oil from the top Cattamarra Coal Measures (Middle Jurassic) was sourced from a clay-rich, low sulphur source rock with a significant input of terrestrial organic matter, deposited under oxic to suboxic conditions. Biomarkers suggest sourcing from a more prokaryotic-dominated facies than for the other FI oils, possibly a saline lagoon. The Houtman-1 FI oil ?13C CSI data are similar to data acquired on the Walyering-2 oil. Possible lacustrine sources include the Early Jurassic Eneabba Formation or the Late Jurassic Yarragadee Formation. The low maturity Gage Roads-2 FI oil from the Carnac Formation (Early Cretaceous) was derived from a strongly terrestrial, non-marine source rock containing a high proportion of Araucariacean-type conifer organic matter. It has some geochemical differences to the presently reservoired oil in Gage Roads-1, and was probably sourced from the Early Cretaceous Parmelia Formation.

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