Processed seismic data (SEG-Y format) and TIFF images for the Arrowie line acquired as part of the 2008 Curnamona-Gawler-Arrowie Deep Crustal Seismic Survey (L189), acquired by Geoscience Australia (GA) under the Onshore Energy Security Program (OESP). Stack and migrated data for line 08GA-A1 as well as CDP coordinates and gravity data. The Arrrowie line is 60km in length and was sited south of Lake Torrens and north of Port Augusta. Raw data for this survey are available on request from clientservices@ga.gov.au

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.

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.

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.

Legacy product - no abstract available

Invited paper by CEO.

Few published studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. This paper presents strong geochemical evidence for coals being the source for the sub-economic oil accumulations in the Bass Basin. Oils in the Bass Basin form a single oil population. Biodegradation of Cormorant oil results in a separate oil family compared to Pelican and Yolla crudes. Oil-to-source correlation based on biomarkers and carbon isotopes shows that the Early Eocene to Palaeocene coals are effective source rocks in the Bass Basin. This is in contrast to previous work which favoured disseminated organic matter in claystone as the sole source (Miyazaki, 1995). Potential oil-prone source rocks in the Bass Basin are the early Tertiary coals, mainly concentrated in the Middle to Early Eocene succession. These coals have hydrogen indices (HI) up to 500 mg HC/gTOC) and are associated with disseminated organic matter in claystones that are mainly gas prone. Maturity is sufficient for oil and gas generation with vitrinite reflectance (VR) up to 1.8 % at base of Pelican-5. Igneous intrusions, mainly within Palaeocene, Oligocene and Miocene sediments, produce localised elevated maturity to 5 % VR. The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are: (i) the onset of oil generation at a VR of 0.65 % (2450m in Pelican-5); (ii) the onset of expulsion (primary migration) at a VR of 0.75 % (2700 to 3200m in Bass Basin; 2850m in Pelican-5); (iii) the main oil window between VR of 0.75 % and 0.95 % (2850-3300m in Pelican-5); and, (iv) the main gas window at VR >1.2 % (>3650m in Pelican-5).

The Otway Basin is now emerging as a major commercial gas province in southeast Australia. Sub-commercial oil occurrences in the basin suggest a liquids potential that has yet to be thoroughly addressed through rigorous geochemical study. To achieve this there is a critical need for more detailed information on the spatial variations in petroleum potential, condensate:gas ratios, (CGR), gas:oil ratios (GOR) and maturation characteristics within potential source horizons to identify sources for the oil and gas. In the Otway Basin, previous regional source rock assessment has identified a range of Late Jurassic to Cretaceous lithostatigraphic units that can be considered as potential petroleum source rocks (Edwards et al., 1999). Furthermore, oil families are particularly well understood through detailed carbon isotope and biomarker studies (Edwards et al., 1999; unpublished studies by Geoscience Australia and GeoMark Research Inc). However, there is a lack of integration of source rock characteristics with gas and oil geochemistry, leading to the identification of the effective source rocks in the Otway Basin. Otway Basin Organic Geochemistry Study A new organic geochemistry study in the Otway Basin is examining the petroleum potential of selected source intervals and aims to identify effective source rocks through oil-source correlations. As part of Geoscience Australia?s regional analysis of the Otway Basin, the study involves the integration of the geochemistry and biostratigraphic data within a sequence stratigraphic framework. The Otway Basin Project is currently interpreting key offshore and onshore wells, and a regional grid of conventional and deep-seismic data. Together, this work aims to chronicle a time-series of source rock development in the Otway Basin. New and existing samples of potential source rocks were selected for analysis by reviewing well logs, geochemical plots and web-based geochemical profiles. A total of 169 sediments from 32 onshore and 15 offshore wells were selected for more detailed gas-oil-source correlation studies. New vitrinite reflectance and fluorescence (VRFTM) analyses based on the technique of Newman (1997) were also carried out on samples from four key offshore wells (Mussell-1, Troas-1, Trumpet-1 and Voluta-1). Kerogen-specific VRFTM analyses will help to constrain vitrinite reflectance-vs-depth profiles, which are critical for accurate burial history modelling, as well as providing the primary control on maturation. On-Line Access to Organic Geochemistry Data The primary resource for organic geochemical data for the Otway Basin Project is ORGCHEM, Geoscience Australia?s Oracle database. Open-file information in the ORGCHEM database is available to users on-line via the Geoscience Australia?s website (www.ga.gov.au/oracle/apcrc). The website enables users to build geochemical profiles of Rock Eval (S2, HI, PI and Tmax) and vitrinite reflectance (VR) data (Figure 1) for most offshore exploration wells. For example, after submitting an initial well query, the user can generate a downhole profile of geochemistry results by clicking the ?Graph? option under the ?OrgChem? header. Sample ages are automatically estimated using GA?s STRATDAT Oracle database (Figure 1). .