This report is a post-drill assessment of wells drilled in the Neoproterozoic to Palaeozoic Arafura Basin and the overlying Mesozoic to Cenozoic Money Shoal Basin. The Arafura Basin is located offshore northern Australia and extends from the onshore Northern Territory to beyond the Australian-Indonesian border. The region is under-explored with only 9 wells drilled, all of which are located in the central Goulburn Graben, a complexly structured feature. They include: Arafura-1, Chameleon-1, Cobra-1A, Kulka-1, Goulburn-1, Money Shoal-1, Tasman-1, Torres-1 and Tuatara-1. These wells have been analysed based on well completion reports, information from Geoscience Australia databases and published reports.

A wide variety of studies have been carried out around the Australian margin to infer or detect natural hydrocarbon seepage. Hydrocarbon seepage can, in selected geological settings, delineate subsurface petroleum accumulations and provide information on hydrocarbon charge type. However, the relationship between near-surface hydrocarbon seepage and subsurface petroleum generation and entrapment is often complex. Rates and volume of hydrocarbon seepage to the surface produce a variety of near-surface geological and biological responses, which require a range of sampling techniques to detect the seepage effectively. Interpreters must firmly grasp these issues to understand the significance of migrated hydrocarbons within near-surface sediments. Thus, it is important to understand the data types that have been used to infer seepage in Australia and the results of these studies, if natural hydrocarbon seepage is to be assumed in this region. Furthermore, the strengths and weaknesses of different approaches need to be understood and the data often need to be set in a global context to appreciate the significance of results obtained. This report is aimed at providing an overview of natural hydrocarbon seepage studies that have been carried out around Australia and to provide information on techniques and approaches that have proved to be successful during studies carried out by Geoscience Australian between 2004 and 2007. ... This investigation provides an increased understanding of seepage detection technologies and techniques, particularly in relation to the Australian environment, and appropriate interpretation of potential seepage indicators in a global context. Consequently, seepage studies can be undertaken with greater confidence in Australia's offshore jurisdiction, in locations and at times that are optimal for effective seepage detection.

This report contains data on the 68 petroleum accumulations discovered in the Bonaparte Basin to December 2002. It provides summaries of the regional setting, evolution and stratigraphy of the basin and discusses the hydrocarbon habitat and development of the producing accumulations. For the purpose of this report, a discrete, measured recovery of petroleum on test from an exploration well qualifies as a `discovery?. Petroleum accumulations inferred from wireline log interpretations (and where petroleum has not been recovered on test) are referred to as `shows?. Small quantities of gas recovered on test in three wells included in this report may represent `solution gas? - indicating these wells may not have intersected a petroleum pool.

Legacy product - no abstract available

Seismic acquisition for the joint BMR-Woodside Petroleum program in the Dampier Sub-basin started at 0800 am on October 24, 1990 and was completed at 1150 am on Sunday October 28, 1990. A total of 352 km of high resolution seismic data was collected along the 17 agreed survey lines, of which 336 km were full stack data with a total 390 magnetic tapes being used. Data quality appears to be good. In addition to the seismic, a total of 530.6 km of water column geochemical data were also collected.

Subsidence and thermal history analysis of 31wells and 25 depocentre sites has been undertaken to examine the generation and expulsion history of Jurassic and Early Cretaceous petroleum systems in the Browse Basin. The models incorporate new palaeo-bathymetric estimates of the deepwater post-Valanginian to Early Tertiary succession based on seismic geometries and detailed benthic foraminiferal data, as well as new kerogen kinetic data for multiple potential source units. The models suggest multiple effective source units for gas expulsion in the basin, whereas effective oil charge is largely restricted to the Heywood Graben in the northeast, and the rift section in the deepwater Serringapatam Sub-basin. Significant quantities of oil are modelled to have been expelled from Jurassic sediments (Plover and Lower Vulcan formations) in the Heywood Graben during the Tertiary and Late Tertiary, respectively. These charges are likely to have sourced the thick palaeo-oil columns interpreted at Heywood-1 and Crux-1. Modelled oil expulsion in the deepwater Seringapatam Sub-basin is highly sensitive to the organic richness and quality of interpreted Jurassic rift sediments. Provided these units contain good quality source rocks comparable to those within Jurassic rifts elsewhere on the North West Shelf, then significant quantities of oil and gas are modelled to have been expelled from this graben during the Late Tertiary. Evidence of such an oil charge may be provided by thin zones of elevated GOI data in Jurassic reservoirs at North Scott Reef-1, Scott Reef-2A and Brecknock-1, all located on a major anticlinal trend inboard of the Seringapatam graben. Regional models of the recently identified, oil-prone, Early Cretaceous (Echuca Shoals Formation) petroleum system suggest that these rocks have not expelled significant volumes of oil. However, organic-rich sediments within this succession occur as thin transgressive sheets deposited in response to fluctuating sea level on a gently inclined ramp margin, and thus higher-resolution sequence stratigraphic models are required to more accurately assess their local expulsion history. Local effective oil charge from these sources is confirmed by the Cornea, Gwydion-1 and Caswell-2 accumulations. The expulsion models highlight the importance of Late Tertiary carbonate clinoforms in controlling the generation and expulsion history of effective source rocks in the Browse Basin. The rapid progradation of these carbonates is likely to cause an outward-migrating compaction wave that forces expelled fluids and hydrocarbons to outboard areas. This mechanism may apply elsewhere on the North West Shelf where carbonate clinoforms are similarly well developed, and could provide new exploration opportunities in outboard areas.

Legacy product - no abstract available

With coal seam gas becoming an increasingly important contributor to the energy sector in eastern Australia, a critical factor is to understand the source of this gas, enabling migration fairways to be inferred and to access the risk of gas alteration and loss from source to reservoir. The paper will detail the use of stable carbon and hydrogen isotopic composition of individual coal seam gas components (methane, C2+ hydrocarbons and CO2) in determining the origin of the coal seam gases. The gas samples are from recent appraisal drilling by Queensland Gas Company Limited and Arrow Energy N.L. in the Jurassic Walloon Coal Measures, eastern Surat Basin, and are supplemented by Permian coal seam gas of a wide geographic distribution from the eastern (Moura and Peat ? Oil Company of Australia) and western margins of the underlying Bowen Basin (Fairway ? Tipperary Oil and Gas (Australia) Pty Ltd). The isotopic analyses from the coal seam gases are also compared with natural gases from conventional sandstone reservoirs in the Surat and Bowen basins. For methane from the Jurassic coals the carbon isotopes show a very narrow range from ?13C -57.3 to -54.2 ?. This compares to the much wider isotopic range for methane from the Permian coals (?13C -79.9 to -22.9 ?), reflecting a `continuum? from biogenic (isotopically light) to thermogenic (isotopically heavy) sources. On the other hand, the natural gases are isotopically heavy (?13C -43 to -31.9 ?), consistent with their thermogenic source from Permian coals and associated disseminated organic matter. Similarly, the hydrogen isotopes show a restricted range from ?D -215.5 to -203.3 ? compared with methane from Permian coals of ?D -255 to -152 ?. On the other hand, the carbon isotopes of the associated C2+ hydrocarbons (?13C -43.9 to -24.5 ?) are similar for the Jurassic coal seam gases and the conventional natural gases, suggesting a common thermogenic source for the wet gas components. Thus, the isotopic data for the hydrocarbon gases supports a mixed origin from local Jurassic coals and Permian sources. The former is the predominant source given that the associated CO2 is mostly isotopically light, ?13C range from -8 to -32 ?, and primarily sourced from decarboxylation of immature Jurassic coals.

"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.

During February-March 1991 the BMR conducted a combined Direct Hydrocarbon Detection (DHD) and high resolution seismic survey (Rig Seismic Survey 99; Fig. 1) in the Bonaparte Basin. This survey is one of three combined seismic and DHD surveys which were conducted in the Timor Sea (Fig. 2). Survey 99 collected approximately 3466 km of DHD, high resolution seismic, gravity, magnetics and side-scan sonar data. The data from this survey complement those obtained from Survey 100 (Bishop et al. 1992), which was conducted in the same general area. Three vibracores were taken in the northwestern corner of WA-217-P, while two grab sample sites were occupied in the vicinity of the Petrel gas field. Several bottom-water light hydrocarbon anomalies were detected during the survey, with most of these being located within the Petrel Sub-basin. A single, strong bottom-water anomaly, and several weaker hydrocarbon anomalies were found in the vicinity of the Petrel gas field, while weak, but aerally extensive anomalies were associated with the Tern gas field. No significant hydrocarbon anomalies were found in the Sahul Syncline. There were no strong C1 - C4 anomalies in the Malita Graben, however, one strong butane anomaly was found in the western end of the Malita Graben (principally composed of n-butane). Slightly elevated concentrations of light hydrocarbons were detected over an area of about 30 km in the eastern end of the Malita Graben (in the vicinity of the Heron 1 well). Cross-plots of percent hydrocarbon wetness versus methane indicate that the water column anomalies detected in the vicinity of the Tern and Petrel gas fields were sourced from a gas/condensate source, which is consistent with the known composition of the reservoired hydrocarbons at Petrel and Tern. The anomalies detected over the Tern and Petrel fields probably represent seepage directly from those accumulations. The general lack of hydrocarbon anomalies in both the Sahul Syncline and the Malita Graben may indicate that these source rock "kitchens" are no longer actively expelling hydrocarbons. A vertical profile conducted over one of the bottom-water anomalies near the Petrel gas field showed that the anomaly could be detected 40 metres above the seafloor. This highlights the fact that the DHD fish should be towed as close to the seafloor as possible if weak bottom-water anomalies are to be detected.