The Early Cretaceous South Perth Shale has been previously identified as the regional seal in the offshore Vlaming Sub-basin. The South Perth Shale is a deltaic succession, which unfilled a large palaeotopographic low in the Early Cretaceous through a series of transgressive and regressive events. The new study undertaken at Geoscience Australia has shown that the seal quality varies greatly throughout the basin and at places has very poor sealing properties. A re-evaluation of the regional seal based on seismic mapping determined the extent of the pro-delta shale facies within the South Perth Shale succession, which are shown to provide effective sealing capacity. New sequence stratigraphic interpretation, seismic facies mapping, new and revised biostratigraphic data and well log analysis were used to produce palaeogeographic reconstructions which document the distribution of depositional facies within the South Perth Shale Formation and reveal evolution of the Early Cretaceous deltas. Our study documents spatial variations in the seal quality and re-defines the extent and thickness of the regional seal in the central Vlaming Sub-basin. It provides an explanation for the lack of exploration success at some structural closures and constraints for possible location of the valid plays.

A movie flythrough displaying various geological and geophysical data used for petroleum prospectivity assessment of the offshore northern Perth Basin

Presentation delivered on 9 March 2012 by Marita Bradshaw.

Extended abstract version of the abstract (Geocat#73747) submitted in March 2012 and accepted for an oral presentation at the symposium.

Exploration for Unconventional Hydrocarbons in Australia reached a new milestone when Beach Energy announced the first successful flow test of a shale gas target in the Cooper Basin. The ever expanding coal seam gas industry on Australia's east coast in addition to the large resource potential of shale and tight gas in Australia's eastern basins has put Australia firmly on the radar of many local and international exploration companies. Over the next 12 months Geoscience Australia in collaboration with its counterparts in the State and Territory resource and energy departments will begin an assessment of Australia's coal seam gas, shale gas and oil and tight gas resource potential. Capitalising on decades of high quality geological data held by the Commonwealth and the States and Territories, the aim of this collaboration is to develop nationally consistent assessment methodologies and provide robust national resource estimates in an internationally accepted standard. Overall, the programme aims to answer the 'where' and 'how much' questions for government, as well as provide this new industry with pre-competitive data and tools for comparing exploration opportunities. The immediate goal is to provide a first-pass, high level estimate of the likely resource volumes, which will be reported in the second edition of the Australian Energy Resource Assessment (published by RET). The longer term work program aims to assess Australia's onshore basins in terms of their resource potential and provide pre-competitive data to industry. To achieve this, several geological techniques will be applied including, but not limited to, geochemical screening, mapping of source rock occurrences and their distributions as well as physical rock property studies.

As part of the Offshore Energy Security Program (2007-2011), Geoscience Australia (GA) undertook an integrated regional study of the deepwater Otway and Sorell basins to improve the understanding of the geology and petroleum prospectivity of the region. Major outputs of this study include: - New interpretations of basement architecture and structural fabric resulting in the recognition of the Avoca-Sorell Fault System as a major control on sedimentary basin development, - Extension of the tectonostratigraphic framework of Krassay et. al. (2004) into the deepwater Otway and Sorell basins, leading to new insights into their structural and accommodation histories of both basins, and - Petroleum systems modelling indicating that these basins are mature for oil and gas generation.

Oil and gas discoveries in Australia's offshore basins are concentrated on the North West Shelf (Northern Carnarvon, Browse and Bonaparte basins) and Bass Strait (Gippsland, Otway and Bass basins). While discoveries have been made in a few regions outside these areas (e.g. Perth Basin), a large proportion of Australia's offshore basins remain exploration frontiers. However, the decline in oil production from the North West Shelf and Bass Strait basins since 2000 has led to an increasing exploration interest in the frontier basins. In order to improve our knowledge of the offshore frontiers and encourage exploration to these areas, from 2003-2011, Geoscience Australia was funded by the Australian Government to undertake a series of pre-competitive data acquisition and analyses programs in frontier basins around the Australian margin. This Record presents a comprehensive inventory of the geology, petroleum systems, exploration status and data coverage for 35 frontier basins, sub-basins and provinces, that draws on the results of those pre-competitive data programs, as well as exploration results and the geoscience literature. The Record also provides an assessment of the critical science and exploration questions and issues for each area. The results of each basin assessment are summarised in a prospectivity ranking. The availability of data and level of knowledge in each area is reflected in a confidence rating for that ranking. While the prospectivity of some areas is widely acknowledged to be high (e.g. Ceduna Sub-basin), the perception of prospectivity in many basins is negatively affected by the amount or quality of data available; in these basins, the acquisition of new data or targeted research could make a significant difference to the understanding of petroleum potential and likelihood of success. Therefore, recommendations for future work that could assist in addressing key knowledge or data gaps are included in each basin assessment.

Geoscience Australia has begun a systematic evaluation of the shale gas/oil (unconventional) resource potential of Australia's onshore sedimentary basins. According to the Australian Gas Resource Assessment 2012 [1] Australia's unconventional gas resource endowment is likely to be greater than its estimated total conventional gas resources with some basins likely to have significant unconventional oil potential. An assessment of Australia's unconventional resource potential will use methodology developed by the United States Geological Survey based on statistically derived estimates of hydrocarbon recovery from actual production data, or basin analogues in data-poor areas. The Georgina Basin, containing Proterozoic-Paleozoic age sediments and covering an area of ~325,000 sq. km in south-central Australia, is the first basin to be assessed and since there is no petroleum production history, suitable analogues will be sought. The assessment also relies heavily on the updated stratigraphy, tectonic history, petrography, geochemistry and petroleum systems modelling, with a discussion emphasis on the latter two datasets. The Georgina Basin is host to basin-wide oil staining and contains proven petroleum systems with relative short migration distances from source to trap, which likely represent multiple hybrid unconventional systems and breached conventional reservoirs. For example, the result of localised migration is exemplified in the composition of residual free hydrocarbons from organic-rich mudstones in which light and heavy hydrocarbons were recorded in samples 3 m apart. The most prolific oil-prone effective sources occur in the Middle Cambrian Thorntonia Limestone (early to middle Ordian) and overlying Arthur Creek Formation (latest Ordian to late Boomerangian). These source rocks were diachronously deposited from west to east under marine anoxic bottom waters, which periodically extended into the photic zone, and represent the local expression of a prolonged Middle-Late Cambrian oceanic anoxic event that lead to deposition of organic-rich 'black shales' on a global scale. The oil stains are varyingly altered by biodegradation and are geochemically characterised by a strong isotopic depletion in 13C, high abundance of monomethylalkanes, C15-C23 odd carbon number predominance for n-alkylcyclohexanes, C27 slightly dominant over C29 desmethylsteranes and high content of tricyclic terpanes. Source richness and maturity estimates are derived from Rock Eval, saturated and aromatic hydrocarbons, FAMM and hydrogen isotopic relationships between n-alkanes and isoprenoids. For example, the 'hot shale' unit comprising predominately dolostone at the base of the Arthur Creek Formation, currently the focus of drilling activity for unconventional hydrocarbons, has TOC and HI up to 15.5 % and 500 mg hydrocarbons/g TOC, respectively. Maturity levels range from the early oil to early dry gas windows. This unit appears to have all the geochemical pre-requesites for a significant unconventional hydrocarbon play. Geohistory modelling using formation-specific compositional kinetics indicates petroleum generation and expulsion begins in the latest Cambrian-Early Ordovician due to relatively rapid burial of the Arthur Creek Formation. Deposition ends with the start of the Alice Springs Orogeny and following uplift and erosion during the Devonian, hydrocarbon generation ceases. An unconventional petroleum resource assessment of the Georgina Basin will be undertaken in February 2013 and available for benchmarking and refinement against any future shale gas and shale oil production. [1] Geoscience Australia and Bureau of Resource and Energy Economics, 2012, Australian Gas Resource Assessment 2012, Canberra, 56 p. https://www.ga.gov.au/products/servlet/controller?event=GEOCAT_DETAILS&catno=74032

Extended abstract version of short abstract accepted for conference presentation GEOCAT# 73701

Introduction: As part of the Offshore Energy Security Program (2007-2011), Geoscience Australia (GA) undertook an integrated regional study of the deepwater Otway and Sorell basins to improve the understanding of the geology and petroleum prospectivity of the region. The under-explored deepwater Otway and Sorell basins lie offshore of southwestern Victoria and western Tasmania in water depths of 100-4,500 m. The basins developed during rifting and continental separation between Australia and Antarctica from the Cretaceous to Cenozoic and contain up to 10 km of sediment. Significant changes in basin architecture and depositional history from west to east reflect the transition from a divergent rifted continental margin to a transform continental margin. The basins are adjacent to hydrocarbon-producing areas of the Otway Basin, but despite good 2D seismic data coverage, they remain relatively untested and their prospectivity poorly understood. The deepwater (>500 m) section of the Otway Basin has been tested by two wells, of which Somerset 1 recorded minor gas shows. Three wells have been drilled in the Sorell Basin, where minor oil shows were recorded near the base of Cape Sorell 1. Structural framework: Using an integrated approach, new aeromagnetic data, open-file potential field, seismic and exploration well data were used to develop new interpretations of basement structure and basin architecture. This analysis has shown that reactivated north-south Paleozoic structures, particularly the Avoca-Sorell Fault System, controlled the transition from extension through transtension to a dominantly strike-slip tectonic regime along this part of the southern margin. Depocentres to the west of this structure are large and deep in contrast to the narrow elongate depocentres to its east. ...