Vertical geochemical profiling of the marine Toolebuc Formation, Eromanga Basin - implications for shale gas/oil potential The regionally extensive, marine, mid-Cretaceous (Albian) Toolebuc Formation, Eromanga Basin hosts one of Australia's most prolific potential source rocks. However, its general low thermal maturity precludes pervasive petroleum generation, although regions of high heat flow and/or deeper burial may make it attractive for unconventional (shale gas and shale oil) hydrocarbon exploration. Previous studies have provided a good understanding of the geographic distribution of the marine organic matter in the Toolebuc Formation where total organic carbon (TOC) contents range to over 20% with approx. half being of labile carbon and convertible to gas and oil. This study focuses on the vertical profiling, at the decimetre to metre scale, of the organic and inorganic geochemical fingerprints within the Toolebuc Formation with a view to quantify fluctuations in the depositional environment and mode of preservation of the organic matter and how these factors influence hydrocarbon generation thresholds. The Toolebuc Formation from three wells, Julia Creek-2 and Wallimbulla-2 and -3, was sampled over an interval from 172 to 360m depth. The total core length was 27m from which 60 samples were selected. Cores from the underlying Wallumbilla Formation (11 samples over 13m) and the overlying Allaru Mudstone (3 samples) completed the sample set. Bulk geochemical analyses included %TOC, %carbonate, %total S, -15N kerogen, -13C kerogen, -13C carbonate, -18O carbonate, and major, minor and tracer elements and quantitative mineralogy. More detailed organic geochemical analyses involved molecular fossils (saturated and aromatic hydrocarbons, and metalloporphyrins), compound specific carbon isotopes of n-alkanes, pyrolysis-gas chromatography and compositional kinetics. etc.

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

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

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.

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. ...

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.

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. Significant exploration activity is being seen in the Amadeus, Pedirka and Georgina basins and Beetaloo Sub-basin, while little is known of the potential of many other Central Australian basins. The globally acknowledged large resource potential of coal seam gas, shale and tight gas on the continent in addition to low sovereign risk 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 undertake an initial assessment of Australia's unconventional hydrocarbon resource potential. Capitalising on decades of high quality geological data held by the Commonwealth and the States and Territories, the programme aims to compile these data using nationally consistent assessment methodologies that ultimately provide robust figures in an internationally accepted standard. 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.

Australia's southern continental margin hosts rich oil and gas resources and offers huge potential for future discoveries. Most of Australia's oil has been produced from the Gippsland Basin, located in the easternmost part of the southern rift system. With all the petroleum system elements and processes in place, the basin contains Australia's only billion barrel oil fields. These giant accumulations are sourced from rich liquid-prone coaly and carbonaceous source rocks. In contrast, the western two-thirds of the southern margin is occupied by one of the largest frontier provinces in Australia - the Bight Basin. The thick sedimentary succession in the Bight Basin (>15 km) and its evolution from local half-graben depocentres during the Jurassic, to an extensive sag basin in the Early Cretaceous and passive margin during the Late Cretaceous to Holocene, suggests that there is significant potential for the presence of multiple petroleum systems across the basin. The Ceduna Sub-basin in the eastern Bight Basin is currently the focus of renewed exploration efforts. The key to its petroleum prospectivity is the distribution of Upper Cretaceous marine and deltaic facies. Dredging of upper Cenomanian-Turonian organic-rich marine rocks has confirmed the presence of high quality potential source rocks in this section. These rocks are mature in the central part of the Ceduna Sub-basin and are likely to have generated and expelled hydrocarbons since the Campanian. Excellent reservoir rocks and potential intraformational seals are present in the Upper Cretaceous deltaic successions, and regional seals could be provided by Upper Cretaceous marine shales.

The 2012 Australian offshore acreage release includes exploration areas in four southern margin basins. Three large Release Areas in the frontier Ceduna Sub-basin lie adjacent to four exploration permits granted in 2011. The petroleum prospectivity of the Ceduna Sub-basin is controlled by the distribution of Upper Cretaceous marine and deltaic facies and a structural framework established by Cenomanian growth faulting. These Release Areas offer a range of plays charged by Cretaceous marine and coaly source rocks and Jurassic lacustrine sediments. In the westernmost part of the gas-producing Otway Basin, a large Release Area offers numerous opportunites to test exisiting and new play concepts in underexplored areas beyond the continental shelf. Gas and oil shows in the eastern part of the Release Area confirm the presence of at least two working petroleum systems. In the eastern Otway Basin, several Release Areas are offered in shallow water on the eastern flank of the highly prospective Shipwreck Trough and provide untested targets along the eastern basin margin southward into Tasmanian waters. To the south, a large Release Area in the frontier Sorell Basin provides the opportunity to explore a range of untested targets in depocentres that formed along the western Tasmanian transform continental margin. This year, two Release Areas offer exploration potential in the under-explored eastern deep-water part of the Gippsland Basin. Geological control is provided by several successful wells indicating the presence of both gas and liquids in the northern area, while the southern area represents the remaining frontier of the basin.

Presentation delivered on 9 March 2012 by Marita Bradshaw.