Geoscience Australia commissioned reprocessing of selected legacy 2D seismic data in the Pedirka-Simpson Basin in South Australia-Northern Territory as part of the Exploring for the Future (EFTF) program. 34 Legacy 2D seismic lines from the Pedirka Basin were reprocessed between May 2021 and January 2022 (phase 1). An additional 54 legacy 2D seismic lines (34 lines from Pedirka Basin, South Australia and 20 lines from Simpson Basin, Northern Territory) were reprocessed between November 2021 and June 2022 (phase 2). Geofizyka Toruń S.A. based in Poland carried out the data processing and Geoscience Australia with the help of an external contractor undertook the quality control of the data processing. The seismic data release package contains reprocessed seismic data acquired between 1974 and 2008. In total, the package contains approximately 3,806.9 km of industry 2D reflection seismic data. The seismic surveys include the Beal Hill, 1974; Pilan Hill, 1976; Koomarinna, 1980; Christmas Creek, 1982; Hogarth, 1984; Morphett, 1984; Colson 2D, 1985; Etingimbra, 1985; Fletcher, 1986; Anacoora, 1987; Mitchell, 1987; Bejah, 1987; Simpson Desert, 1979, 1984, 1986, 1987; Forrest, 1988; Eringa Trough, 1994; Amadeus-Pedirka, 2008 and covers areas within the Amadeus Basin, Simpson Basin, Pedirka Basin, Warburton Basin and Cooper Basin in South Australia and Northern Territory. The objective of the seismic reprocessing was to produce a processed 2D land seismic reflection dataset using the latest processing techniques to improve resolution and data quality over legacy processing. In particular, the purpose of the reprocessing was to image the structure and stratigraphic architecture of the Neoproterozoic to Late Palaeozoic Amadeus Basin, Triassic Simpson Basin, Cambrian–Devonian Warburton Basin, Permian–Triassic Pedirka Basin and Cooper Basin. All vintages were processed to DMO stack, Pre-stack Time Migration and Post-Stack Time Migration. <b>Data is available on request from clientservices@ga.gov.au - Quote eCat# 146309</b>

The Cooper Basin is a Pennsylvanian to Middle Triassic intracratonic basin in northeastern South Australia and southwestern Queensland (Gravestock et al., 1998; Draper, 2002; Carr et al., 2016). Exploration activity in the region has recently expanded with explorers pursuing a range of newly-identified unconventional hydrocarbon plays (Goldstein et al., 2012; Menpes et al., 2013; Greenstreet, 2015). In support of this ongoing exploration activity in the region, Hall et al. (2016a) reviewed the Cooper Basin source rock geochemistry and maturity based on a compilation of updated and quality controlled publically available total organic carbon (TOC), Rock-Eval pyrolysis and vitrinite reflectance data. This is the first study of its kind to be undertaken for the Cooper Basin as a whole and builds on the previous work of Boreham & Hill (1998) in South Australia. This data pack contains the supplementary material accompanying this report. The distribution, quantity, quality and thermal maturity of the organic matter were described for all formations within the Pennsylvanian¿Permian Gidgealpa Group and collectively for the formations within the Triassic Nappamerri Group (Hall et al., 2015a, 2016a). Where possible, data were also analysed by lithology. The total organic carbon (TOC) and Rock-Eval pyrolysis data were used to investigate source rock quality, maturity and kerogen type. Original Hydrogen Index (HIo) values for each formation and lithology were determined through the analysis of a subset of low maturity samples and through application of a maturity correction based on Cooper Basin-specific kinetics (Deighton et al., 2003; Mahlstedt et al., 2015). Where data density permits, maps of present day TOC content and both present day HI and original HI were created, showing the spatial variation in the amount and quality of the source rock present now and prior to the onset of hydrocarbon generation. This data pack includes all TOC and Rock Eval data for the Cooper Basin stratigraphic evaluated in Hall et al. (2016a). It also includes the grids of present day TOC for the shale and/or coaly shale intervals, along with the grids of present day and original HI by formation. These datasets quantify the spatial distribution, quantity and quality of the source rocks and provide important insights into the hydrocarbon prospectivity of the Cooper Basin (Hall et al., 2015b; Kuske et al., 2015). This was the first study to be completed as part of the Australian Petroleum Source Rock Mapping project, a new work program being undertaken at Geoscience Australia to improve our understanding of the petroleum resource potential of Australia's sedimentary basins.

The Cooper Basin is an upper Carboniferous-Middle Triassic intracratonic basin in northeastern South Australia and southwestern Queensland (Gravestock et al., 1998; Draper, 2002; McKellar, 2013; Carr et al., 2016; Hall et al., 2015a). The basin is Australia's premier onshore hydrocarbon producing province and is nationally significant in providing gas to the eastern Australian gas market. The basin also hosts a range of unconventional gas play types within the Permian Gidgealpa Group, including basin-centred gas and tight gas accumulations, deep dry coal gas associated with the Patchawarra and Toolachee formations, the Murteree and Roseneath shale gas plays and deep coal seam gas in the Weena Trough (e.g. Goldstein et al., 2012; Menpes et al., 2013; Greenstreet, 2015). The principal source rocks for these plays are the Permian coals and coaly shales of the Gidgealpa Group (Boreham & Hill, 1998; Deighton et al., 2003; Hall et al., 2016a). Mapping the petroleum generation potential of these source rocks is critical for understanding the hydrocarbon prospectivity of the basin. Geoscience Australia, in conjunction with the Department of State Development, South Australia and the Geological Survey of Queensland, have recently released a series of studies reviewing the distribution, type, quality, maturity and generation potential of the Cooper Basin source rocks (Hall et al., 2015a; 2016a; 2016b, 2016c; 2016d). Petroleum systems models, incorporating new Cooper Basin kinetics (Mahlstedt et al., 2015), highlight the variability in burial, thermal and hydrocarbon generation histories for each source rock across the basin (Hall et al., 2016a). A Geoscience Australia record 'Cooper Basin Petroleum Systems Analysis: Regional Hydrocarbon Prospectivity of the Cooper Basin, Part 3' providing full documentation of the model input data, workflow and results is currently in press. This work provides important insights into the hydrocarbon prospectivity of the basin (Hall et al., 2015b; Kuske et al., 2015). This product contains the working Cooper Basin Trinity-Genesis-KinEx petroleum systems model used to generate the results presented in these studies. This includes maps describing thickness, TOC and original HI for the following Permian source intervals: Toolachee Fm coals and coaly shales Daralingie Fm coals and coaly shales Roseneath Shale Epsilon Fm coals and coaly shales Murteree Shale Patchawarra Fm coals and coaly shales This model is designed for use as a regional scale hydrocarbon prospectivity screening tool. Model resolution is not high enough for this product to be used for sub-basin to prospect scale analysis, without further modification. However, the model provides a regional framework, into which more detailed prospect scale data may be embedded. The systematic workflow applied demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia's sedimentary basins.

The Cooper Basin is Australia's premier onshore hydrocarbon producing province and hosts a range of conventional and unconventional gas play types. This study investigates the petroleum generation potential of the basin's major Permian source rocks, to improve regional understanding of the basin's hydrocarbon prospectivity. Source rock distribution, thickness, present-day amount of total organic carbon (TOC), quality (Hydrogen Index) and maturity were mapped across the basin, together with original source quality maps prior to the on-set of generation. Results of the source rock property mapping and basin-specific kinetics were integrated with 1D burial and thermal history models and a 3D basin model to create a regional pseudo-3D petroleum system model for the basin. The modelling outputs quantify the spatial distribution of both the maximum possible hydrocarbon yield, as well as the oil/ gas expelled and retained, for ten Permian source rocks. Monte Carlo simulations were used to quantify the uncertainty associated with hydrocarbon yields and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coal and coaly shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals and coaly shales. The broad extent of the Cooper Basin's Permian source kitchen and its large total generation potential (P50 scenario >2000 bboe) highlights the basin¿s significance as a world-class hydrocarbon province. The difference between the P90 (~800 bboe) and P10 (>4000 bboe) scenarios demonstrate the range of uncertainties inherent in this modelling.

An assessment of tight, shale and deep coal gas prospectivity of the Cooper Basin has been undertaken as part of the Australian Government’s Geological and Bioregional Assessment Program. This aims to both encourage exploration and understand the potential impacts of resource development on water and the environment. This appendix presents a review of the regional petroleum prospectivity, its exploration, and the characterisation and analysis of shale, deep coal and tight gas in Carboniferous–Permian Gidgealpa Group of the Cooper Basin. The Cooper Basin is Australia’s premier onshore conventional hydrocarbon-producing province providing domestic gas for the East Coast Gas Market. As of December 2014, the Cooper and Eromanga basins have produced 6.54 Tcf of gas since 1969. The basins contain 256 gas fields as well as 166 oil fields that are currently in production. Gas is predominantly reservoired in the Cooper Basin, whereas the overlying Eromanga Basin hosts mainly oil. Hydrocarbon shows are found in the reservoir units throughout the succession. Recently, exploration targeting a range of unconventional plays has gained momentum. Unconventional play types within the mainly Permian Gidgealpa Group include shale gas associated with the Patchawarra Formation and the Roseneath and Murteree shales, tight and deep coal gas accumulations within the Toolachee, Epsilon and Patchawarra formations and additional tight gas plays in the Daralingie Formation and Tirrawarra Sandstone. To date, at least 80 wells have been drilled to test shale, tight and deep coal gas plays. Given the basin’s existing conventional production, and its processing and pipeline infrastructure, these plays are well placed to be rapidly commercialised, should exploration be successful. A prospectivity confidence mapping workflow was developed to evaluate the regional distribution of key unconventional gas plays within the Gidgealpa Group. For each play type, key physical properties were identified and characterised. The specific physical properties evaluated include formation extents, source rock properties (net thickness, TOC, quality and thermal maturity), reservoir characteristics (porosity, permeability, gas saturation and brittleness), regional stress regime and overpressure. Parameters for mappable physical properties were individually classified to assign prospectivity rankings. Individual properties were then multiplied together produce formation and play-specific prospectivity confidence maps. Non-mappable criteria were not integrated into the prospectivity mapping but were used to better understand the geological characteristics of the formations. Overall, both source and reservoir characteristics were found to be moderately to highly favourable for all play types assessed. Abundant source rocks are present in the Gidgealpa Group across the Cooper Basin. The Toolachee and Patchawarra formations are the richest, thickest and most extensive source rocks, with good to excellent source potential across their entire formation extents. Net shale, coal and sand thicknesses also demonstrate an abundance of potential reservoir units in the Gidgealpa Group across the basin. The predominantly fluvial Toolachee Formation is thickest in the Windorah Trough and Ullenbury Depression. Average effective porosity for assessed tight gas plays ranges from 6.7 % in the fluvio-deltaic to lacustrine Epsilon Formation to 7.8% in the Toolachee Formation. Based on an assessment of the brittleness of the shales and coaly shales, the Patchawarra Formation appears to be most favourable for hydraulic stimulation with an average Brittleness Index of 0.695, indicative of brittle rocks. This compares to the less brittle lacustrine Roseneath and Murteree shales have brittleness indices of 0.343 and 0.374, respectively. As-received total gas content is favourable, with averages ranging from 1.3 scc/g in the Patchawarra Formation to 1.6 scc/g for the Murteree Shale. The regional stress regime has an approximately east-west oriented maximum horizontal stress azimuth, resulting in predominantly strike-slip faulting to reverse faulting, depending on the depth, lithology and proximity of structures, e.g. GMI ridge. Significant overpressure is present at depths greater than 2800 m, especially in the Nappamerri and Patchawarra troughs. Overpressures are generally constrained to the Gidgealpa Group, with the Toolachee Formation being the youngest formation in which significant overpressure has been achieved. Based on a review of the geomechanical properties of the Cooper Basin sedimentary succession, it was found that stress variations within and between lithologies and formations are likely to provide natural barriers to fracture propagation between the gas saturated Permian sediments and the overlying Eromanga Basin. Prospectivity confidence maps were generated for six individual shale and deep coal plays and one combined tight gas play across the Gidgealpa Group. Comparison with key wells targeting shale, tight and deep coal gas plays, indicates that the prospectivity confidence mapping results are largely consistent with exploration activity to-date, with the highest prospectivity confidence for tight, shale and deep coal gas plays mapped in the Nappamerri, Patchawarra, Windorah, Allunga and Wooloo troughs and the southern Ullenbury Depression. Consequently, there is more confidence in the resultant maps in the southern Cooper Basin as more data was available here. Prospectivity confidence maps are relative, therefore a high prospectivity confidence does not equate to 100 % chance of success for a particular formation or play. The outputs of this regional prospectivity assessment identify areas warranting more detailed data collection and exploration and the assessment of potential impacts of resource development on water and the environment. The results also have the potential to encourage further exploration investment in underexplored regions of the Cooper Basin.

This appendix provides a regional geological analysis and conceptualisation of the Cooper GBA region. It delivers information critical for the shale, tight and deep coal gas prospectivity assessment outlined in the petroleum prospectivity technical appendix (Lech et al., 2019), and for input into assessing the potential impacts on groundwater and surface water assets detailed in the hydrogeology (Evans et al., 2019) and hydraulic fracturing (Kear et al., 2019) technical appendices. The Cooper Basin is a Carboniferous to Triassic intracratonic basin in north-eastern South Australia and south-western Queensland. It has a total area of approximately 127,000 km2, of which about three quarters lies within Queensland and the remainder lies within South Australia. Section 2 provides a comprehensive inventory and review of existing open data and information for the Cooper GBA region relevant for the prospectivity assessment (see the petroleum prospectivity technical appendix (Lech et al., 2019)) and hydrogeological characterisation (see the hydrogeology technical appendix (Evans et al., 2019)). It includes discussion of the datasets incorporated in the data inventory. A broad range of datasets were utilised to develop a three-dimensional conceptualisation of the geological basin. These include: geographic and cultural datasets which details the location and nature of administrative boundaries, infrastructure and topography; and geological datasets such as surface geology and geological provinces, well and seismic data and geophysical data. A range of public domain publications, reports and data packages for the Cooper Basin are also utilised to characterise the basin architecture and evolution. Section 3 reviews the Cooper Basin’s geological setting and the GBA region’s basin evolution from pre-Permian basement to creation of the Cooper, Eromanga and Lake Eyre basins. Section 4 reviews the main structural elements of the Cooper Basin and how these relate to the basin’s stratigraphy and evolution. The base of the Cooper Basin succession sits at depths of up to 4500 m, and reaches thicknesses in excess of 2400 m. The Cooper Basin is divided into north-eastern and south-western areas, which show different structural and sedimentary histories, and are separated by a series of north-west–south-east trending ridges. In the south-west the Cooper Basin unconformably overlies lower Paleozoic sediments of the Warburton Basin, and includes three major troughs (Patchawarra, Nappamerri and Tenappera troughs) separated by ridges (the Gidgealpa–Merrimelia–Innamincka and Murteree ridges). The depocentres include a thick succession of Permian to Triassic sediments (the Gidgealpa and Nappamerri groups) deposited in fluvio-glacial to fluvio-lacustrine and deltaic environments. The north-eastern Cooper Basin overlies Devonian sediments associated with the Adavale Basin. Here the Permian succession is thinner than in the south-west, and the major depocentres, including the Windorah Trough and Ullenbury Depression, are generally less well defined. The Cooper Basin is entirely and disconformably overlain by the Jurassic–Cretaceous Eromanga Basin. In the Cooper GBA region the Eromanga Basin includes two major depocentres, the Central Eromanga Depocentre and the Poolowanna Trough, and exceeds thicknesses of 2500 m. Deposition within the Eromanga Basin was relatively continuous and widespread and was controlled by subsidence rates and plate tectonic events along the eastern margins of the Australian Plate. The Eromanga Basin is comprised of a succession of terrestrial and marine origin. It includes a basal succession of terrestrial sedimentary rocks, followed by a middle marine succession, then finally an upper terrestrial succession. The Lake Eyre Basin is a Cenozoic sedimentary succession overlying the Eromanga Basin, covering parts of northern and eastern South Australia, south-eastern Northern Territory, western Queensland and north-western New South Wales. The Lake Eyre Basin is subdivided into sub-basins, with the northern part of the Callabonna Sub-basin overlying the Cooper Basin. Here the basin is up to 300 m thick and contains sediments deposited from the Paleocene through to the Quaternary. Deposition within the Lake Eyre Basin is recognised to have occurred in three phases, punctuated by periods of tectonic activity and deep weathering. This technical appendix provides the conceptual framework to better understand the potential connectivity between the Cooper Basin and overlying aquifers of the Great Artesian Basin and to help understand potential impacts of shale, tight and deep coal gas development on water and water-dependent assets.

The Cooper Basin is a Pennsylvanian to Middle Triassic intracratonic basin in northeastern South Australia and southwestern Queensland (Gravestock et al., 1998; Draper, 2002). Exploration activity in the region has recently expanded with explorers pursuing a range of newly-identified unconventional hydrocarbon plays (Goldstein et al., 2012; Menpes et al., 2013; Greenstreet, 2015; Carr et al., 2016). In support of this on-going exploration activity, Hall et al. (2015a) presented a regional overview of the architecture, tectonic evolution and lithostratigraphy of the Cooper Basin. This data pack contains the supplementary material accompanying this report. Structural architecture, extent and thickness of key stratigraphic units were characterised through construction of a regional 3D geological model, designed to capture the groups and formations associated with the major play types in the basin (Hall et al., 2015a). Existing published Cooper Basin horizons (DMITRE, 2001, 2009; NGMA, 2001) were integrated with stratigraphic tops (DNRM, 2015; DSD, 2015) and new seismic data interpretations, ensuring seamless integration of datasets across the state border. Isopachs extracted from the 3D model were used to review the extent and true vertical thickness of each stratigraphic unit. The Permian Toolachee and Patchawarra formations in Queensland are shown to have a wider extent compared with previous studies. The boundaries of the Roseneath and Murteree shales were revised, although their distribution still remains uncertain in areas such as the Arrabury Depression. Lithofacies analysis published for South Australia (Sun & Camac, 2004) were integrated with new stratigraphic analysis in the Weena Trough (Morton, 2016) and new electrofacies mapping in Queensland to produce the first basin wide set of lithofacies maps for the Toolachee, Daralingie, Epsilon and Patchawarra formations (Hall et al., 2015a). The resulting net sandstone, siltstone, shale and coal thickness maps characterise the regional distribution of key source, reservoir and seal units across the basin. Maps of net coal and shale thickness demonstrate an abundance of potential source rock facies in the Toolachee and Patchawarra formations in all regions. Additional potential source rock facies can be found in the Roseneath and Murteree shales, as well as in coals and shales of the Daralingie and Epsilon formations. Net sandstone thickness maps highlight possible regional reservoir facies distribution. The model is designed to characterise the formations associated with the basin's key petroleum systems elements, providing a framework for regional scale petroleum systems analysis and resource assessment studies (Hall et al., 2015b; Kuske et al., 2015). While this work provides important insights into both the conventional and unconventional hydrocarbon prospectivity of the basin, it also has application for the assessment of other resources such as groundwater (e.g. Smith et al., 2015a, b, c).

<div>The Australian Government's Trusted Environmental and Geological Information (TEGI) program is a collaboration between Geoscience Australia and the CSIRO that aims to provide access to baseline geological and environmental data and information for strategically important geological basins. The initial geological focus is on the north Bowen, Galilee, Cooper, Adavale, and their overlying basins. This paper presents seven stratigraphic frameworks from these basin regions that underpin groundwater, environmental and resource assessments, identify intervals of resource potential, and can assist in management of associated risks to groundwater resources and other environmental assets. The construction of stratigraphic frameworks for this program builds upon existing lithostratigraphic schemes to capture the current state of knowledge. The frameworks incorporate play divisions for resource and hydrogeological assessments. A total of 33 play intervals are defined for the north Bowen, Galilee, Cooper, Adavale, and their overlying basins, using chronostratigraphic principles. Where possible, unconformities and flooding surfaces are used to define the lower and upper limits of plays. Data availability and temporal resolution are considered in capturing significant changes in gross depositional environments. The results from this work enable the consistent assessment of shared play intervals between basins, and also highlight uncertainties in the age and correlation of lithostratigraphic units, notably in the Galilee and north Bowen Basins.</div> This presentation was given at the 2023 Australasian Exploration Geoscience Conference (AEGC) 13-18 March, Brisbane (https://2023.aegc.com.au/)

<div>Two new programs at Geoscience Australia are providing trusted, high-quality science to support decision making and the Australian resources industry. </div><div>&nbsp;</div><div>The Trusted Environmental and Geological Information program will provide baseline pre-competitive data in the Cooper, Adavale, north Bowen and Galilee basin regions. A repository of information is being developed in collaboration with CSIRO, including new geological and environmental assessments, to accelerate development in the sectors of petroleum, mineral, hydrogen and carbon capture and storage, while simultaneously providing opportunities to understand the potential hazards, risk and impacts of these resources being developed.&nbsp;</div><div>&nbsp;</div><div>The Data Driven Discoveries program is combining new and old data to better understand the under-explored Adavale Basin in central-western Queensland. The program will undertake chemical composition analyses to support the correlation of geological layers, collate and reprocess historical seismic data, acquire new seismic reflection data, and undertake stratigraphic research drilling to provide a more detailed understanding of basin architecture and the resource potential of the Adavale Basin. </div><div>&nbsp;</div><div>An overview of the Trusted Environmental and Geological Information and Data Driven Discoveries programs will be provided, including initial results and planned acquisition. This will show how these complementary programs will contribute to streamlined regulation and approval processes, the low emissions agenda, and responsible resource development in key basin regions across Australia.</div> This Abstract was submitted/presented to the 2022 Petroleum Exploration Society of Australia (PESA) QLD Symposium 9 September (https://pesa.com.au/events/pesa-qld-2022-symposium/)

Following the publication of Geoscience Australia record 2014/09: Petroleum geology inventory of Australia's offshore frontier basins by Totterdell et. al, (2014), the onshore petroleum section embarked upon a similar project for onshore Australian basins. The purpose of this project is to provide a thorough basis for whole of basin information to advise the Australia Government and other stakeholders, such as the petroleum industry, regarding the exploration status and prospectivity of onshore Australian basins. Eight onshore Australian basins have been selected for this volume and these include: the McArthur, South Nicholson, Georgina, Amadeus, Warburton, Wiso, Galilee and Cooper basins. This record provides a comprehensive whole of basin inventory of the geology, petroleum systems, exploration status and data coverage for these eight onshore Australian basins. It draws on precompetitive work programs by Geoscience Australia as well as publicly available exploration results and geoscience literature. Furthermore, the record provides an assessment of issues and unanswered questions and recommends future work directions to meet these unknowns.