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.

Geoscience Australia recently commenced work on a multi-year study of Australian petroleum source rocks to improve our understanding of the petroleum resource potential of Australia's sedimentary basins. The Permian source rocks of the Cooper Basin are the first to be characterised for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. 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., 2015; 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 contains reviews the distribution, type, quality, maturity and generation potential of the Cooper Basin source rocks. 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. - A 3D basin model, characterising regional basin architecture, was constructed through the integration of existing horizons with formation tops and seismic interpretations (Hall et al., 2015a; Hall et al., 2016d). - Source rock distribution, amount and quality were reviewed through the analysis of log data and source rock geochemical data (including data acquired from new sampling), characterising source rocks across the whole basin (Hall et al., 2016a; Hall et al., 2016e). - 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., 2016b in prep; Hall et al., 2016f). This GIS contains all data associated with the above reports and accompanying data packages, providing important insights into the hydrocarbon prospectivity of the basin (Hall et al., 2015b; Kuske et al., 2015). The broad extent of the Cooper Basin's Permian source kitchen and its large total generation potential, highlights the basin's significance as a world class hydrocarbon province. The systematic workflow applied here 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.

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.

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).

The Cooper Basin is an upper Carboniferous to Middle Triassic intracratonic basin in northeastern South Australia and southwestern Queensland (Gravestock et al., 1998; Draper, 2002; Carr et al., 2016). 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 & Hill, 1998; Deighton et al., 2003). Hall et al. (2016a) reviews the maturity and generation potential of the Cooper Basin source rocks and is the third part of a series of reports reviewing various aspects of the hydrocarbon prospectivity of the Cooper Basin (see also Hall et al., 2015a; Hall et al., 2016a). This data pack contains the supplementary material accompanying this report. Over ninety 1D thermal and burial history models were integrated with the 3D basin model and source rock property characteristics to create a regional multi-1D petroleum systems model for the basin. The burial and thermal history of the model was calibrated using present day corrected temperatures and maturity indicators (Ro, Tmax). In addition lithologies for key wells were calibrated using velocity, density and thermal conductivity data. Thermal boundary conditions were modelled as transient heat-flow from base lithosphere. Crustal thickness and radiogenic heat production properties were used from published studies (e.g. Beardsmore, 2004; Meixner et al., 2012; Hall et al. 2015a). The 1D models are integrated with a 3D regional basin model (Hall et al., 2015a) to create a multi-1D petroleum systems model of the Cooper Basin. Parameters for source rock distribution, amount and quality were added from analysis of log data and source rock geochemical data (Hall et al., 2016a) and new Cooper Basin kinetics (Mahlstedt et al., 2015). This data pack includes the following grids for each source rock: temperature (°C), maturity (%Ro), transformation ratio (%), total hydrocarbon generation (mmboe/km2), oil expelled (mmbbl/km2), gas expelled (mmboe/km2; bcf/km2), oil retained (mmbbl/km2) and gas retailed (mmboe/km2; bcf/km2). The results quantify both the maturity and total maximum hydrocarbon yield of each source rock, providing important insights into the hydrocarbon prospectivity of the basin (Hall et al., 2015b; Kuske et al., 2015).

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.

Publicly available baseline ecology data are compiled to provide a common information base for environmental, resource development and regulatory decisions in the Cooper Basin region. This web service summarises existing knowledge of the ecosystems and environmental assets in the Cooper Basin region.

Publicly available groundwater data have been compiled to provide a common information base to inform environmental, resource development and regulatory decisions in the Cooper Basin region. This web service summarises salinity, water levels, resource size, potential aquifer yield and surface water–groundwater interactions for the Lake Eyre Basin located within the Cooper Basin region.

Publicly available geology data are compiled to provide a common information base for resource development and regulatory decisions in the Cooper Basin region. This web service summarises the geology of the Cooper Basin.

Publicly available groundwater data have been compiled to provide a common information base to inform environmental, resource development and regulatory decisions in the Cooper Basin region. This web service summarises salinity, water levels, resource size, potential aquifer yield and surface water–groundwater interactions for the Eromanga Basin located within the Cooper Basin region.