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 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 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.

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.

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 northern Houtman Sub-basin is an under-explored region of Australia’s western continental margin. It is located at the transition between the non-volcanic margin of the northern Perth Basin and the volcanic province of the Wallaby Plateau and lies adjacent to the Wallaby-Zenith Transform Margin. In 2014, Geoscience Australia acquired new 2D seismic data (GA-349, 3455 km) across the northern Houtman Sub-basin to assess its hydrocarbon prospectivity. Previous studies of the Houtman Sub-basin indicated that en-echelon basin bounding N-NW trending faults are associated with the Permian half graben complex, however, it was not known if this structural style continued into the northern area of the Houtman Sub-basin. This study integrated interpretation of the recently acquired survey, with regional interpretation of the Houtman Sub-basin. This was further supported by well data and geophysical modelling and a regional 2D structural and stratigraphic interpretation developed. Structural mapping was done for the basement, Early Triassic (Woodada Formation) and Early Jurassic (Eneabba Formation). The basement structure of the northern Houtman Sub-basin is controlled by a series of large en-echelon NW-SE trending SW dipping faults, some of which have a throw of more than 10 km. These basement-involved faults control a series of Permian half graben separated by transfer zones and fault ramps. This basement architecture is similar to the inboard part of the southern Houtman Sub-basin, however the structures are larger. The Early Triassic and Early Jurassic faults trend NW-SE similar to the basement-involved faults, however major faults within the Jurassic succession lie about 50 km to the west of the Permian faults. Interpretation of the northern Houtman Sub-basin reveals a structurally complex basin containing a wide range of structural and stratigraphic traps at several stratigraphic levels. Potential plays have been identified in the upper Permian, Triassic and Jurassic successions. They include large stratigraphic plays in the Upper Permian/Lower Triassic, rollover anticlines within the Lower Triassic and Jurassic, and fault propagation folds and fault block plays in the Jurassic. Extended Abstract presented at the 2018 First Australasian Exploration Geoscience Conference (https://www.aig.org.au/events/first-australian-exploration-geoscience-conference/)