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.

This report highlights results of petroleum systems analysis undertaken on the northern Lawn Hill Platform area of the Isa Superbasin, specifically focusing on burial and thermal history modelling. A second report will highlight the results of the source rock analysis and maturity modelling.

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 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.

This Geoscience Australia Record reports the findings of the Canning Basin Petroleum Systems Modelling Project. The southern, frontier portions of the Canning Basin have numerous potential hydrocarbon play opportunities, in particular unconventional gas plays, which remain untested. Of particular interest are Ordovician-aged petroleum systems. Geoscience Australia in collaboration with the Geological Survey of Western Australia acquired an 872 km long 2D seismic line across the south and south-west Canning Basin in 2018, and drilled the 2680 m stratigraphic hole Barnicarndy 1 in the Barnicarndy Graben to further develop the understanding of hydrocarbon prospectivity in these frontier regions. As part of the Exploring for the Future program Geoscience Australia contracted GNS Science to construct ten 1D petroleum systems models and one 2D model across the frontier southern parts of the basin. The aim was to combine interpretation of the newly acquired seismic data with interpretation of legacy and new well data, in particular organic geochemical data, to improve the understanding of the burial and thermal history, trap formation, generation and migration of hydrocarbons in the southern, frontier parts of the Canning Basin. This Record is a compilation of the work completed by GNS Science International Limited and the reports containing new data collected and analyzed relevant to the petroleum systems modelling.

Presentation from the Exploring for the Future Roadshow on the Energy prospectivity of the South Nicholson region, regional geochemical data acquisition and shale gas prospectivity analysis.

The northern Lawn Hill Platform (nLHP) is considered an emerging region with less than 15 wells drilled to date. With renewed interest in unconventional gas, new exploration opportunities exist in this early Proterozoic region. Petroleum systems analysis is presented here to improve the understanding of burial history, source rock richness and maturity of the nLHP of the Isa Superbasin, far NW Queensland. A pseudo-3D geological model was built and calibrated, in combination with 1-D burial and thermal history modelling of Desert Creek 1 and Egilabria 1. These were combined with source rock characteristics (e.g., Rock Eval and kerogen kinetics) which helped assess the hydrocarbon generation potential by source rock, allowing a broader assessment of petroleum prospectivity of the nLHP. The study focussed on two potential source rocks; the Lawn 4 Sequence and the River Supersequence. Maturity modelling of the Lawn 4 Sequence at Desert Creek 1 and Egilabria 1 predicted equivalent vitrinite reflectance (EqVR) of over 1.2% and 2%, respectively. The River Supersequence was modelled as overmature at both wells. Combining these results with the pseudo-3D model and source rock characteristics demonstrates that the highest maturities are encountered in the deepest depocentres to the east and gradually decrease in maturity to the west, indicating some potential for wet gas. Modelling results show generation of varying amounts of gas and oil from each potential source rock. Overall, due to the age of the sediments, maximum depth of burial and high paleotemperatures, the most likely hydrocarbon phase is gas from primary generation and supplemented by secondary gas from oil cracking. In spite of high maturities, encouraging gas shows from the Egilabria prospect support continued exploration interest in this region for unconventional hydrocarbons.