Large-scale storage of commercially produced hydrogen worldwide is presently stored in salt caverns. Through the Exploring for the Future program, Geoscience Australia is identifying and mapping salt deposits in Australia that may be suitable for hydrogen storage. The Boree Salt in the Adavale Basin of central Queensland is the only known thick salt accumulation in eastern Australia, and represent potentially strategic assets for underground hydrogen storage. The Boree Salt consists predominantly of halite and can be up to 555 m thick in some wells. Geoscience Australia contracted CSIRO to conduct analyses four Boree Salt whole cores extracted from Boree 1 and Bury 1 wells. The tests were carried out to determine the seal capacity (mercury injection capillary pressure - MICP), mineralogy (X-ray diffraction - XRD), and inorganic geochemistry of the cores. The entire core sections were scanned using X-ray CT images. In addition, four plugs were taken from the cores and tested for dry bulk density, grain density, gas porosity, and permeability. Two plugs underwent ultra-low permeability tests. The MICP test suggests that the Boree Salt is a competent seal for hydrogen storage. Mineralogy testing (XRD) revealed that the Boree Salt samples primarily comprise halite (96.5%), minor anhydrite (1.32%) and dolomite (1.65%) with traces of quartz, calcite, sylvite and cristobalite. Inorganic geochemistry results show sodium (Na; 55.4% average) is the most abundant element. Further tests, such as the creep test, in-situ seal capacity test, and leaching tests, are required to determine the suitability of the Boree Salt for underground hydrogen storage. Disclaimer: Geoscience Australia has tried to make the information in this product as accurate as possible. However, it does not guarantee that the information is totally accurate or complete. Therefore, you should not solely rely on this information when making a commercial decision. This dataset is published with the permission of the CEO, Geoscience Australia.

Proterozoic rocks of the South Nicholson region are juxtaposed between the Mount Isa Province and the McArthur Basin. Whereas the latter two provinces are well-studied and prospective for energy and mineral resources, the geological evolution and resource potential of the South Nicholson region is not well understood. Geoscience Australia, under the Exploring for the Future (EFTF) initiative, in collaboration with State and Territory Geological Surveys, conducted a range of regional geoscience investigations to better understand the resource potential across the South Nicholson region to encourage greenfield resource exploration. Here we discuss preliminary findings on an unreported massive manganese oxide (MnO) occurrence in the Carrara Range in the South Nicholson region, north-eastern Northern Territory. The occurrence is hosted by a north-dipping quartz sandstone unit of the ca. 1640 Ma) sandstones of the Plain Creek Formation (McNamara Group), in the hanging wall of the south-verging, east-west trending Wild Cow Fault zone. The Plain Creek Formation conformably overlies the Shady Bore Quartzite, and conformably underlies shales and carbonaceous siltstones of the Lawn Hill Formation. The Plain Creek Formation is stratigraphically equivalent to the Riversleigh Siltstone in the Lawn Hill Platform. The massive MnO body is comprised of pyrolusite (MnO2) and cryptomelane (KMn8O16), surrounded by a halo of partially MnO altered host sandstone, crosscut by numerous 1‒5mm wide ‘feeder’ veinlets. These zoned veinlets consist of quartz, pyrolusite and cryptomelane with wall quartz projecting into the veinlets with Mn minerals infilling the centre of the veins. The MnO body is ~20 m wide across strike. The lateral and depth extent of the occurrence is unknown, but satellite imagery indicates that MnO mineralisation is visible, along strike, for at least several hundred metres. These observations suggest that the Carrara Range MnO occurrence is likely an epigenetic replacement stratiform body. Geochemistry on the MnO body return 49.8 wt% MnO with appreciable (ca. 450 ppm) Zn; the host sandstone return 10.8 wt% MnO and ca. 25 ppm Zn. Reconnaissance fluid inclusion analysis on quartz-MnO veinlets reveals both brine+vapour aqueous inclusions and hydrocarbon+vapour inclusions. Co-existing aqueous and hydrocarbon were not observed. Homogenisation temperatures are 90‒180°C for aqueous inclusions and 60‒140°C for hydrocarbon inclusions. Fluid salinities are 10‒23 wt% (NaCl equivalent), which may suggest interaction with evaporites. Decrepitation of the fluid inclusions yielded CO2 with no accompanying hydrocarbon gases, suggesting an oxidising fluid. The 𝛿13C CO2 of -22 ‰ is consistent with an organic source, possibly from oil oxidation. The mineralising fluids were high salinity, low temperature (ca. 120°C) fluids, typical of fluids for Mississippi-Valley and/or Mount Isa style base-metal deposits. The host Plain Creek Formation is stratigraphically equivalent to units that host world-class regional Pb-Zn deposits such as Century, McArthur River (HYC) and Lady Loretta and others of north-western Queensland and north-eastern Northern Territory. This correlation, together with the knowledge that many Pb-Zn deposits across the region are associated with manganese enrichment, increases the potential of a base metal resource in the South Nicholson region. Discovery of the Carrara Range Mn occurrence may stimulate regional base metal exploration. Abstract presented at the 2021 Australian Earth Sciences Convention (AESC)

To help the management and exploration at depth of increasing demand for mineral, energy and water resources, integration of new data acquired in frontier areas in a common 3D sub-surface geological model is critical. The Exploring for the Future Program has facilitated the acquisition of major datasets in northern Australia, where rocks are mostly undercover and the basin evolution and resource potential is not well understood. Here we present a case study in the South-Nicholson Basin, located in a vast, poorly exposed area between two highly prospective Paleo- to Mesoproterozoic provinces, the Mt Isa Province and the McArthur Basin. Both regions host major base metal mineral deposits, and contain units prospective for hydrocarbons. In this study we integrate new large-scale data, which include ~1 900 km of deep seismic reflection data and 60 000 line kilometers of AusAEM1 airborne electromagnetic survey, with legacy information and new tools, to help build a semi-continental geological framework, as input to national coverage databases and inform decision-making for mining and petroleum exploration. This study provides a 3D chronostratigraphic cover model down to the Paleoproterozoic basement. We mapped the depth to the base of geological eras, as well as deeper pre-Neoproterozoic Superbasin sequence boundaries to refine the cover model. The depth estimates are based on the interpretation, compilation and integration of boreholes, solid geology, reflection seismic, airborne electromagnetic data and depth to magnetic source estimates. These depth estimates are consistently stored in national databases. These integrated datasets inform on the basin evolution in relation to the basement architecture and provided key outcomes: 1) expanded the size of the basin, significantly increasing the extent of regional petroleum systems in the region, 2) revealed a large concealed sedimentary sub-basin interpreted to include rocks that host the world class Mount Isa Cu-Pb-Zn deposits, 3) linked the stratigraphy with correlation of prospective stratigraphic units across the region, 4) identified major crustal boundaries and structures showing evidence for crustal-scale fluid flow and localised groundwater springs. Presented at the 2020 American Geophysical Union (AGU) Fall Meeting (Online)

The Palaeoproterozoic Fraynes Formation in the Birrindudu Basin is a chronostratigraphic counterpart to the highly prospective Barney Creek Formation in the McArthur Basin. However, there is limited understanding of its source potential in comparison. As part of Geoscience Australia’s Exploring for the Future program, this study aims to assess the hydrocarbon generating potential and shale gas prospectivity of the Fraynes Formation in the exploration drillhole Manbulloo S1 through the reconstruction of original source-rock generating potential and well log interpretation. Internal units inside the Fraynes Formation were defined according to sedimentary facies. The hydrocarbon generation potential was estimated using the original TOC content, hydrogen index and thermal maturity data. The shale total porosity was re-interpreted from bulk density logs by removing the organic matter effect and adding organic porosity for the organic-rich shales. The water saturation was then updated accordingly. The maximum amount of generated gas of the organic-rich source rocks are 3969 Mcf/a-ft, 2769 Mcf/a-ft and 1912 Mcf/a-ft when assuming the kerogen compositions of 100 Type I, mix of 50-50% Type I and II, and 100% Type II, respectively. The richness of organic matter and interpreted water saturation (<100%) imply favourable shale gas prospectivity in the Fraynes Formation. This work expands our knowledge on the unconventional energy resources in the west of the greater McArthur Basin. Paper presented at the 2024 Australian Energy Producers (AEP) Conference &amp; Exhibition (https://pesa.com.au/events/2024-aep-conference-exhibition/)

Airborne electromagnetic data generated by the AusAEM Survey are shown to map mineral deposit host rocks and regional geological features within the AusAEM Survey area. We have developed new functionality in Geoscience Australia’s sample-by-sample layered earth inversion algorithm, allowing inversion of the magnitude of the combined vector sum of the X- and Z-components of TEMPEST AEM data. This functionality improves the clarity of inverted interpretation products by reducing the degree of along-line incoherency inherent to stitched 1D inversions. The new inversion approach improves the interpretability of sub-horizontal conductors, allowing better mapping of geological features under cover. Examples of geological mapping by the AusAEM survey highlight the utility of wide line spacing, regional AEM surveying to improve geological, mineral systems and groundwater resource understanding in the regions flanking outcropping mineral deposit host rocks in northern Australia. Presented at the 2019 Australasian Exploration Geoscience Conference

NDI Carrara 1 is a deep stratigraphic well completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI), in collaboration with Geoscience Australia and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-Basin, a newly discovered depocentre in the South Nicholson region. The well intersected Proterozoic sediments with numerous hydrocarbon shows, likely to be of particular interest due to affinities with the known Proterozoic plays of the Beetaloo Sub-basin and the Lawn Hill Platform, including two organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones. Alongside an extensive suite of wireline logs, continuous core was recovered from 283.9 m to total depth at 1750.8 m, providing high-quality data to support comprehensive analysis. Presently, this includes geochronology, geochemistry, geomechanics, and petrophysics. Rock Eval pyrolysis data demonstrates the potential for several thick black shales to be a source of hydrocarbons for conventional and unconventional plays. Integration of these data with geomechanical properties highlights potential brittle zones within the fine-grained intervals where hydraulic stimulation is likely to enhance permeability, identifying prospective Carrara Sub-basin shale gas intervals. Detailed wireline log analysis further supports a high potential for unconventional shale resources. Interpretation of the L210 and L212 seismic surveys suggests that the intersected sequences are laterally extensive and continuous throughout the Carrara Sub-basin, potentially forming a significant new hydrocarbon province and continuing the Proterozoic shale play fairway across the Northern Territory and northwest Queensland. This abstract was submitted and presented at the 2022 Australian Petroleum Production and Exploration Association (APPEA), Brisbane (https://appea.eventsair.com/appea-2022/)

Exploring for the Future (EFTF) is an Australian Government initiative focused on gathering new data and information about potential mineral, energy and groundwater resources across northern Australia. This area is generally under-explored and offers enormous potential for industry development, as it is advantageously located close to major global markets, infrastructure and hosts many prospective regions. In June 2020, the Hon Keith Pitt MP, Minister for Resources, Water and Northern Australia, announced a four year extension to this program with an expansion in scope to cover the whole of Australia. The energy component of EFTF aims to improve our understanding of the petroleum potential of frontier Australian basins. Building an understanding of geomechanical rock properties is key to understanding both conventional and unconventional petroleum systems as well as carbon storage and sedimentary geothermal systems. Under EFTF, Geoscience Australia has undertaken geomechanical work including stress modelling, shale brittleness studies, and the acquisition of new rock property data through extensive testing on samples from the Paleo- to Mesoproterozoic South Nicholson region of Queensland and the Northern Territory and the Paleozoic Kidson Sub-basin of Western Australia. These analyses are summarised herein. Providing baseline geomechanical data in frontier basins is essential as legacy data coverage can often be inadequate for making investment decisions, particularly where unconventional plays are a primary exploration target. As EFTF increases in scope, Geoscience Australia anticipates expanding these studies to encompass further underexplored regions throughout Australia, lowering the barrier to entry and encouraging greenfield exploration. <b>Citation:</b> Bailey Adam H. E., Jarrett Amber J. M., Wang Liuqi, Dewhurst David N., Esteban Lionel, Kager Shane, Monmusson Ludwig, Carr Lidena K., Henson Paul A. (2021) Exploring for the Future geomechanics: breaking down barriers to exploration. <i>The APPEA Journal </i><b>61</b>, 579-587. https://doi.org/10.1071/AJ20039

Led by Geoscience Australia, Exploring for the Future (EFTF) is a A$225 million Australian Government program dedicated to exploring Australia’s resource potential and boosting investment. The EFTF program energy component aimed to attract industry investment by delivering a suite of new precompetitive geoscience data in prospective Australian sedimentary basins. Through EFTF, Geoscience Australia has acquired significant amounts of new geomechanical data from underexplored onshore sedimentary basins with identified hydrocarbon prospectivity, from both legacy and newly acquired samples. These data were acquired to build a better understanding of basin sediment rock properties, particularly looking at the reservoir and seal potential of postulated unconventional and conventional targets. Four major datasets are presented herein, representing prospective intervals from the Paleozoic Canning Basin of Western Australia, the Neoproterozoic-Paleozoic Officer Basin of South Australia and Western Australia, the Paleo-Mesoproterozoic South Nicholson region of the Northern Territory and northwest Queensland, and the Paleo-Mesoproterozoic Birrindudu Basin of the Northern Territory and Western Australia. Additionally, the Paleo-Mesoproterozoic McArthur Basin of the Northern Territory is represented by a small number of analyses. Tests include unconfined compressive strength tests, laboratory ultrasonic measurements, single and multi-stage triaxial tests and Brazilian tensile strength tests. These datasets are a precompetitive resource that can facilitate investment decisions in frontier regions, helping to identify elements of conventional and unconventional hydrocarbon systems as well as providing essential data to assess geological storage opportunities. <b>Citation:</b> Bailey Adam, Dewhurst David, Wang Liuqi, Carson Chris, Anderson Jade, Butcher Grace, Henson Paul (2024) Exploring for the Future: new geomechanical data in frontier Australian basins. Australian Energy Producers Journal 64, 155-168. https://doi.org/10.1071/EP23029

Northern Australia contains extensive Proterozoic aged sedimentary basins that contain organic-rich rocks with the potential to host major petroleum and basin-hosted mineral systems (Figures 1 and 2). These intracratonic basins include the greater McArthur Basin including the McArthur and Birrindudu basins and the Tomkinson Provence (Close 2014), the Isa Superbasin and the South Nicholson Basin. The sedimentary sections within these basins are assumed to be of equivalent age and deposited under similar climatic controls resulting in correlative lithology, source facies and stratigraphic intervals. The greater McArthur Basin contains Paleoproterozoic to Mesoproterozoic organic-rich siltstones and shales with the potential to generate conventional oil and gas deposits, self-sourced continuous shale oil and shale gas targets (Munson 2014; Revie 2017; Weatherford Laboratories 2017). Exploration has focused on the Beetaloo Sub-basin where organic-rich siltstones of the Velkerri Formation contain up to 10 weight percent total organic carbon (wt % TOC) and have been assessed to contain 118 trillion cubic feet (Tcf) of gas-in-place (Munson 2014; Revie 2017; Weatherford Laboratories 2017; Revie and Normington 2018). Other significant source rocks include the Kyalla Formation of the Roper Group, the Barney Creek, Yalco and Lynott formations of the McArthur Group, the Wollogorang, and perhaps the McDermott formations of the Tawallah Group and the Vaughton Siltstone of the Balma Group in the northern greater McArthur Basin (Munson 2014). These source rocks are host to diverse play types, for example, Cote et al (2018) describes five petroleum plays in the Beetaloo Sub-basin; the Velkerri shale dry gas play, the Velkerri liquids-rich gas play, the Kyalla shale and hybrid liquid-rich gas play and the Hayfield Sandstone oil/condensate play. This highlights the large shale and tight gas resource potential of the McArthur Basin, the full extent of these resources are poorly understood and insufficiently quantified. More work is needed to characterise the source rocks, the petroleum generative potential, fluid migration pathways, the fluid types and the thermal and burial history to understand the hydrocarbon prospectivity of the basin. The Exploring for the Future (EFTF) program is a four-year (2016?-2020) $100.5 million initiative by the Australian Government conducted in partnership with state and Northern Territory government agencies, other key government, research and industry partners and universities. EFTF aims to boost northern Australia's attractiveness as a destination for investment in resource exploration. The Energy Systems Branch at Geoscience Australia has undertaken a regional study on the prospectivity of several northern Australian basins by expanding our knowledge of petroleum and mineral system geochemistry. Here we highlight some of the results of this ongoing program with a primary focus on the greater McArthur Basin. Abstract submitted to and presented at the Annual Geoscience Exploration Seminar (AGES) 2019 (https://www.aig.org.au/events/ages-2019/)

The South Nicholson region, which includes the Paleoproterozoic Isa Superbasin, the Mesoproterozoic South Nicholson Group and overlying younger sediments, is sparsely explored and has recently come into increased focus as a result of the Australian Government’s Exploring for the Future program. Previous exploration has identified potential shale gas plays within the River and Lawn supersequences of the Isa Superbasin in northwest Queensland’s northern Lawn Hill Platform region. Understanding mineralogy is important for characterising shale reservoirs, as mechanical properties such as shale brittleness are influenced by mineral composition. Mineralogy can, therefore, be utilised as a proxy for mechanical properties that are crucial to minimising risks associated with exploring for and developing shale reservoirs. This study utilises three different methods for calculating brittleness; XRD mineralogy, XRF major element geochemistry, and geomechanical properties. Results indicate highly variable mineralogy within the analysed samples, demonstrating heterogeneity in shale brittleness throughout the studied supersequences. Brittleness calculated from XRD analysis ranges from ductile to brittle with zones of brittle shales present in all supersequences. Increasing quartz and decreasing clay content is the dominant control on shale brittleness in the studied samples. Correlation between XRF major element geochemistry and XRD mineralogy is demonstrated to be moderate to poor, with brittleness derived from XRF major element geochemistry observed to be significantly higher than brittleness derived from XRD mineralogy. Conversely, brittleness derived from geomechanical properties agrees closely with XRD mineralogy derived brittleness. Hence, XRF major element geochemistry data are not recommended in the South Nicholson region to calculate brittleness. Analysis of brittleness indices from this study, in combination with total organic carbon content drawn from regional geochemical analysis in the South Nicholson region, identifies potential shale gas target intervals in the River, Term, and Lawn supersequences. Data presented on correlated well sections highlights intervals of exploration interest within these supersequences, being those depths where high organic content, brittle rocks are identified. The rocks that meet this criteria are primarily constrained to the already known potential shale gas plays of the River and Lawn supersequences. Recent data from Geoscience Australia implies that these potential shale gas plays are likely to extend from the northern Lawn Hill Platform, where they have been primarily identified to date, underneath the South Nicholson Basin and into the Carrara Sub-basin, significantly increasing their lateral extent. <b>Citation:</b> A. H. E. Bailey, A. J. M. Jarrett, L. Wang, B. L. Reno, E. Tenthorey, C. Carson & P. Henson (2022) Shale brittleness within the Paleoproterozoic Isa Superbasin succession in the South Nicholson region, Northern Australia, <i>Australian Journal of Earth Sciences, </i>DOI: 10.1080/08120099.2022.2095029