<div>This study was commissioned by Geoscience Australia (GA) to produce a report on methane adsorption and desorption of select samples from the deep stratigraphic drill hole NDI Carrara 1, located in the Proterozoic Carrara Sub-basin in the Northern Territory. Plugs were taken from depths of interest and analysed via adsorption and desorption isotherm testing at the CSIRO laboratories in Clayton, Victoria. </div>

Report is result of a rapid geological reconnaissance of the Federal Territory made primarily to locate deposits of limestone and shale, suitable for the manufacture of Portland cement, and other materials likely to be of value in the building of the Federal City.

Studies of three global sediment-hosted zinc provinces (Mt Isa, Australia; Northern Cordillera, Canada/USA; Irish Midlands, Ireland) indicate that deposits in all three provinces are associated with gradients in many geological parameters. These include lead isotopes, the depth of the lithosphere-asthenosphere boundary, upward-continued gravity and magnetotellurics data. These gradients are interpreted to mark major cratonic boundaries, or edges, that control the distribution of these deposits in space and in time. Studies of the Mt Isa Province indicate that regional alteration has caused extensive loss of zinc, copper and cobalt, potentially providing more than sufficient metal for the known deposits. Moreover, in some cases, metal loss corresponds to changes in rock properties, possibly enabling regional mapping of zones of metal loss using geophysical data.

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/)

The Geological and Bioregional Assessments (GBA) Program is a series of independent scientific studies undertaken by Geoscience Australia and the CSIRO, supported by the Bureau of Meteorology, and managed by the Department of Agriculture, Water and the Environment. The Program consists of three stages across three regions with potential to deliver gas to the East Coast Gas Market. Stage 1 was a rapid regional prioritisation conducted by Geoscience Australia, to identify those sedimentary basins with the greatest potential to deliver shale and/or tight gas to the East Coast Gas Market within the next five to ten years. This prioritisation process assessed 27 onshore eastern and northern Australian basins with shale and/or tight gas potential. Further screening reduced this to a shortlist of nine basins where exploration was underway. The shortlisted basins were ranked on a number of criteria. The Cooper Basin, the Beetaloo Sub-basin and the Isa Superbasin were selected for more detailed assessment. Stage 2 of the program involved establishing a baseline understanding of the identified regions. Geoscience Australia produced regional geological evaluations and conceptualisations that inform the assessment of shale and/or tight gas prospectivity, ground- and surface-water impacts, and hydraulic fracturing models. Geoscience Australia’s relative prospectivity assessments provide an indication of where viable petroleum plays are most likely to be present. These data indicate areal and stratigraphic constraints that support the program’s further work in Stage 3, on understanding likely development scenarios, impact assessments, and causal pathways. <b>Citation:</b> Hall Lisa S., Orr Meredith L., Lech Megan E., Lewis Steven, Bailey Adam H. E., Owens Ryan, Bradshaw Barry E., Bernardel George (2021) Geological and Bioregional Assessments: assessing the prospectivity for tight, shale and deep-coal resources in the Cooper Basin, Beetaloo Subbasin and Isa Superbasin. <i>The APPEA Journal</i><b> 61</b>, 477-484. https://doi.org/10.1071/AJ20035

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

The South Nicholson region of northwest Queensland and the Northern Territory is the focus of a regional hydrocarbon prospectivity assessment being undertaken by the Exploring for the Future (EFTF) program, an Australian Government initiative dedicated to increasing investment in resource exploration in northern Australia. This data release provides data from new digital photography, X-ray Computerised Tomography (XCT) scanning, unconfined compressive strength (UCS) testing and laboratory ultrasonic testing for 14 samples from stratigraphic and exploration wells drilled into the South Nicholson Basin and Lawn Hill Platform in the South Nicholson region described in Jarrett et al (2020). These samples were analysed at CSIRO Geomechanics and Geophysics Laboratory in Perth during May and June 2020.

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/)