<div>Lateral variation in maturity of potential Devonian source rocks in the Adavale Basin has been investigated using nine 1D burial, thermal and petroleum generation history models, constructed using existing open file data. These models provide an estimate of the hydrocarbon generation potential of the basin. Total organic carbon (TOC) content and pyrolysis data indicate that the Log Creek Formation, Bury Limestone and shale units of the Buckabie Formation have the most potential as source rocks. The Log Creek Formation and the Bury Limestone are the most likely targets for unconventional gas exploration.</div><div>The models were constructed using geological information from well completion reports to assign formation tops and stratigraphic ages, and then forward model the evolution of geophysical parameters. The rock parameters, including facies, temperature, organic geochemistry and petrology, were used to investigate source rock quality, maturity and kerogen type. Suitable boundary conditions were assigned for paleo-heat flow, paleo-surface temperature and paleo-water depth. The resulting models were calibrated using bottom hole temperature and measured vitrinite reflectance data.</div><div>The results correspond well with published heat flow predictions, although a few wells show possible localised heat effects that differ from the basin average. The models indicate that three major burial events contribute to the maturation of the Devonian source rocks, the first occurring from the Late Devonian to early Carboniferous during maximum deposition of the Adavale Basin, the second in the Late Triassic during maximum deposition of the Galilee Basin, and the third in the Late Cretaceous during maximum deposition of the Eromanga Basin. Generation in the southeastern area appears to have not been effected by the second and third burial events, with hydrocarbon generation only modelled during the Late Devonian to early Carboniferous event. This suggests that Galilee Basin deposition was not significant or was absent in this area. Any potential hydrocarbon accumulations could be trapped in Devonian sandstone, limestone and mudstone units, as well as overlying younger sediments of the Mesozoic Eromanga Basin. Migration of the expelled hydrocarbons may be restricted by overlying regional seals, such as the Wallumbilla Formation of the Eromanga Basin. Unconventional hydrocarbons are a likely target for exploration in the Adavale Basin, with potential for tight or shale gas from the Log Creek Formation and Bury Limestone in favourable areas.</div>

<div>The Adavale Basin is located approximately 850 km west-northwest of Brisbane and southwest of Longreach in south-central Queensland. The basin system covers approximately 100,000 km2 and represents an Early to Late Devonian (Pragian to Famennian) depositional episode, which was terminated in the Famennian by widespread contractional deformation, regional uplift and erosion. </div><div>Burial and thermal history models were constructed for nine wells using existing open file data to assess the lateral variation in maturity and temperature for potential source rocks in the Adavale Basin, and to provide an estimate of the hydrocarbon generation potential in the region.</div>

Pyrolysis and bulk kinetic studies were used to investigate the hydrocarbon generation potential and source rock facies variability of the marine organic-rich rocks from the Middle Ordovician (Darriwilian) Goldwyer Formation in the Canning Basin, Western Australia. Rock Eval pyrolysis results for the analysed immature to mid-mature calcareous mudstones imply that the upper Goldwyer Sequence I samples contain oil-prone Type I kerogen, while the lower Goldwyer Sequence III samples comprise on average Type II/III oil- and gas-prone kerogen. This is supported by the pyrolysis gas chromatography (Py-GC) results that show the presence of homogenous organofacies in the Goldwyer Sequence I that comprise aliphatic molecular signatures, possibly attributed to the selective preservation of the lipid fraction derived from <i>Gloeocapsomorpha prisca</i> (<i>G. prisca</i>). The heterogeneous organofacies of the Goldwyer Sequence III contains aromatic moieties that are present in similar abundance as the aliphatic compounds. The calcareous claystones of the Goldwyer Sequence I have the capacity to generate paraffinic oil with low wax contents, whereas those of the Goldwyer Sequence III have generative potential for paraffinic-naphthenic-aromatic (P-N-A) low wax oils and gas and condensate. The temperature for hydrocarbon generation for the Type I kerogen, assuming a constant geological heating rate of 3^oC/Ma, is estimated to occur over a narrow interval between 145^oC and 170^oC for the Goldwyer Sequence I samples. Generation from the Type II/III kerogen occurs from 100°C to 160°C in the Goldwyer Sequence III samples which are significantly thermally less stable than observed for the Goldwyer Sequence I samples. The kinetics results for both sequences were used in standard thermal and burial history plots to evaluate their transformation ratio and hydrocarbon generative potential. This provided a basin-specific kinetic input for burial history modelling and a better constraint for kerogen transformation and hydrocarbon generation on the Broome Platform. <b>Citation:</b> Lukman M. Johnson, Reza Rezaee, Gregory C. Smith, Nicolaj Mahlstedt, Dianne S. Edwards, Ali Kadkhodaie, Hongyan Yu,; Kinetics of hydrocarbon generation from the marine Ordovician Goldwyer Formation, Canning Basin, Western Australia,<i> International Journal of Coal Geology</i>, Volume 232, <b>2020</b>, 103623, ISSN 0166-5162, https://doi.org/10.1016/j.coal.2020.103623.

<div>NDI Carrara 1 is a 1750 m stratigraphic drill hole completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI) in collaboration with Geoscience Australia under the Exploring for the Future program and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a recently discovered depocentre in the South Nicholson region. The drill hole intersected Cambrian and Proterozoic sediments consisting of organic-rich black shales and a thick sequence of interbedded black shales and silty sandstones with hydrocarbon shows. A comprehensive analytical program carried out by Geoscience Australia on the recovered core samples from 283 m to total depth at 1751&nbsp;m provides critical data for calibration of burial and thermal history modelling.</div><div>Using data from this drilling campaign, burial and thermal history modelling was undertaken to provide an estimate of the time-temperature maxima that the sub-basin has experienced, contributing to an understanding of hydrocarbon maturity. Proxy kerogen kinetics are assessed to estimate the petroleum prospectivity of the sub-basin and attempt to understand the timing and nature of hydrocarbon generation. Combined, these newly modelled data provide insights into the resource potential of this frontier Proterozoic hydrocarbon province, delivering foundational data to support explorers across the eastern Northern Territory and northwest Queensland.</div> <b>Citation:</b> Palu Tehani J., Grosjean Emmanuelle, Wang Liuqi, Boreham Christopher J., Bailey Adam H. E. (2023) Thermal history of the Carrara Sub-basin: insights from modelling of the NDI Carrara 1 drill hole. <i>The APPEA Journal</i><b> 63</b>, S263-S268. https://doi.org/10.1071/AJ22048

This petroleum systems summary report provides a compilation of the current understanding of petroleum systems for the Canning Basin. The contents of this report are also available via the Geoscience Australia Portal at https://portal.ga.gov.au/, called The Petroleum Systems Summary Assessment Tool (Edwards et al., 2020). Three summaries have been developed as part of the Exploring for the Future (EFTF) program (Czarnota et al., 2020); the McArthur Basin, the Canning Basin, and a combined summary of the South Nicholson Basin and Isa Superbasin region. The petroleum systems summary reports aim to facilitate exploration by summarising key datasets related to conventional and unconventional hydrocarbon exploration, enabling a quick, high-level assessment of the hydrocarbon prospectivity of the region.

<p>Northern Australia contains extensive Proterozoic-aged sedimentary basins with potential energy, mineral, and groundwater resources concealed beneath the surface. The region is remote and largely underexplored with limited data and infrastructure and therefore is considered to have high exploration risk. Exploration for hydrocarbons and basin-hosted base metals, although perceived to have very different exploration models, share a number of important similarities and key parameters. Foremost amongst these is shale geochemistry since the same reduced, organic-rich shales are both a hydrocarbon source rock and a depositional site for base metal mineralisation. Furthermore, anoxic and euxinic (anoxic with free hydrogen sulfide, H2S) water column and sediments are important for both the preservation of organic matter and as a H2S reservoir needed for precipitation of ore minerals after reaction with oxic metalliferous brines. Here we present new organic and inorganic geochemical datasets for shales in the South Nicholson Basin, Lawn Hill Platform and greater McArthur Basin, including the organic-richness of shales and the inorganic geochemistry of redox-sensitive trace metals, to demonstrate changes in water-column chemistry and favourable base metals depositional sites. Parameters such as total organic carbon (TOC) content and redox-sensitive elemental concentrations are used to identify prospective packages with hydrocarbon and base metals mineral resource potential <p>The results reveal many units in the Lawn Hill Platform, South Nicholson Basin and greater McArthur Basin contain organic-rich rocks. A cut-off value of TOC ≥ 2 wt% is used to define several shale and carbonate sequences in the region that are favourable for both hydrocarbon generation and as base metals depositional sites. Inorganic geochemistry results demonstrate a range of paleoredox conditions, from predominantly anoxic, ferruginous conditions with deviations, to sub-oxic and euxinic conditions. Future work mapping the temporal and spatial distribution of this geochemistry, in combination with other mappable geological criteria, is required to create mineral and petroleum systems models that can define prospective fairways across the basins and increase our understanding of resource potential. <p>The precompetitive data generated in this study highlight the utility of shared geochemical datasets for resource exploration in the region. More broadly, this study improves our understanding of the energy and mineral potential across northern Australia, supporting resource decision-making and investment.

Petroleum geochemical datasets and information are essential to government for evidence-based decision making on natural resources, and to the petroleum industry for de-risking exploration. Geoscience Australia’s newly built Data Discovery Portal (https://portal.ga.gov.au/) enables digital discoverability and accessibility to key petroleum geochemical datasets. The portal’s web map services and web feature services allow download and visualisation of geochemical data for source rocks and petroleum fluids, and deliver a petroleum systems framework for northern Australian basins. The Petroleum Source Rock Analytics Tool enables interrogation of source rock data within boreholes and field sites, and facilitates correlation of these elements of the petroleum system within and between basins. The Petroleum Systems Summary Assessment Tool assists the user to search and query components of the petroleum system(s) identified within a basin. The portal functionality includes customised data searches, and visualisation of data via interactive maps, graphs and geoscientific tools. Integration of the petroleum systems framework with the supporting geochemical data enables the Data Discovery Portal to unlock the value of these datasets by affording the user a one-stop access to interrogate the data. This allows greater efficiency and performance in evaluating the petroleum prospectivity of Australia’s sedimentary basins, facilitating and accelerating decision making around exploration investment to ensure Australia’s future resource wealth <b>Citation:</b> Edwards, D.S., MacFarlane, S.K., Grosjean, E., Buckler, T., Boreham, C.J., Henson, P., Cherukoori, R., Tracey-Patte, T., van der Wielen, S., Ray, J. and Raymond, O., 2020. Australian source rocks, fluids and petroleum systems – a new integrated geoscience data discovery portal for maximising data potential. In: Czarnota, K., Roach, I., Abbott, S., Haynes, M., Kositcin, N., Ray, A. and Slatter, E. (eds.) Exploring for the Future: Extended Abstracts, Geoscience Australia, Canberra, 1–4.

<div>Geoscience Australia’s Onshore Basin Inventories project delivers a single point of reference and creates a standardised national basin inventory that provides a whole-of-basin catalogue of geology, petroleum systems, exploration status and data coverage of hydrocarbon-prone onshore Australian sedimentary basins. In addition to summarising the current state of knowledge within each basin, the onshore basin inventory reports identify critical science questions and key exploration uncertainties that may help inform future work program planning and decision making for both government and industry. Volume 1 of the inventory covers the McArthur, South Nicholson, Georgina, Wiso, Amadeus, Warburton, Cooper and Galilee basins and Volume 2 expands this list to include the Officer, Perth and onshore Canning basins. Under Geoscience Australia’s Exploring for the Future (EFTF) program, several new onshore basin inventory reports are being delivered. Upcoming releases include the Adavale Basin of southern Queensland, and a compilation report addressing Australia’s poorly understood Mesoproterozoic basins. These are supported by value-add products that address identified data gaps and evolve regional understanding of basin evolution and prospectivity, including petroleum systems modelling, seismic reprocessing and regional geochemical studies. The Onshore Basin Inventories project continues to provide scientific and strategic direction for pre-competitive data acquisition under the EFTF work program, guiding program planning and shaping post-acquisition analysis programs.</div>

<div>Lateral variation in maturity of potential Devonian source rocks in the Adavale Basin have been investigated using nine 1D burial thermal and petroleum generation history models, constructed using existing open file data. These models provide an estimate of the hydrocarbon generation potential of the basin. Total organic carbon (TOC) content and pyrolysis data indicate that the Log Creek Formation, Bury Limestone and shale units of the Buckabie Formation have the most potential as source rocks. The Log Creek Formation and the Bury Limestone are the most likely targets for unconventional gas exploration.</div><div>&nbsp;</div><div>The models were constructed used geological information from well completion reports to assign formation tops and stratigraphic ages to then forward-model the evolution of geophysical parameters. The rock parameters, including facies, temperature, organic geochemistry/petrology, were used to investigate source rock quality, maturity and kerogen type. Suitable boundary conditions were assigned for paleo-heat flow, paleo-surface temperature and paleo-water depth. The resulting models were calibrated using bottom hole temperature and measured vitrinite reflectance data.</div><div>&nbsp;</div><div>The results correspond relatively well with published heat flow predictions, however a few wells show possible localised heat effects that differ from the overall basin average. The models indicate full maturation of the Devonian source rocks with generation occurring during the Carboniferous and again during the Late Cretaceous. Any potential accumulations may be trapped in Devonian sandstone, limestone and mudstone units, as well as overlying younger sediments of the Mesozoic Eromanga Basin. Accumulations could be trapped by localised deposits of the Cooladdi Dolomite and other marine, terrestrial clastic and evaporite units around the basin. Migration of the expelled hydrocarbons may be restricted by overlying regional seals, such as the Wallumbilla Formation of the Eromanga Basin. Unconventional hydrocarbons are a likely target for the Adavale Basin with potential either for tight or shale gas in favourable areas from the Log Creek Formation and Bury Limestone.</div> This Abstract was submitted/presented to the 2023 Australian Exploration Geoscience Conference 13-18 Mar (https://2023.aegc.com.au/)

The Browse Basin hosts considerable gas and condensate resources, including the Ichthys and Prelude fields that are being developed for liquefied natural gas (LNG) production. Oil discoveries are sub-economic. This multi-disciplinary study integrating sequence stratigraphy, palaeogeography and geochemical data has mapped the spatial and temporal distribution of Jurassic to earliest Cretaceous source rocks. This study allows a better understanding of the source rocks contribution to the known hydrocarbon accumulations and charge history in the basin, including in underexplored areas. The Jurassic to earliest Cretaceous source rocks have been identified as being the primary sources of the gases and condensates recovered from accumulations in the Browse Basin as follows: - The Lower–Middle Jurassic J10–J20 (Plover Formation) organic-rich source rocks have been deposited along the northeast-southwest trending fluvial-deltaic system associated with a phase of pre-breakup extension. They have charged gas reservoired within J10–J20 accumulations on the Scott Reef Trend and in the central Caswell Sub-basin at Ichthys/Prelude, and in the Lower Cretaceous K40 supersequence on the Yampi Shelf. - Late Jurassic–earliest Cretaceous J30–K10 source rocks are interpreted to have been deposited in a rift, north of the Scott Reef Trend and along the Heywood Fault System (e.g. Callovian–Tithonian J30–J50 supersequences, lower Vulcan Formation). The J30–K10 shales are believed to have sourced wet gas reservoired in the K10 sandstone (Brewster Member) in the Ichthys/Prelude and Burnside accumulations, and potentially similar plays in the southern Caswell Sub-basin. - The organic-rich source rocks observed in the Heywood Graben may be associated with deeper water marine shales with higher plant input into the isolated inboard rift. They are the potential source of fluids reservoired within the Crux accumulation, which has a geochemical composition more closely resembling a petroleum system in the southern Bonaparte Basin.