The Browse Basin, located offshore on Australia¿s North West Shelf, is a proven hydrocarbon province that hosts large gas accumulations with associated condensate. Small light oil accumulations are found mostly within the Cretaceous succession. Geoscience Australia undertook a multi-disciplinary study of the Browse Basin to better understand the regional hydrocarbon prospectivity and high-grade areas with increased liquids potential in Cretaceous supersequences. The sequence stratigraphy and structural framework of the Cretaceous succession were analysed to determine the spatial relationship of reservoir and seal pairs, and areas of source rock development. Updated biostratigraphy, well lithology and log analysis, seismic stratal geometry, facies, palaeogeographic and play fairway interpretations were completed for seven supersequences from the late Tithonian to Maastrichtian (K10¿K60 supersequences). These data, together with geochemical studies of source rocks and fluids (gases and liquids), were integrated in a regional petroleum systems model to better understand source rock distribution, character, generation potential, and play prospectivity. The regional deposition of the Permo-Carboniferous, Triassic, Jurassic and Cenozoic successions were mapped to constrain the burial history model. Supersequence cross-sections and palaeogeographic maps show the distribution of gross depositional facies, revealing three main Cretaceous stratigraphic play types across the basin. These are basin-margin, clinoform topset and submarine fan plays. Geochemical analyses using molecular and stable carbon and hydrogen isotopic signatures correlate fluids in these plays with potential source rocks. The geochemical fingerprints enabled the identification of four Mesozoic petroleum systems. Burial history modelling demonstrates hydrocarbon generation from potential source rocks within the Jurassic and Lower Cretaceous supersequences. Many accumulations have a complex charge history with the mixing of hydrocarbon fluids from multiple Mesozoic source rocks, as recognised from the deconvolution of their geochemical compositions. The basin margin play occurs within the K10¿K40 supersequences (Early Cretaceous upper Vulcan and Echuca Shoals formations) along the inboard Yampi and Leveque shelves. The K20¿K30 (Echuca Shoals Formation) basin margin play received gas (Caspar 1A) potentially sourced from the J10¿J20 supersequences (Plover Formation) and oil (Gwydion 1) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). Seal quality and thickness are good except where the seal facies pinch out around basement highs on the Yampi Shelf, and where they are truncated by the K50 sequence boundary (Wangarlu Formation) inboard on the Leveque Shelf. The K40 basin margin play (Jamieson Formation) received gas (Gwydion 1, Cornea field) that is most likely sourced from the J10¿J20 supersequences (Plover Formation) and oil (Cornea field) sourced from the K20¿K30 supersequences (Echuca Shoals Formation). The marine shales in the K20¿K30 supersequences (Echuca Shoals Formation) have low hydrogen indices (~200 mg hydrocarbons/gTOC) and hence may only be able to expel sufficient hydrocarbons to sustain migration over short distances. The co-existence of oil sourced from these successions and gas sourced from the J10¿J20 supersequences (Plover Formation) suggests that potential Cretaceous-sourced liquids were mobilised and carried to the shelf edge by co-migrating Early¿Middle Jurassic Plover-derived gas. Once present within these shallow reservoirs, further loss of the low and mid-chain hydrocarbons occurred through leakage, water washing and biodegradation. Together, the migration and secondary alteration processes have enhanced the liquids potential on the basin margin. The clinoform topset play extends between the basin-margin and the shelf-edge. These plays consist of higher order progradational sandstone units overlain by intraformational and top seals. The K10 clinoform topset play (namely the Brewster Member of the Upper Vulcan Formation) hosts gas in the Ichthys/Prelude and Burnside accumulations. The gas is probably largely sourced from the organic-rich shales of the J30¿K10 supersequences (Vulcan Formation), with an additional contribution from the J10¿J20 supersequences (Plover Formation) in satellite fields, such as observed at Concerto 1 ST1. Other similar K10 plays are mapped in the southern Caswell and Oobagooma sub-basins and could receive charge from J30¿K10 potential source pods. The K30 clinoform topset play (M. australis sand of the Echuca Shoals Formation) is a reservoir for gas on the Leveque Shelf at Psepotus 1, with additional evidence for oil migration into this play at Braveheart 1 in the northern Caswell Sub-basin. This play extends in underexplored areas on the Leveque Shelf to the inboard Barcoo Sub-basin and on the southern Yampi Shelf to the outboard Caswell Sub-basin. The K40 clinoform topset play (D. davidii sand of the Jamieson Formation) hosts gas (Adele 1) and light oil (Caswell 1). The light oil is probably sourced primarily from the K20¿K30 supersequences (Echuca Shoals Formation) in the central Caswell Sub-basin. This play extends outboard in the Caswell Sub-basin to Caswell 2 ST2 and Phrixus 1. The submarine fan play comprises sandstone-prone basin floor fans that extend across the basin floor from the toe of the slope and are sealed by down-lapping mudstone facies. This play may overlie either second, third, fourth or fifth-order sequence boundaries and are particularly well developed within the Upper Cretaceous K60 supersequence (Wangarlu Formation). The K30 submarine fan play (Echuca Shoals Formation) hosts gas in the outboard northern Caswell Sub-basin (Abalone Deep 1 and Adele 1). Isotopic evidence for the gas at Adele 1 suggests that the K20¿K30 supersequences (Echuca Shoals Formation) is the most likely source. This play is underexplored elsewhere within the basin, but it includes the tentatively interpreted play around Omar 1 in the Barcoo Sub-basin. There is evidence for oil migration through the K50 (Wangarlu Formation) submarine fan play at Discorbis 1, with the source of hydrocarbons possibly being from the K20¿K30 supersequences (Echuca Shoals Formation). This play extends into the inboard northern Caswell Sub-basin. The K60 submarine fan (Wangarlu Formation) play either hosts oil and gas (Abalone 1, Caswell 2 and Marabou 1) or contains evidence of hydrocarbon migration (Discorbis 1 and Gryphaea 1) in numerous wells. The most likely source of petroleum is from the K20¿K30 supersequences (Echuca Shoals Formation). The results of this study reveal the existence of multiple stacked Cretaceous plays in the basin, including those in underexplored vacant acreage. Presented at the 2017 Southeast Asia Petroleum Exploration Society (SEAPEX) Conference

<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>

<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>

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.

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.

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.

The main aim of this study is to use petroleum systems analysis to improve the understanding of the petroleum systems present on the Lawn Hill Platform of the Isa Superbasin. Part A of this report series reported the results of burial and thermal modelling of two wells (Desert Creek 1 and Egilabria 1). Results from the 1-D modelling help other aspects of interest such as the hydrocarbon generation potential and distribution of hydrocarbons by source rock which this publication presents. Modelling uncertainties are reported and described, highlighting knowledge gaps and areas for further work.

Although the Canning Basin has yielded minor gas and oil within conventional and unconventional reservoirs, the relatively limited geological data available in this under-explored basin hinder a thorough assessment of its hydrocarbon potential. Knowledge of the Paleozoic Larapintine Petroleum Supersystem is restricted by the scarcity of samples, especially recovered natural gases, which are limited to those collected from recent exploration successes in Ordovician and Permo-Carboniferous successions along the margins of the Fitzroy Trough and Broome Platform. To address this shortcoming, gases trapped within fluid inclusions were analysed from 121 Ordovician to Permian rock samples (encompassing cores, sidewall cores and cuttings) from 70 exploration wells with elevated mud gas readings. The molecular and carbon isotopic compositions of these gases have been integrated with gas compositions derived from open-file sources and recovered gases analysed by Geoscience Australia. Fluid inclusion C1–C5 hydrocarbon gases record a snapshot of the hydrocarbon generation history. Where fluid inclusion gases and recovered gases show similar carbon isotopes, a simple filling history is likely; where they differ, a multicharge history is evident. Since some fluid inclusion gases fall outside the carbon isotopic range of recovered gases, previously unidentified gas systems may have operated in the Canning Basin. Interestingly, the carbon isotopes of the fluid-inclusion heavy wet gases converge with the carbon isotopes of the light oil liquids, indicating potential for gas–oil correlation. A regional geochemical database incorporating these analyses underpins our re-evaluation of gas systems and gas–gas correlations across the basin. <b>Citation:</b> Boreham, C.J., Edwards, D.S., Sohn, J.H., Palatty, P., Chen, J.H. and Mory, A.J., 2020. Gas systems in the onshore Canning Basin as revealed by gas trapped in fluid inclusions. 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.

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.