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.

<div>This study aims to understand both the burial and thermal history of the Carrara Sub-basin to further develop an understanding of possible geo-energy resources, particularly that for unconventional resources such as shale gas. A 1D and 2D model were developed using data from the above mentioned seismic and drilling campaigns, combined with previously published knowledge of the basin. This work contributes to Australia’s Future Energy Resources (AFER) Project, specifically the Onshore Basin Inventories study, which aims to promote exploration and investment in selected underexplored onshore basins. Inventory reports and petroleum systems modelling are being undertaken in select basins to highlight the oil and gas potential in underexplored provinces and to increase the impact of existing datasets.</div><div><br></div>

The greater Phoenix area in the Bedout Sub-basin has experienced recent exploration success on Australia’s North West Shelf (NWS). Oil and gas discoveries in the Triassic reservoirs of the Keraudren Formation and Locker Shale have revived interest in mapping the distribution and lateral facies variation of the Triassic succession from the Bedout Sub-basin into the adjacent underexplored Beagle and Rowley sub-basins. This multi-disciplinary study integrating structural architecture, sequence stratigraphy, palaeogeography and geochemistry has mapped the spatial and temporal distributions of Triassic source rocks on the central NWS. The Lower‒Middle Triassic palaeogeography is dominated by a deltaic system building from the Bedout Sub-basin into the Beagle Sub-basin. The oil sourced and reservoired within the Lower‒Middle Triassic sequences at Phoenix South 1 is unique to the Bedout Sub-basin, compared to other oils along the NWS. Its mixed land-plant and algal biomarker signature is most likely sourced locally by fluvial-deltaic mudstones within the TR10‒TR14 or TR15 sequences and represents a new petroleum system on the NWS. A Middle Triassic marine incursion is recorded in the Bedout Sub-basin with the development of a carbonate platform while in the Rowley Sub-basin, volcanics have been penetrated at the top of the thick Lower‒Middle Triassic sediment package. The Late Triassic palaeogeographic map suggests a carbonate environment in the Rowley Sub-basin distinct to the clastic-dominated fluvial-deltaic environment in the Beagle Sub-basin. This information combined with results of well-based geochemical analyses highlights the potential for hydrocarbon generation within the Upper Triassic in these sub-basins. This extended abstract was presented at the Australasian Exploration Geoscience Conference (AECG) 2019

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

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.

The Browse Basin is located offshore on Australia's North West Shelf and is a proven hydrocarbon province hosting gas with associated condensate and where oil reserves are typically small. The assessment of a basin's oil potential traditionally focuses on the presence or absence of oil-prone source rocks. However, light oil can be found in basins where source rocks are gas-prone and the primary hydrocarbon type is gas-condensate. Oil rims form whenever such fluids migrate into reservoirs at pressures less than their dew point (saturation) pressure. By combining petroleum systems analysis with geochemical studies of source rocks and fluids (gases and liquids), four Mesozoic petroleum systems have been identified in the basin. This study applies petroleum systems analysis to understand the source of fluids and their phase behaviour in the Browse Basin. Source rock richness, thickness and quality are mapped from well control. Petroleum systems modelling that integrates source rock property maps, basin-specific kinetics, 1D burial history models and regional 3D surfaces, provides new insights into source rock maturity, generation and expelled fluid composition. The principal source rocks are Early-Middle Jurassic fluvio-deltaic coaly shales and shales within the J10-J20 supersequences (Plover Formation), Middle-Late Jurassic to Early Cretaceous sub-oxic marine shales within the J30-K10 supersequences (Vulcan and Montara formations) and K20-K30 supersequences (Echuca Shoals Formation). All of these source rocks contain significant contributions of land-plant derived organic matter and within the Caswell Sub-basin have reached sufficient maturities to have transformed most of the kerogen into hydrocarbons, with the majority of expulsion occurring from the Late Cretaceous until present.

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.

<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>

<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.