The Source Rock and Fluids Atlas delivery and publication services provide up-to-date information on petroleum (organic) geochemical and geological data from Geoscience Australia's Organic Geochemistry Database (ORGCHEM). The sample data provides the spatial distribution of petroleum source rocks and their derived fluids (natural gas and crude oil) from boreholes and field sites in onshore and offshore Australian basins. The services provide characterisation of source rocks through the visualisation of Pyrolysis, Organic Petrology (Maceral Groups, Maceral Reflectance) and Organoclast Maturity data. The services also provide molecular and isotopic characterisation of source rocks and petroleum through the visualisation of Bulk, Whole Oil GC, Gas, Compound-Specific Isotopic Analyses (CSIA) and Gas Chromatography-Mass Spectrometry (GCMS) data tables. Interpretation of these data enables the characterisation of petroleum source rocks and identification of their derived petroleum fluids that comprise two key elements of petroleum systems analysis. The composition of petroleum determines whether or not it can be an economic commodity and if other processes (e.g. CO2 removal and sequestration; cryogenic liquefaction of LNG) are required for development.

The Source Rock and Fluids Atlas delivery and publication services provide up-to-date information on petroleum (organic) geochemical and geological data from Geoscience Australia's Organic Geochemistry Database (ORGCHEM). The sample data provides the spatial distribution of petroleum source rocks and their derived fluids (natural gas and crude oil) from boreholes and field sites in onshore and offshore Australian basins. The services provide characterisation of source rocks through the visualisation of Pyrolysis, Organic Petrology (Maceral Groups, Maceral Reflectance) and Organoclast Maturity data. The services also provide molecular and isotopic characterisation of source rocks and petroleum through the visualisation of Bulk, Whole Oil GC, Gas, Compound-Specific Isotopic Analyses (CSIA) and Gas Chromatography-Mass Spectrometry (GCMS) data tables. Interpretation of these data enables the characterisation of petroleum source rocks and identification of their derived petroleum fluids that comprise two key elements of petroleum systems analysis. The composition of petroleum determines whether or not it can be an economic commodity and if other processes (e.g. CO2 removal and sequestration; cryogenic liquefaction of LNG) are required for development.

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.

Small-angle neutron scattering (SANS) measurements were performed on 32 rock samples from the southern Georgina Basin, central Australia to assess nanopore anisotropy. Anisotropy can only be determined from oriented core material, hence the samples were cut perpendicular to bedding in cores selected from three wells that intersect the base of the hydrocarbon-bearing, organic-rich middle Cambrian Arthur Creek Formation; the latter is the source rock for both unconventional and conventional plays in the basin. The evolution of anisotropy of two-dimensional SANS intensity profiles with depth (for pore diameters ranging from 10 nm to 100 nm) was quantified and correlated with SANS intensity and total organic carbon (TOC) content. Our results confirm hydrocarbon generation at the base of the Arthur Creek Formation. The nanopore anisotropy in the basal Arthur Creek Formation at the well locations CKAD0001 (oil generation window) and MacIntyre 1 (late oil generation window) varies roughly according to normal compaction. When the Arthur Creek Formation is in the gas window, as sampled at Baldwin 1, there is a strong (negative) correlation between the average vertical-to-horizontal pore shape anisotropy and SANS intensity. The results indicate that unconventional gas production from organic-rich regions of over mature shale may be adversely affected by abnormal pore compaction.

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.

<p>The Paleoproterozoic Isa Superbasin and the Mesoproterozoic South Nicholson Basin in the Northern Territory and northwestern Queensland contain organic rich sedimentary units with the potential to host both conventional and unconventional petroleum systems (Gorton & Troup, 2018). On the Lawn Hill Platform, the River and Lawn supersequences of the Isa Superbasin host the recently discovered Egilabria shale gas play and are considered highly prospective shale gas targets. However, the lateral extent of these plays is currently unknown due to the limited well and associated geochemical data. Until recently, little attention had been given to the petroleum prospectivity of the Mesoproterozoic South Nicholson Basin; however there is evidence to suggest that these units also contain potential source rocks. For example, shale in drill core NTGS 00/1 Soudan, tentatively assigned as the Mullera Formation, has a reported TOC value of 3.5 wt% indicating good source rock potential (Carr et al. 2016 and references therein). Additionally, the Mullera Formation is considered equivalent to the Roper Group of the McArthur Basin (Carr et al. 2016), where shales of the Kyalla and Velkerri Formations host commercial quantities of shale gas (e.g. Revie, 2018). <p>The Energy component of Geoscience Australia’s Exploring for the Future (EFTF) program is aimed at improving our understanding of the petroleum resource potential of northern Australia, including the Lawn Hill Platform region, through delivery of a suite of new pre-competitive geoscience data and knowledge. To aid in the identification of new areas with the potential to host active petroleum systems, and to target future areas for study as part of the EFTF program, this report assesses the organic richness, quality and thermal maturity of source rocks of the South Nicholson Basin (South Nicholson Group) and Isa Superbasin (Fickling and McNamara groups). This assessment is based on a compilation of updated and quality controlled publicly available total organic carbon (TOC), Rock-Eval pyrolysis and organic matter reflectance data. Furthermore, hydrocarbon shows for the region were compiled primarily based on well completion reports and supplementary petroleum reports. <p>Seven source rocks are investigated within the Isa Superbasin and a further two in South Nicholson Basin. For the Fickling and McNamara groups of the Isa Superbasin, source rock statistics are presented by supersequence (River, Lawn, Loretta, Term, Wide, Gun and Doom supersequences). In the South Nicholson Basin, where no sequence stratigraphic framework has yet been defined, source rock statistics are presented by lithostratigraphic unit. Shales from the River and Lawn supersequences have excellent source rock potential, as is evident from the multiple gas shows. Source rocks of the River and Lawn supersequences are typically organic rich (River: average TOC 2.2 wt%, maximum 11.7 wt%; Lawn: average TOC 3.3 wt%, maximum 7.1 wt%). However, the high maturity of the analysed sediments (Lawn: Tmax average 503°C ± 87°C) indicates that the kerogen has effectively expelled hydrocarbons (HI = 21 ± 27 mg HC/ g TOC), making original source rock quality difficult to determine. <p>The Loretta, Term and Wide supersequences have a large spread of TOC values. The average TOC for all supersequences is < 1 wt%, with maximum values of 2 wt%, 5 wt% and 7 wt% respectively, demonstrating poor to good source potential. The wide range of source potential may be a product of the mixed lithologies contained within each supersequence, which include sandstone, carbonaceous shale, micaceous siltstone and organic rich siltstone. The Loretta Supersequence kerogens contain the potential to generate gas and condensate (HI = 112 ± 43 mg HC/ g TOC) over a large area from drillcores ND2 to Amoco 83-4 in the CALVERT HILLS and WESTMORELAND 1:250 000 Sheet areas respectively. The Term and Wide Supersequences require more Tmax data for a statistical analysis. The Gun and Doom supersequences appear organically lean with an average TOC < 1 wt%. However, data is extremely limited (n = 4 and 7 respectively). Gun Supersequence sediments appear to be affected by oil staining and hence warrant further investigation into their oil or condensate potential. <p>Source rocks in the South Nicholson Group contain poor to good potential to generate gas (Constance Sandstone: HI = 49 ± 27 mg HC/g TOC; Mullera Formation: HI = 49 ± 37 mg HC/g TOC). TOC averages < 1 wt% for both the Constance Sandstone and Mullera Formation with a maximum value of 1.2 wt% in the Constance Sandstone (fair gas potential) and 3.5 wt% in the Mullera Formation (good gas potential). <p>This is the first regional synthesis of source rock data sampled from the South Nicholson Basin and Fickling and McNamara groups of the Isa Superbasin and builds on the previous North Australian Basins Resource Evaluation (NABRE) studies of the 1990s. The resulting source rock statistics provide the baseline data for targeting future work within the EFTF program. Although nine stratigraphic intervals are described as a potential source rocks, data coverage is extremely limited and a large proportion of the available data is old and of poor quality. To more comprehensively characterise these organic rich source rocks, higher resolution coverages of pre-competitive geochemical data is required. In addition, future work is needed to improve our understanding of the geochemistry of generated fluids and how these correlate with source rocks. Such studies, in addition to having a robust lithostratigraphic and sequence stratigraphic framework, will assist in accurate petroleum systems analysis and future resource assessment studies.

The ca. 1.5–1.3 Ga Roper Group of the greater McArthur Basin is a component of one of the most extensive Precambrian hydrocarbon-bearing basins preserved in the geological record, recently assessed as of 429 million bbl oil (68 million cubic meters of oil) and between 8 and 118 TCF (222.56 billion cubic meters) of gas (in place). It was deposited in an intracratonic sea, referred to here as the McArthur-Yanliao gulf. The Velkerri Formation forms the major deep-water facies of the Roper Group. Trace metal redox proxies from this formation indicate that it was deposited in stratified waters, in which a shallow oxic layer overlay suboxic to anoxic waters. These deep waters became episodically euxinic during periods of high organic carbon export. The Velkerri Formation has organic carbon contents that reach ∼10 wt. %. Variations in organic carbon isotopes are consistent with organic carbon enrichment being associated with increases in primary productivity and export, rather than flooding surfaces or variations in mineralogy. Although deposition of the Velkerri Formation in an intracontinental setting has been well established, recent global reconstructions show a broader mid to low latitude gulf, with deposition of the Velkerri Formation being coeval with the widespread deposition of organic-rich rocks across northern Australia and northern China. The deposition of these organic-rich rocks may have been accompanied by significant oxygenation associated with such widespread organic carbon burial during the Mesoproterozoic. <b>Citation:</b> Grant M. Cox, Alan S. Collins, Amber J. M. Jarrett, Morgan L. Blades, April V. Shannon, Bo Yang, Juraj Farkas, Philip A. Hall, Brendan O’Hara, David Close, Elizabeth T. Baruch; A very unconventional hydrocarbon play: The Mesoproterozoic Velkerri Formation of northern Australia. <i>AAPG Bulletin</i> 2022;; 106 (6): 1213–1237. doi: https://doi.org/10.1306/12162120148

The Roebuck Basin and the adjoining Beagle and Barcoo sub-basins are underexplored areas on Australia’s North West Shelf that are undergoing renewed exploration interest since the discovery of oil at Phoenix South 1 in 2014 and subsequent hydrocarbon discoveries in the Bedout Sub-basin. A well folio of 24 offshore wells across the Beagle, Bedout, Rowley and Barcoo sub-basins has been compiled as part of Geoscience Australia’s hydrocarbon prospectivity assessment across the region. It consists of composite well log plots and well correlations that summarise lithology, lithostratigraphy, Geoscience Australia’s newly acquired biostratigraphic and geochemical data as well as results of petrophysical analysis. A revised sequence-stratigraphic interpretation, key petroleum system elements and drilling results are also documented. The wells dominantly target Triassic shoreward facies (Keraudren Formation) as the primary reservoir objective and Jurassic fluvial-deltaic (Depuch Formation) and/or Lower Cretaceous sandy deltaic facies as the secondary objective. The Keraudren Formation sandstones are sealed intra-formationally either by discontinuous units and/or by the regional Cossigny Member. The Jurassic Depuch Formation sandstones are sealed by regional Lower Cretaceous mudstones. Both charge and structure have been identified as critical issues in the Roebuck Basin. In the Beagle Sub-basin, seal integrity and migration pathways are also considered high risk. Well correlations have identified differences in the basin history and provide insights into the distribution of facies and other characteristics of the Jurassic and Triassic successions. <b>Citation:</b> Nguyen Duy, Rollet Nadege, Grosjean Emmanuelle, Edwards Dianne S., Abbott Steve, Orlov Claire, Bernardel George, Nicholson Chris, Kelman Andrew, Khider Kamal, Buckler Tamara (2019) The Roebuck Basin, Beagle and Barcoo Sub-basin well folio. <i>The APPEA Journal</i><b> 59</b>, 920-927.

The Energy component of Geoscience Australia’s Exploring for the Future (EFTF) program is aimed at improving our understanding of the petroleum resource potential of northern Australia, including the Lawn Hill Platform region of the Isa Superbasin. The Paleoproterozoic Isa Superbasin in northwestern Queensland contains organic rich sedimentary units with the potential to host both conventional and unconventional petroleum systems (Gorton & Troup, 2018). On the Lawn Hill Platform, the River and Lawn supersequences of the Isa Superbasin host the recently discovered Egilabria shale gas play and are considered highly prospective shale gas targets. However, the lateral extent of these plays is currently unknown due to the limited well and associated geochemical data. To aid in the identification of new areas with the potential to host active petroleum systems, this work assesses the burial and thermal history of the Lawn Hill Platform (Figure 1) by using organic richness, quality and thermal maturity of source rocks of the Isa Superbasin. This assessment is based on a compilation of updated and quality controlled publicly available total organic carbon (TOC), Rock-Eval pyrolysis and organic matter reflectance data, and combines revised assessments of the depth structure and isopach mapping by Bradshaw et al., (2018, in press). Burial-thermal relationships in the basin have been difficult to determine in the past, usually attributed to multiple hydrothermal events which has resulted in erratic, and occasionally inverted, maturity reflectance profiles (Gorton and Troup, 2018; Glikson, 1993). Additional difficulties that contribute large uncertainties to our understanding are estimating the burial history across the basin, especially the maximum depth of burial and hence the estimated amount of erosion. Initial modelling suggests erosion amounts could range anywhere from several hundreds of meters to several thousands of meters across the Lawn Hill Platform region (Figure 2). Burial and thermal history modelling is calibrated using paleo-maturity data (reflectance profiles as mentioned above, Figure 2), which is poorly constrained. Because of the age (Paleoproterozoic) of the organic matter, reflectance values of alginite and bitumen were used, which are not always comparable to the standard vitrinite reflectance profiles that are typically used for burial and thermal history modelling calibration. In this study other options of burial-thermal model calibrations were assessed to aid in characterising the petroleum potential of this region, including; bottom hole temperature, developing an improved Tmax conversion equation specific to the Isa Superbasin region, using published conversion equations to convert alginite and bitumen reflectance to vitrinite equivalent reflectance, using HI as an indicator of thermal history, oxygen isotopes (δ18O), and fluid inclusion geothermometry. Abstract and poster for presentation at the Australian Organic Geochemistry Conference 2018

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.