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 Network Capacity Mapping Tool (NCMT) provides the capability to view Western Power’s current and proposed electrical network in the southern region of Western Australia.

An updated National Seismic Hazard Assessment of Australia was released in 2018 (the NSHA18). This assessment leveraged off advances in earthquake-hazard science in Australia and analogue tectonic regions to offer many improvements over its predecessors. The outcomes of the assessment represent a significant shift in the way national-scale seismic hazard is modelled in Australia, and so challenged long-held notions of seismic hazard amongst the Australian seismological and earthquake engineering community. The NSHA18 is one of the most complex national-scale seismic hazard assessments conducted to date, comprising 19 independent seismic source models (contributed by Geoscience Australia and third-party contributors) with three tectonic region types, each represented by at least six ground motion models each. The NSHA18 applied a classical probabilistic seismic hazard analysis (PSHA) using a weighted logic tree approach, where the model weights were determined through two structured expert elicitation workshops. The response from the participants of these workshops was overwhelmingly positive and the participants appreciated the opportunity to contribute towards the model’s development. Since the model’s publication, Geoscience Australia has been able to reflect on the choices made both through the expert elicitation process and through decisions made by the NSHA18 team. The consequences of those choices on the production of the final seismic hazard model may not have been fully appreciated prior to embarking on the development of the NSHA18, nor during the expert elicitation workshops. The development of the NSHA18 revealed several philosophical challenges in terms of characterising seismic hazard in regions of low seismicity such as Australia. Chief among these are: 1) the inclusion of neotectonic faults, whose rupture characteristics are underexplored and poorly understood; 2) processes for the adjustment and conversion of historical earthquake magnitudes to be consistently expressed in terms of moment magnitude; 3) the relative weighting of different seismic-source classes (i.e., background, regional, smoothed seismicity, etc) for different regions of interest and exceedance probabilities; 4) the assignment of Gutenberg-Richter b-values for most seismic source models based on b-values determined from broad neotectonic domains, and; 5) the characterisation and assignment of ground-motion models used for different tectonic regimes. This paper discusses lessons learned through the development of the NSHA18, identifies successes in the expert elicitation and modelling processes, and explores some of the abovementioned challenges that could be reviewed for future editions of the model. Abstract presented at the 17th World Conference on Earthquake Engineering (17WCEE )

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

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 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.

Northern Australia contains extensive Proterozoic aged sedimentary basins that contain organic-rich rocks with the potential to host major petroleum and basin-hosted mineral systems (Figures 1 and 2). These intracratonic basins include the greater McArthur Basin including the McArthur and Birrindudu basins and the Tomkinson Provence (Close 2014), the Isa Superbasin and the South Nicholson Basin. The sedimentary sections within these basins are assumed to be of equivalent age and deposited under similar climatic controls resulting in correlative lithology, source facies and stratigraphic intervals. The greater McArthur Basin contains Paleoproterozoic to Mesoproterozoic organic-rich siltstones and shales with the potential to generate conventional oil and gas deposits, self-sourced continuous shale oil and shale gas targets (Munson 2014; Revie 2017; Weatherford Laboratories 2017). Exploration has focused on the Beetaloo Sub-basin where organic-rich siltstones of the Velkerri Formation contain up to 10 weight percent total organic carbon (wt % TOC) and have been assessed to contain 118 trillion cubic feet (Tcf) of gas-in-place (Munson 2014; Revie 2017; Weatherford Laboratories 2017; Revie and Normington 2018). Other significant source rocks include the Kyalla Formation of the Roper Group, the Barney Creek, Yalco and Lynott formations of the McArthur Group, the Wollogorang, and perhaps the McDermott formations of the Tawallah Group and the Vaughton Siltstone of the Balma Group in the northern greater McArthur Basin (Munson 2014). These source rocks are host to diverse play types, for example, Cote et al (2018) describes five petroleum plays in the Beetaloo Sub-basin; the Velkerri shale dry gas play, the Velkerri liquids-rich gas play, the Kyalla shale and hybrid liquid-rich gas play and the Hayfield Sandstone oil/condensate play. This highlights the large shale and tight gas resource potential of the McArthur Basin, the full extent of these resources are poorly understood and insufficiently quantified. More work is needed to characterise the source rocks, the petroleum generative potential, fluid migration pathways, the fluid types and the thermal and burial history to understand the hydrocarbon prospectivity of the basin. The Exploring for the Future (EFTF) program is a four-year (2016?-2020) $100.5 million initiative by the Australian Government conducted in partnership with state and Northern Territory government agencies, other key government, research and industry partners and universities. EFTF aims to boost northern Australia's attractiveness as a destination for investment in resource exploration. The Energy Systems Branch at Geoscience Australia has undertaken a regional study on the prospectivity of several northern Australian basins by expanding our knowledge of petroleum and mineral system geochemistry. Here we highlight some of the results of this ongoing program with a primary focus on the greater McArthur Basin. Abstract submitted to and presented at the Annual Geoscience Exploration Seminar (AGES) 2019 (https://www.aig.org.au/events/ages-2019/)

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.

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 AEMO Electricity Transmission Lines Diagrams are a schematic overview of the main transmission networks and interconnections for each region of the National Electricity Market (NEM) high voltage transmission network