We measured the light absorption properties of two naturally occurring Australian hydrocarbon oils, a Gippsland light crude oil and a North West Shelf light condensate. Using these results in conjunction with estimated sensor environmental noise thresholds, the theoretical minimum limit of detectability of each oil type (as a function of oil thickness) was calculated for both the hyperspectral HYMAP and multispectral Quickbird sensors. The Gippsland crude oil is discernable at layer thickness of 20 micro metres or more in the Quickbird green channel. The HYMAP sensor was found to be theoretically capable of detecting a layer of Gippsland crude oil with a thickness of 10 micro metres in approximately six sensor channels. By contrast, the North West Shelf light condensate was not able to be detected by either sensor for any thickness up to 200 icro metres. Optical remote sensing is therefore not applicable for detecting diagnostic absorption features associated with this light condensate oil type, which is considered representative for the prospective Australian Northwest Shelf area. We conclude that oil type is critical to the applicability of optical remote sensing for natural oil slick detection and identification. We recommend that a sensor- and oil-specific sensitivity study should be conducted prior to applying optical remote sensors for oil exploration. The oil optical properties were obtained using two different laboratory methods, a reflectance-based approach and transmittance-based approach. The reflectance-based approach was relatively complex to implement, but was chosen in order to replicate as closely as possible real world remote sensing measurement conditions of an oil film on water. The transmittance-based approach, based upon standard laboratory spectrophotometric measurements was found to generate results in good agreement with the reflectance-based approach. Therefore, for future oil- and sensor-specific sensitivity studies, we recommend the relatively accessible transmittance-based approach, which is detailed in this paper.

1. Blevin et al.:Hydrocarbon prospectivity of the Bight Basin - petroleum systems analysis in a frontier basin 2. Boreham et al : Geochemical Comparisons Between Asphaltites on the Southern Australian Margin and Cretaceous Source Rock Analogues 3. Brown et al: Anomalous Tectonic Subsidence of the Southern Australian Passive Margin: Response to Cretaceous Dynamic Topography or Differential Lithospheric Stretching? 4. Krassay and Totterdell : Seismic stratigraphy of a large, Cretaceous shelf-margin delta complex, offshore southern Australia 5. Ruble et al : Geochemistry and Charge History of a Palaeo-Oil Column: Jerboa-1, Eyre Sub-Basin, Great Australian Bight 6. Struckmeyer et al : Character, Maturity and Distribution of Potential Cretaceous Oil Source Rocks in the Ceduna Sub-Basin, Bight Basin, Great Australian Bight 7. Struckmeyer et al: The role of shale deformation and growth faulting in the Late Cretaceous evolution of the Bight Basin, offshore southern Australia 8. Totterdell et al : A new sequence framework for the Great Australian Bight: starting with a clean slate 9. Totterdell and Bradshaw : The structural framework and tectonic evolution of the Bight Basin 10. Totterdell and Krassay : The role of shale deformation and growth faulting in the Late Cretaceous evolution of the Bight Basin, offshore southern Australia

A recent Geoscience Australia sampling survey in the Bight Basin recovered hundreds of dredge samples of Early Cenomanian to Late Maastrichtian age. Given the location of these samples near the updip northern edge of the Ceduna Sub-basin, they are all immature for hydrocarbon generation with vitrinite reflectance - 0.5% RVmax, Tmax < 440oC and PI < 0.1. Excellent hydrocarbon generative potential is seen for marine, outer shelf, black shales and mudstones with TOC to 6.9% and HI up to 479 mg hydrocarbons/g TOC. These sediments are exclusively of Late Cenomanian-Early Turonian (C/T) in age. The high hydrocarbon potential of the C/T dredge samples is further supported by a dominance of the hydrogen-rich exinite maceral group (liptinite, lamalginite and telalginite macerals), where samples with the highest HI (> 200 mg hydrocarbons/g TOC) contain > 70% of the exinite maceral group. Pyrolysis-gas chromatography and pyrolysis-gas chromatography mass spectrometry of the C/T kerogens reveal moderate levels of sulphur compounds and the relative abundances of aliphatic and aromatic hydrocarbons predict the generation of a paraffinic-naphthenic-aromatic low wax oil in nature. Not enough oom for rest of Abstract

Numerous Miocene reefs and build-ups have been identified in the Rowley Shoals region of the central North West Shelf, offshore Western Australia. The reefs form part of an extensive Miocene reef tract over 1600 km long, which extended northward into the Timor Sea and southwards to North West Cape. Growth of the vast majority of these Miocene reefs failed to keep pace with relative sea-level changes in the latest Miocene, whereas reef growth continued on the central North West Shelf to form the three present-day atolls of the Rowley Shoals (Mermaid, Clerke and Imperieuse Reefs). Widespread buildups and atoll reefs developed in the Rowley Shoals region in the Middle Miocene, and their internal stacking geometries indicate successive aggradational, progradational and back-stepping growth phases that are correlated with eustatic sea-level fluctuations. Growth of the majority of the Miocene reefs ceased at a major sea-level fall in the late Late Miocene, and only the reefs of the present-day Rowley Shoals continued to grow after this event. The Rowley Shoals reefs continued to keep pace with Pliocene-Pleistocene sea level changes, whereas the surrounding shelf subsided to depths of 230-440 m. Contrary to previous hypotheses, we find no direct evidence that active, or palaeo, hydrocarbon seepage triggered or controlled growth of the Rowley Shoals reefs or their buried Miocene predecessors. Rather we conclude that initial reef growth was controlled by transpressional reactivation and structuring of the Mermaid Fault Zone during the early stage of collision between the Australia and Asian plates.

Invited paper by CEO.

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.

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.

Conference volume and CD are available through the Petroleum Exploration Society of Australia

D/H ratios of terrestrially-sourced whole oils and their respective saturated, aromatic, and polar fractions, individual n-alkanes, formation waters and non-exchangeable hydrogen in kerogen were measured from source rocks from seven Australian petroleum basins. Data for 75 oils and condensates, their sub-fractions, and 52 kerogens indicate that oil sub-fractions have deltaD values comparable to deltaDoil, with a deltadeltaD offset (deltaDkerogen - deltaDoil) averaging ca. 23?. The weighted-average deltaD of individual n-alkanes is usually identical to deltaDoil and deltaDsaturate. A trend of increasing deltaD with n-alkane chain length in most oils causes individual n-alkanes from an oil to vary in deltaD by 30? or more. A modest correlation between deltaD for aromatic sub-fractions and formation waters indicates that about 50% of aromatic C-bound H has exchanged with water. In contrast, deltaDoil and deltaDsaturated show no evidence for H-exchange with formation water under reservoir conditions at temperatures up to 150 oC. Acyclic isoprenoids and n-alkanes show essentially indistinguishable deltaD, indicating that primary isotopic differences from biosynthesis have been erased. Overall, extensive exchange of C-bound H in petroleum with other hydrogen is apparent, but seems to have affected most hydrocarbons only during their chemical genesis from precursor molecules. Our isotopic findings from terrestrial-sourced oils should be qualitatively relevant for marine oils as well.

Genetic relationships, identified using a combination of molecular and isotopic (carbon and hydrogen) compositions, have been found between natural gases, oils, oil stains, bitumens and potential source rocks in the onshore and offshore Otway Basin. The gas-gas, gas-oil and oil-source correlations herein challenge the validity of some previously accepted oil families and re-enforces the strong compartmentalisation of petroleum systems in the Otway Basin. Previous geochemical studies in the Otway Basin, mainly focussed on the oils and oil stains, have established that the Otway Basin hosts the most diverse array of petroleum systems within Australia. Up to five different oil families have previously been identified. These oils are sourced from a wide range of depositional environments from fresh to saline lacustrine, fluvio-lacustrine to peat swamp and marine, with suspected effective source rock ages from Late Jurassic to Late Cretaceous. Such depositional settings are consistent with the progressive development of source rocks facies intimately linked to basin development from initial rifting to thermal sag. It is now concluded that there is no indigenous representation of the saline lacustrine oil population in the Otway Basin. The geochemical signal is attributed to downhole contamination from gilsonite; a solid bitumen from the Eocene Green River Formation, USA. Oils stains are thought to be a result of primary migration from mature source rocks into juxtaposed sands and are not a strong advocate for secondary oil migration fairways. The natural gases show a strong geochemical association with their respective oils, suggesting that both are generated together from the same source. Also the gases and oils and their effective source rocks have a strong stratigraphic and geographic relationship, indicating mainly short- to medium-range migration distances from source to trap. Gas and oil in the western Otway Basin are sourced from the fluvio-lacustrine Casterton Formation?Crayfish Group sediments while in the eastern Otway Basin the gas and oil from the Shipwreck Trough and its onshore extension are from the coaly Eumeralla Formation sediments. Gas and oil in the central Otway Basin have a mixed source but predominantly are of Eumeralla Formation source Multiple charge histories are also evident with the widespread influx of overmature, dry gas focused in the western Otway Basin and more recently magmatic CO2 influx. Successive natural gas charges have the potential to displace and/or alter the composition of the pre-existing reservoired gas and oil. In-reservoir biodegradation of oil is seen in the shallower reservoirs but this is not a significant risk in the Otway Basin since nearly all reservoired petroleum is below the temperature/depth limits for biologically sustainable life.