Surficial marine sediments are an important source of nutrients for productivity and biodiversity yet the biogeochemistry of these sediments is poorly known in Australia. Seabed samples were collected at >350 locations in Australia’s western, northern and eastern continental margins during federal government surveys (2007-2014). Parameters analysed included measures of organic matter (OM) source (δ13C, δ15N and C:N-ratios), concentration (total organic carbon (%TOC) and surface area normalised TOC (OC:SA)) and bioavailability (chlorin indices, total reactive chlorins, total oxygen uptake, total sediment metabolism (TSM), sediment oxygen demand (SOD) and SOD and TSM normalised to TOC). The aim of this study is to summarise these biogeochemical ‘baseline’ data, and make contextualised inferences about processes that govern the observed concentrations. The OM was mainly from marine sources and OC:SA broadly reflected water column productivity (MODIS). Approximately 40% of sediments were organic-poor by global standards reflecting seawater oligotrophy; ~12% were organic-rich due to benthic production, high water column productivity and pockmark formation. OM freshness varied due to pigment degradation in water columns and dilution with refractory OM in reworked sediments. δ15N values confirmed the importance of N2 fixation to Timor Sea productivity, and point to recycling of fixed nitrogen within food chains in Western Australia. <b>Citation:</b> Radke Lynda, Nicholas Tony, Thompson Peter A., Li Jin, Raes Eric, Carey Matthew, Atkinson Ian, Huang Zhi, Trafford Janice, Nichol Scott (2017) Baseline biogeochemical data from Australia’s continental margin links seabed sediments to water column characteristics. <i>Marine and Freshwater Research</i> <b>68</b>, 1593-1617. https://doi.org/10.1071/MF16219

First paragraph of abstract: The importance of organic sulphur fixation in the preservation of organic matter in humic coal-forming environments is demonstrated in this thesis. The transgression of coal depositional systems by marine waters during their deposition and early diagenesis enables the production of reduced inorganic sulphur species by sulphate-reducing bacteria. The presence of these reactive sulphur species, in combination with the altered chemical and microbial regime, influences the preservation and petroleum potential of humic coal.

This Record presents a new stratigraphic interpretation of Cretaceous sedimentary rocks encountered in petroleum exploration wells, stratigraphic holes and water bores along the southern Australian coast in Western Australia and South Australia. The Cretaceous succession in these wells is interpreted within the Bight Basin sequence stratigraphic framework, and is correlated with the thicker section farther basinward. The correlation is based on existing and recently commissioned biostratigraphic data, and the interpretation of seismic data on the continental shelf. The onshore wells contain a sedimentary section ranging in age from Valanginian to Campanian, and attributable to the Bronze Whaler, Blue Whale-White Pointer, Tiger and Hammerhead supersequences. The succession reaches a maximum thickness of more than 357 m in the Madura 1 well. The section preserved in these wells records the evolution of depositional environments near the northern margin of the Bight Basin, from areally restricted non-marine deposition in the Early Cretaceous, through increasingly marine, although shallow and anoxic, conditions, to the local development of a small deltaic complex in the Late Cretaceous. Organic-rich non-marine shales of Early Cretaceous age, and Late Cretaceous organic-rich facies of marine affinity have been identified in wells in the study area., providing new information about the nature and extent of potential source rocks in the Bight Basin.

This Record presents a summary of an analysis of 21 offshore Otway Basin wells (Appendix 1) based on data provided in open file Well Completion Reports (WCRs) and Geoscience Australia online databases. Additional data and interpretations are drawn from the large body of published material on the basin. Analysis was inhibited in some cases by the quantity of data in WCRs, specifically the paucity of maps provided in the interpretive sections. Fortunately, most well analyses appear to have a determination of the reason/s for failure that is reasonably clear even without maps. The end product is primarily focused on individual well results, specifically success and failure analysis. To put the wells in a geological perspective, the introduction outlines briefly the regional geologic setting, distilling the ideas of many workers through the basin's exploration history. The final section presents a petroleum systems focused summary of the main findings of the work. From this, critical risks have been identified and areas of higher or additional potential have been indicated.

We have demonstrated for the first time the application of a small angle neutron scattering (SANS) technique for the precise determination of the onset of hydrocarbon transport (primary migration) in shaly source rocks. We used a sequence of rocks pyrolysed in the laboratory under nitrogen at temperatures in the range 310-370°C. These rocks contained several percent of dispersed marine Type II organic matter. Geochemical analysis indicated a peak of the hydrocarbon generation in the middle of the temperature range (at 340°C). We observed a sharp decrease of SANS intensity in a narrow maturity range within the geochemically determined region of the onset of hydrocarbon generation. This decrease was a direct consequence of the SANS contrast variation caused by the invasion of the pore space by bitumen during the primary migration of hydrocarbons. A similar phenomenon was observed for a natural maturity sequence of source rocks originating from the same location.

The transgression of coal depositional systems by marine waters enables the preservation of functionalised lipids, such as steranes, hopanes and higher plant triterpanes, via their reaction with reduced inorganic sulphides produced by sulphate-reducing bacteria. Using compound specific isotopic analysis, higher plant and microbial sources of these lipids can be identified. The carbon isotopic compositions of the lipids are invariant to differences in the degree or timing of marine incursion. This indicates that the introduction of marine waters at any stage of mire and peat development preserves the inherited lipid composition and does not overwhelm this biotic signature during sulphate reduction. Consequently, the selective preservation of certain biomarkers enables their use in the reconstruction of coal palaeoenvironments and facilitates oil-source rock correlations. The presence of these coal-derived chemical markers in crude oils is testament to the petroleum generation potential of marine-influenced coals.

A prospectivity assessment of the offshore northern Perth Basin, Western Australia, was undertaken as part of the Australian Goverment's Offshore Energy Security Program.

To date, compositional information and compound specific isotope analysis (CSIA) of stable carbon isotopes for individual C1 to C5 gaseous hydrocarbons has been the primary data for the interpretation on Australian natural gases (Boreham et al., 2001). Here we report for the first time the stable hydrogen isotopic composition (D/H ratio) of the C1 to C5 gaseous hydrocarbons in Australian natural gases. The influence of source, maturity and in-reservoir alteration (biodegradation) is documented, and in combination with complementary carbon isotope data, this provides a powerful tool for the study of the origin and correlation of the natural gas. Source influences in Australian natural gases from Australian sedimentary basins show a wide range in hydrogen isotopes with ?D ca. 160 ? for both methane (?D -290 to -135 ?) and iso-butane (?D -255 to -94 ?). On the other hand, the isotopic range for carbon isotopes is an order of magnitude less, ?13C of 17 ? and 13 ? for methane (?13C -48.5 to 31.5 ?) and iso-butane (?13C -35.4 to -22.5 ?), respectively (Boreham et al., 2001). The source rock ages of the natural gases cover most of the Phanerozoic, from Ordovician in the Amadeus Basin to Early Eocene in the Bass Basin. Gases generated from older marine source rocks are most depleted in deuterium whereas gases sourced from the younger terrestrial coals are amongst the most enriched in D; carbon isotopes also show a similar response to age and source organic facies. Biodegradation of natural gas from the Carnarvon Basin produces a drier gas, due to the addition of biogenic methane and selective removal of wet gas components in the order propane > n-butane ? n?pentane > i-pentane > ethane ? i-butane. The addition of isotopically light biogenic methane leads to an overall isotopic shift of ?13C = ?11.5 ? compared to the non-biodegraded thermogenic gas, whereas the hydrogen isotopes remain unchanged. This, coupled with the enrichment in 13C of the associated CO2 suggests a role for anaerobic methanogenic bacteria. For the wet gas components maximum isotopic enrichments of ?13C = 18.2 ? (Boreham et al., 2001) and in ?D of 225 ? occur for those components that have been almost completely biodegraded. The strong positive correlation between carbon and hydrogen isotopes for the individual wet gas components implies a kinetic control on the isotopic composition, consistent with a biological-mediated process. The response of ?D to maturity is less attenuated compared to source and biodegradation effects. A maturation sequence from mature oil-associated wet gas to highly overmature dry gas from the Cooper Basin shows a ?13C enrichment of 15 ? for methane, with less isotopic enrichment in the wet gas components (Boreham et al., 2001). Such a maturity range in carbon isotopes for methane relates to a vitrinite reflectance range between 0.9 to 7.0% (Schoell, 1983), which is consistent with measured source rock maturities in the Cooper Basin (Boreham and Hill, 1998). On the other hand, ?D varies by ca. 50 ? for methane (?D -162 to -116 ?), with a lower isotopic enrichment observed for the wet gas components. The strong correlation shown between hydrogen and carbon isotopes in natural gas components suggests that isotopic exchange with external hydrogen sources (eg. water) is not a significant process. This contrasts with liquid hydrocarbon components where it appears that scrambling of the hydrogen isotopes occurs during oil generation (Schimmelman et al., in press). Furthermore, the relative insensitivity in ?D to maturity effects enhances the potential of CSIA for D/H ratios becoming an important isotopic tool in gas-gas (and gas-oil) correlation where the influence of source is of primary interest.

<p>The Oils of Australia Series comprises a trilogy of reports on the molecular (biomarker) and isotopic fingerprinting of Australia's oils and condensates compiled by Geoscience Australia and GeoMark Research of Houston. The series includes The Oils of Western Australia I (1996), The Oils of Eastern Australia (2002) and The Oils of Western Australia II (2005). <p>These studies have geochemically characterised Australia's petroleum accumulations into genetically related families. These data sets provide the exploration industry with an understanding of the petroleum systems operating in Australia's basins, and indicate their importance to future exploration.

A study of the Strahan Sub-basin in particular, and the wider Sorell Basin in general, has revealed the likely presence of an active hydrocarbon generation, migration, leakage and seepage system along the West Tasmanian Margin (WTM). 2D basin modelling of seismic data has demonstrated that a previously identified, high-quality Maastrichtian source interval is unlikely to contribute significantly to hydrocarbon inventories in the region. However. an interpreted deeper Cretaceous source rock has been sufficiently mature to expel hydrocarbons over much of the sub-basin since the Early Tertiary. Combining the seismic mapping and modelling of this deeper source facies with the mapping of hydrocarbon leakage indicators such as gas chimneys and carbonate build-ups has shown that active, present day hydrocarbon leakage and seepage is restricted to fault arrays immediately to the north-west of, and up-dip from, a thermally mature, Cretaceous source system. These observations demonstrate that a deeper source system is working but do not reveal whether the source system is oil-, condensate- or gas-prone. In one area, strong seismic evidence for present day seepage at the seafloor was observed, with the likely formation of methane-derived authigenic carbonates located directly above seismically prominent chimneys. The fact that the faults up-dip from the mature source leak raises the issue of how much of the generated hydrocarbons have been preserved in this area. Interpretation of new Synthetic Aperture Radar (SAR) data revealed a very low density of natural oil slicks along the West Tasmanian margin. Moreover, no SAR seepage slicks were observed over the area of identified active seepage within the Strahan Sub-basin. This could suggest that the area is condensate- or gas-prone, though hydrocarbon analyses of the seafloor sediments suggest that thermogenic hydrocarbons, some of which are moderately geochemically wet, are present along the West Tasmanian margin. This apparent contradiction might be explained by the fact that the seepage is intermittent, that the SAR data were at the upper end or lower end of the weather compliance envelope, or that the amount of liquid hydrocarbons leaking is relatively small, and hence the resulting SAR seepage slicks are too small to map. Further work to discriminate between these alternatives, and combinations thereof, is necessary. In particular, we would recommend the sampling of the seafloor seeps identified in the Strahan Sub-basin as a priority, as the presence of oil within these sediments would immediately high-grade this area significantly. Fault seal is quite likely to be a major risk within the Strahan Sub-basin due to the apparent relatively unfavourable alignment of the faults and the regional NNW stress trajectories. If the faults have relatively steep dips, they are probably leaky, as evidenced by the presence of gas chimneys developed preferentially along these faults in areas where the source is mature. In general, more north-east to east-west trending fault blocks will be likely to have higher seal integrity, but if such targets cannot be identified, then NNW trending faulted traps with shallow-dipping bounding faults represent a more attractive target than those with steeper dips, as would stratigraphic traps.