No abstract available

Oil sourced from terrestrial organic matter accounts for over half of Australia?s oil reserves. The majority of this lies with the 4 billion barrels of recoverable oil in Late Cretaceous?Early Tertiary reservoirs of the Gippsland Basin. However, the role of oil expulsion from coal still raises considerable debate, both in the regional and global context. This question was addressed by a detailed gas-oil-source correlation study in the Bass Basin with complementary geochemistry on gas, oil and coal from the adjacent Gippsland Basin. Both basins shared a similar extensional tectonic and depositional setting throughout the Cretaceous to Tertiary leading to the breakup and isolation of continental Australia. Potential oil-prone source rocks in the Bass Basin are the early Tertiary coals. These coals have hydrogen indices (HI) up to 500 mg HC/gTOC and H/C ratio of 0.8 to 1.0. Associated disseminated terrestrial organic matter in claystones is mainly gas prone. Maturity is sufficient for oil and gas generation with vitrinite reflectance up to 1.8 % attained solely through burial. The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are: (i) the onset of oil generation at a vitrinite reflectance (VR) of 0.65 %; (ii) the onset of expulsion (primary migration) at a VR of 0.75 %; (iii) the main oil window between VR of 0.75 % and 0.95 %; and, (iv) the main gas window at VR >1.2 %. Sub-economic oil accumulations in the Bass Basin form a single oil population, based on carbon isotopes and biomarker, and are distinct from the oils from the Gippsland Basin. Natural gases are generated over a broader maturity range than the oils but nonetheless are associated with the same source rocks. Oil-to-source correlation in the Bass Basin based on biomarkers shows that the latest Paleocene?Early Eocene coals are the effective source rocks in the Bass Basin and provides the strongest geochemical evidence yet that coal has sourced petroleum in Australia. Carbon isotopes provide the main discrimination for coals, and their derived gases and oils, with the Early Eocene coals being the most depleted in 13C compared to older Late Cretaceous and Early Tertiary coals. It is likely that the carbon isotopes reflect both secular changes in the isotopic composition of atmospheric CO2 and floral influences, with the Early Eocene isotopically-light, angiosperm-dominated coals and the Late Cretaceous?Paleocene isotopically heavier, gymnosperm-dominated coals being the sources for the oil in the Bass and Gippsland basins, respectively.

With coal seam gas becoming an increasingly important contributor to the energy sector in eastern Australia, a critical factor is to understand the source of this gas, enabling migration fairways to be inferred and to access the risk of gas alteration and loss from source to reservoir. The paper will detail the use of stable carbon and hydrogen isotopic composition of individual coal seam gas components (methane, C2+ hydrocarbons and CO2) in determining the origin of the coal seam gases. The gas samples are from recent appraisal drilling by Queensland Gas Company Limited and Arrow Energy N.L. in the Jurassic Walloon Coal Measures, eastern Surat Basin, and are supplemented by Permian coal seam gas of a wide geographic distribution from the eastern (Moura and Peat ? Oil Company of Australia) and western margins of the underlying Bowen Basin (Fairway ? Tipperary Oil and Gas (Australia) Pty Ltd). The isotopic analyses from the coal seam gases are also compared with natural gases from conventional sandstone reservoirs in the Surat and Bowen basins. For methane from the Jurassic coals the carbon isotopes show a very narrow range from ?13C -57.3 to -54.2 ?. This compares to the much wider isotopic range for methane from the Permian coals (?13C -79.9 to -22.9 ?), reflecting a `continuum? from biogenic (isotopically light) to thermogenic (isotopically heavy) sources. On the other hand, the natural gases are isotopically heavy (?13C -43 to -31.9 ?), consistent with their thermogenic source from Permian coals and associated disseminated organic matter. Similarly, the hydrogen isotopes show a restricted range from ?D -215.5 to -203.3 ? compared with methane from Permian coals of ?D -255 to -152 ?. On the other hand, the carbon isotopes of the associated C2+ hydrocarbons (?13C -43.9 to -24.5 ?) are similar for the Jurassic coal seam gases and the conventional natural gases, suggesting a common thermogenic source for the wet gas components. Thus, the isotopic data for the hydrocarbon gases supports a mixed origin from local Jurassic coals and Permian sources. The former is the predominant source given that the associated CO2 is mostly isotopically light, ?13C range from -8 to -32 ?, and primarily sourced from decarboxylation of immature Jurassic coals.

The technique of reaction-gas chromatography-mass spectrometry (R-GCMS) has been used to characterise the polar fractions of sediment extracts and crude oils. R-GCMS was shown to be rapid, to require only small quantities of sample for analysis and the products formed during analysis were readily identified. To undertake R-GCMS, glass liners for split vaporising injection containing the catalyst, palladium black, were placed into the injection port of a gas chromatograph. Hydrogen gas was used both as an effective reactant for gas phase hydrogenation/hydrogenolysis and as the carrier gas for the subsequent separation. The reaction products were mostly hydrocarbons, which were swept on to the column and readily resolved by the non-polar stationary phase and then identified by mass spectrometry. The fully active catalyst was effective in hydrogenating and isomerising alkenes and partially hydrogenating aromatic moieties. Desulphurisation of thiols, sulphides, and thiophenes also readily occurred. Primary alcohols, acids, esters and ethers were transformed into a hydrocarbon of one carbon atom less, while secondary alcohols were reduced to the parent hydrocarbon. Polar fractions, isolated by column chromatography from the bitumen extracts of the Heartbreak Ridge lignite (Bremer Basin, Western Australia; Eocene age) and the Monterey Formation shale (Naples Beach, USA; Miocene age), reacted to produce compound distributions that were characteristic of the organic matter sources. In contrast, polar fractions from crude oils of the Exxon Program release low to minuscule quantities of hydrocarbons during R-GCMS, and their distributions were remarkably similar to each other and thus not diagnostic of organic matter sources. R-GCMS experiments also demonstrate that asphaltenes, even when redissolved and reprecipitated repeatedly, contain a proportion of functionalised material of low molecular weight.

No abstract available

The hydrocarbon and source rock evaluation given in this report summarises our present understanding of the geochemical factors which control petroleum occurrence in the Browse Basin. The aims of the present work are to describe the methods used in, and initial results of our characterisation (richness, quality and maturity) of the organic-rich rocks (ORR) within the Browse Basin stratigraphic section. In addition, an oil-source correlation involving biomarkers and stable carbon isotopes enables us to identify the contribution of the specific ORR's to migrated petroleum (oil stains) and reservoired hydrocarbons in the basin. One important task in effective source prediction is to place the ORR in a sequence stratigraphic context. Using the stratigraphic framework for the Browse Basin, combined with the known chronostratigraphy, we have chosen to analyse and interpret source rock potential within nine major intervals, BB1-BB3, BB4-BB5, BB6-BB7, BB8, BB9, BB10, BB11, BB12, and BB13-BB15 based on the most significant sequence boundaries within the Browse Basin succession.

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.