Compelling evidence is presented for the process of lipid sulfurisation in humic coal-forming environments. The production of reduced inorganic sulfides by sulfate-reducing bacteria during early diagenetic marine transgression enabled the selective sequestration of functionalised lipids in the polar and asphaltene fractions from the Eocene, marine-influenced Heartbreak Ridge lignite deposit, southeast Western Australia. Nickel boride desulfurisation experiments conducted on these fractions released small, but significant, quantities of sulfur-bound hydrocarbons. These comprised mostly higher plant triterpanes, C29 steranes and extended 17?(H),21?(H)-hopanes, linked by one sulfur atom at, or close to, sites of oxygenation in the original natural product precursors. These sulfurised lipids mostly derive from the same carbon sources as the free hydrocarbon lipids, the exception being the sulfurised extended hopanoids, which may be partially derived from a different bacterial source compared to the free hopanoids. These results indicate that the selectivity and nature of steroid and hopanoid vulcanisation in coal-forming mires is akin to that observed in other sedimentary environments. However, the diversity of sulfurised higher plant triterpanes is greater than that typically reported in immature coals. This selective preservation mechanism explains the formation of the structurally-related biomarkers in more mature sulfur-rich humic coals.

A laboratory study has been conducted to determine the best methods for the detection of C10 to C40 hydrocarbons at naturally occurring oil seeps in marine sediments. The results indicate that a commercially available method using hexane to extract sediments and gas chromatography to screen the resulting extract is effective at recognizing the presence of migrated hydrocarbons at concentrations between 50 to 5,000 ppm. When the oil charge is unbiodegraded the level of charge is effectively tracked by the sum of n-alkanes in the gas chromatogram. However, once the charge oil becomes biodegraded, with the loss of n-alkanes and isoprenoids, the level of charge is tracked by the quantification of the Unresolved Complex Mixture (UCM). The use of GC-MS was also found to be very effective for the recognition of petroleum related hydrocarbons and results indicate that GC-MS would be a very effective tool for screening samples at concentrations below 50 ppm oil charge.

The geological debate about whether, and to what extent, humic coals have sourced oil is likely to continue for some time, despite some important advances in our knowledge of the processes involved. Both liptinites and perhydrous vitrinites have the potential to generate oil; the key problem is whether this oil can be expelled. Expulsion of hydrocarbons is best explained by activated diffusion of molecules to maceral boundaries and ultimately by cleats and fractures to coal seam boundaries. The relative timing of release of generated CO2 and CH4 could have considerable importance in promoting the expulsion of liquid hydrocarbons. The main reason for poor expulsion from coal is the adsorption of oil on the organic macromolecule, which may be overcome (1) if coals are thin and interbedded with clastic sediments, or (2) if the coals are very hydrogen rich and generate large quantities of oil. Review of the distribution of oil-prone coals in time and space reveals that most are Jurassic-Tertiary, with key examples from Australia, New Zealand and Indonesia. Regarding establishing oil-coal correlations, a complication is that the molecular geochemistry of coals is often very similar to that of the enclosing, fine-grained rocks containing terrestrial organic matter. One potential solution to this problem is the use of carbon and hydrogen isotopes of n-alkanes, which have recently been shown to be powerful discriminators of mudstone and coal sources in the Turpan Basin (China). There is a continuum from carbonaceous shales to pure coals, but the question as to which of these are effective oil sources is an extremely important issue, because volumetric calculations hinge on the result. Unambiguous evidence of expulsion from coals is limited. Bitumen-filled microfractures in sandstones interbedded with coals in offshore mid-Norway and in Scotland have been interpreted to be the migration routes of hydrocarbons from the coal seams towards the sandstones. In the San Juan Basin, USA, direct evidence for the primary migration of oil within coal is provided by the sub-economic quantities (10s to 100s of barrels per well) of light oil produced directly from coal beds of the Upper Cretaceous Fruitland Formation. The Gippsland Basin (Australia) is commonly cited as the outstanding example of a province dominated by oil from coal, but there is no literature that explicitly demonstrates that generation and expulsion has been from the coal seams and not the intervening carbonaceous mudstones. The best evidence for coals as source for oil in the Gippsland appears to be volumetric modelling, which indicates that it would have been impossible to generate the volume of oil discovered to date from the organic-rich shales alone. However, early reports that mid-Jurassic coals in mid-Norway were a major source of the reservoired oils, also based to a large extent on oil generation and expulsion modelling, have now been shown to be inaccurate by detailed biomarker, isotope, whole oil and pyrolysis studies. The most convincing commercial oil discoveries that can be correlated to coals are: (1) Taranaki Basin oils in New Zealand, where Late Cretaceous and Tertiary coals, shaly coals and carbonaceous mudstones are likely to have sourced oils in approximate proportion to their volumes and organic contents, and (2) the oils and condensates in the Harald, Amalie and Lulita oilfields (Danish North Sea) which are likely to have been sourced are least partially from mid-Jurassic coals. New oil-source correlation studies based on diterpane, triterpane and sterane distributions in the Bass Basin (Australia), which lies adjacent to the Gippsland Basin and contains sub-economic reserves of oil and gas, has shown that the Tertiary coals and not the associated shales are best correlated with the oils.

This article focuses on the re-evaluation of the source rock potential of the basal Kockatea Shale in the offshore portion of the northern Perth Basin.

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.