No abstract available

abstract

The Ceduna Sub-basin of the Bight Basin is a frontier region containing only one exploration well. Therefore, our assessment of the distribution of potential source rocks in the area is based on an understanding of the regional sequence stratigraphic framework and the potential petroleum systems present, along with the regionsal palaeogeography, and geochemical data from onshore and the adjacent Duntroon Basin. Studies carried out by AGSO over the past three years suggest that the thick Cretaceous succession in the Ceduna Sub-basin contains a range of fluvio-lacustrine, deltaic and marine source rocks that have the potential to generate liquid hydrocarbons.

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.

Legacy product - no abstract available

APPEA 2000 joint paper to arrive at a better understanding of the petroleum systems active in the Northern Bonaparte Basin, geochemical data from oils and source rock-extracts were compiled and interpreted from over 20 wells in the area.

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.

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.

The molecular composition of fluid inclusion (FI) oils from Leander Reef-1, Houtman 1 and Gage Roads-2 provide evidence of the origin of palaeo-oil accumulations in the offshore Perth Basin. These data are complemented by compound specific isotope (CSI) profiles of n-alkanes for the Leander Reef-1 and Houtman-1 samples, which were acquired on purified n-alkane fractions gained by micro-fractionation of lean FI oil samples, showing the technical feasibility of this technique. The Leander Reef-1 FI oil from the top Carynginia Formation shares many biomarker similarities with oils from the Dongara and Yardarino oilfields, which have been correlated with the Early Triassic Kockatea Shale. However, the heavier isotopic values for the C15-C25 n-alkanes in the Leander Reef-1 FI oil indicate that it is a mixture, and suggest that the main part of this oil (~90%) was sourced from the more terrestrial and isotopically heavier Early Permian Carynginia Formation or Irwin River Coal Measures. This insight would have been precluded when looking at molecular evidence alone. The Houtman-1 FI oil from the top Cattamarra Coal Measures (Middle Jurassic) was sourced from a clay-rich, low sulphur source rock with a significant input of terrestrial organic matter, deposited under oxic to suboxic conditions. Biomarkers suggest sourcing from a more prokaryotic-dominated facies than for the other FI oils, possibly a saline lagoon. The Houtman-1 FI oil ?13C CSI data are similar to data acquired on the Walyering-2 oil. Possible lacustrine sources include the Early Jurassic Eneabba Formation or the Late Jurassic Yarragadee Formation. The low maturity Gage Roads-2 FI oil from the Carnac Formation (Early Cretaceous) was derived from a strongly terrestrial, non-marine source rock containing a high proportion of Araucariacean-type conifer organic matter. It has some geochemical differences to the presently reservoired oil in Gage Roads-1, and was probably sourced from the Early Cretaceous Parmelia Formation.