This report provides a detailed account of several important aspects relating to the organic geochemical analyses of oil, gas and source rocks in the AGSO - Geoscience Australia laboratory. It focuses on the main methods used for the molecular analysis of the sterane, hopane and alkylaromatic biomarkers as well as the stable carbon isotopic (bulk and CSIA) analysis of these materials. In the following description of these methods the areas of sample preparation, instrumental analysis and data processing/reporting are separately addressed.

No abstract available

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.

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.

Molecular and stable isotopic (carbon and hydrogen) analyses are being undertaken on fluid samples from offshore Australian gas accumulations, as part of a Geoscience Australia initiative to understand the origin, thermal maturity and degree of preservation of these economic resources. The geochemical data are available from Geoscience Australia's web site http://www.ga.gov.au/oracle/apcrc. Here, emphasis is placed upon documenting the natural gas compositions of the Exmouth Plateau and Exmouth Sub-basin (Fig. 1). It is apparent from the isotopic signatures of the non-combustible and combustible gases that several sources of gas are mixed within these accumulations, many of which have complex fill histories. These results were presented at the Combined National Conference of the Australian Organic Geochemists and the Natural Organic Matter Interest Group, Rottnest Island, Perth, WA, February 2006 (Edwards et al., 2006).

Legacy product - no abstract available

AGSO's 1995-96 Petrel Sub-basin Study was undertaken within AGSO's Marine, Petroleum and Sedimentary Resources Division (MPSR) as part of MPSR's North West Shelf Project. The study was aimed at understanding the stratigraphic and structural development of the basin as a framework for more effective and efficient resource exploration. Specifically, the study aimed to: - define the nature of the major basement elements underlying the Petrel Sub-basin and their influence on the development of the basin through time, - determine the nature and age of the events that have controlled the initiation, distribution and tectonic evolution of the basin; - define the nature and age of the basin fill, and the processes that have controlled its deposition and deformation; and, importantly, - determine the factors controlling the development and distribution of the basin's petroleum systems and occurrences.

The warm greenhouse world of the Late Cretaceous created an ocean that was poorly stratified latitudinally and vertically. Periodically these oceans experienced globally significant events where oxygen minimum zones enveloped the continental margins. Evidence of the effect of one of these Ocean Anoxic Events (OAE?s) is preserved in the southern high latitude strata of the Otway Basin in southeast Australia. During the Late Cretaceous, thick sequences of mudstone-dominated deltaic sediments (the Otway Delta) were deposited in an elongate inlet (ca. 500km wide) between Antarctica and Australia located at least 70?S. The initial Turonian strata of this delta (the Waarre Formation) were deposited in marginal marine delta plain to delta front conditions. The overlying Flaxman Formation and basal Belfast Mudstone preserve evidence of transgressive inner to middle shelf upper delta to prodelta conditions. These Turonian units were subject to periodic dysoxia. The conditions that created this dysoxia in the region were similar to those of the high northern latitude Cretaceous Interior Seaway of North America where intermittent freshwater input and deepening seas caused periods of thermohaline stratification and reduced bottom waters. The overlying Coniacian to Santonian Belfast Mudstone was deposited in outer shelf to upper slope prodelta conditions subject to periodic fluctuations in dysoxia with normal marine salinities. After a period when the oxygen minimum zone contracted, upward-increasing dysoxia in the Belfast Mudstone herald the onset of the Coniacian to Santonian OAE 3. This was the last OAE of the Late Cretaceous, prior to the onset of more ?modern? oceanic conditions. The fluctuations in TOC and hydrogen index in these strata reflect variable dysoxic conditions similar to that reported for OAE 3 in the tropical eastern Atlantic by Hofmann et al. (2003). This periodicity implies a very active and dynamic Late Cretaceous hydrosphere. Eventually, hyposaline conditions or higher sedimentation rates due to upper delta progradation and shallowing in the Santonian caused the local extinction and dissolution of many of the calcareous benthic taxa of the Belfast Mudstone.

Australia's National Oil-on-the-Sea Identification Database (NOSID) contains organic geochemical data on a reference set of 30 oils that is used to characterised (or fingerprint) an oil. The data on these oils have been produced from a variety of analytical methods including isotope, UVF, GC and GC-MS (biomarker) analyses. The NOSID database and the Oil Identification Reference Kit are the products of collaboration between the Geoscience Australia (GA), the Australian Government Analytical Laboratories (AGAL) and the Australian Maritime Safety Authority (AMSA).

Geoscience Australia has begun a systematic evaluation of the shale gas/oil (unconventional) resource potential of Australia's onshore sedimentary basins. According to the Australian Gas Resource Assessment 2012 [1] Australia's unconventional gas resource endowment is likely to be greater than its estimated total conventional gas resources with some basins likely to have significant unconventional oil potential. An assessment of Australia's unconventional resource potential will use methodology developed by the United States Geological Survey based on statistically derived estimates of hydrocarbon recovery from actual production data, or basin analogues in data-poor areas. The Georgina Basin, containing Proterozoic-Paleozoic age sediments and covering an area of ~325,000 sq. km in south-central Australia, is the first basin to be assessed and since there is no petroleum production history, suitable analogues will be sought. The assessment also relies heavily on the updated stratigraphy, tectonic history, petrography, geochemistry and petroleum systems modelling, with a discussion emphasis on the latter two datasets. The Georgina Basin is host to basin-wide oil staining and contains proven petroleum systems with relative short migration distances from source to trap, which likely represent multiple hybrid unconventional systems and breached conventional reservoirs. For example, the result of localised migration is exemplified in the composition of residual free hydrocarbons from organic-rich mudstones in which light and heavy hydrocarbons were recorded in samples 3 m apart. The most prolific oil-prone effective sources occur in the Middle Cambrian Thorntonia Limestone (early to middle Ordian) and overlying Arthur Creek Formation (latest Ordian to late Boomerangian). These source rocks were diachronously deposited from west to east under marine anoxic bottom waters, which periodically extended into the photic zone, and represent the local expression of a prolonged Middle-Late Cambrian oceanic anoxic event that lead to deposition of organic-rich 'black shales' on a global scale. The oil stains are varyingly altered by biodegradation and are geochemically characterised by a strong isotopic depletion in 13C, high abundance of monomethylalkanes, C15-C23 odd carbon number predominance for n-alkylcyclohexanes, C27 slightly dominant over C29 desmethylsteranes and high content of tricyclic terpanes. Source richness and maturity estimates are derived from Rock Eval, saturated and aromatic hydrocarbons, FAMM and hydrogen isotopic relationships between n-alkanes and isoprenoids. For example, the 'hot shale' unit comprising predominately dolostone at the base of the Arthur Creek Formation, currently the focus of drilling activity for unconventional hydrocarbons, has TOC and HI up to 15.5 % and 500 mg hydrocarbons/g TOC, respectively. Maturity levels range from the early oil to early dry gas windows. This unit appears to have all the geochemical pre-requesites for a significant unconventional hydrocarbon play. Geohistory modelling using formation-specific compositional kinetics indicates petroleum generation and expulsion begins in the latest Cambrian-Early Ordovician due to relatively rapid burial of the Arthur Creek Formation. Deposition ends with the start of the Alice Springs Orogeny and following uplift and erosion during the Devonian, hydrocarbon generation ceases. An unconventional petroleum resource assessment of the Georgina Basin will be undertaken in February 2013 and available for benchmarking and refinement against any future shale gas and shale oil production. [1] Geoscience Australia and Bureau of Resource and Energy Economics, 2012, Australian Gas Resource Assessment 2012, Canberra, 56 p. https://www.ga.gov.au/products/servlet/controller?event=GEOCAT_DETAILS&catno=74032