Basin evolution of the Vlaming Sub-basin and the deep-water Mentelle Basin, both located offshore on the southwest Australian continental margin, were investigated using 2D and 3D petroleum system modelling. Compositional kinetics, determined on the main source sequences, were used to predict timing of hydrocarbon generation and migration as well as GOR evolution and phase behaviour in our 2D and 3D basin models. The main phase of petroleum generation in the Vlaming Sub-basin occurred at 150 Ma and ceased during following inversion and erosion episodes. Only areas which observed later burial have generated additional hydrocarbons during the Tertiary and up to present day. The modelling results indicate the likely generation and trapping of light oils for the Jurassic intervals for a variety of structural traps. It is these areas which are of greatest interest from an exploration point of view. The 2D numerical simulations in the Mentelle Basin indicate the presence of active hydrocarbon generating kitchen areas. Burial histories and generalized petroleum evolutionary histories are investigated.

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 Source Rock and Fluids Atlas delivery and publication services provide up-to-date information on petroleum (organic) geochemical and geological data from Geoscience Australia's Organic Geochemistry Database (ORGCHEM). The sample data provides the spatial distribution of petroleum source rocks and their derived fluids (natural gas and crude oil) from boreholes and field sites in onshore and offshore Australian basins. The services provide characterisation of source rocks through the visualisation of Pyrolysis, Organic Petrology (Maceral Groups, Maceral Reflectance) and Organoclast Maturity data. The services also provide molecular and isotopic characterisation of source rocks and petroleum through the visualisation of Bulk, Whole Oil GC, Gas, Compound-Specific Isotopic Analyses (CSIA) and Gas Chromatography-Mass Spectrometry (GCMS) data tables. Interpretation of these data enables the characterisation of petroleum source rocks and identification of their derived petroleum fluids that comprise two key elements of petroleum systems analysis. The composition of petroleum determines whether or not it can be an economic commodity and if other processes (e.g. CO2 removal and sequestration; cryogenic liquefaction of LNG) are required for development.

Organic geochemists are increasingly involved in multi-disciplinary collaborative studies but not often in the initial sample collection phase, so understanding the origin and source of contaminants derived from sample handling and containers is of vital importance as standard laboratory blanks cannot assess this contamination. A variety of organic contaminants was detected in different sediments collected during Geoscience Australia marine survey S282. These include fatty acid amides, chemical antioxidants such as butylated hydroxytoluene and octadecyl-3, 5-di-tert-butyl-4-hydroxyhydrocinnamate (Irganox 1076), plus the UV absorbers octabenzone and octyl methoxycinnamate. These compounds were introduced during sampling on board the research vessel or during subsequent handling. Solvent extraction of potential contamination sources identified two brands of plastic sampling bags as the main source for the fatty acid amides, butylated hydroxytoluene and Irganox 1076. Direct contact of samples with hands covered with sunscreen appears to have caused contamination by octabenzone and octyl methoxycinnamate. As the primary aim of the survey was to detect evidence for hydrocarbon seepage in the Arafura Sea, care was also taken to identify potential sources of hydrocarbons that might have been introduced during sampling and storage. Detailed examination of solvent extracts from plastic bags revealed the occurrence of several homologous series of branched alkanes with quaternary carbon atoms (BAQCs), as well as distributions of alkyl cyclohexanes and alkyl cyclopentanes with strong even over odd carbon predominance. These compounds were also found in sediment samples collected during the survey. Other potential sources of contamination used on board the ship, such as PVC core liners and lubricants, yielded hydrocarbons that could easily be mistaken for evidence of naturally occurring petroleum if care is not taken during interpretation.

This study undertook geochemical and isotopic analyses on a wide selection of oil stains from the Thorntonia Limestone, Arthur Creek Formation and the Arrinthrunga Formation and its lower Hagen Member in order to define geochemical inter-relationships between the oils, characterize their source facies and to determine the extent of post-emplacement alteration. Oil stains were collected from BHD-4 and -9, Elkedra-2 and -7A, Hacking-1, MacIntyre-1, M13 PD, NTGS99/1, Owen-2, Randall-1 and Ross-1 over a depth range from 91 to 1065 m and were analysed for bulk, molecular (biomarkers) and carbon isotopic compositions. Gas chromatograph of the saturated hydrocarbon fraction clearly showed biodegradation as the main alteration process in the shallow reservoirs. Unaltered oil stains show a dominance of medium weight n-alkanes with a maximum at n-C15. Biodegradation results in a progressive loss of the lighter hydrocarbons and an accompanying shift in n-alkane maximum to C27, to finally a complete loss of n-alkanes and a large unresolved complex mixture (UCM). The absence of 25-norhopanes suggests a mild level of biodegradation. The low ratio of saturated hydrocarbons/aromatic hydrocarbons (<1, down to 0.42) compared to high ratios (up to 4.35) for oils with abundant lower molecular weight n-alkanes is consistent with biodegradation. However, low ratios are also seen for otherwise pristine oils, suggesting a complex charge history of initial biodegraded and subsequent re-charge with n-alkane-laden oil. The level of biodegradation is not too severe as to overtly affect the distribution of the biomarkers C19 - C26 tricyclic terpanes, C24 tetracyclic terpane, C27 - C35 hopanes, C30 triterpane (gammacerane) and C27- C29 desmethylsteranes, enabling their use in oil-oil correlation and definition of oil populations. To clarify the inter-relationships among the Georgina Basin oil stains multivariate statistical analysis was used involving a wide range of biomarker ratios that are source-specific and environmental indicators. Resulting oil populations showed a strong correlation with their reservoir unit across the basin, suggesting juxtaposition of source and reservoir within the same stratigraphic unit. Oil-source correlation based on biomarker, bulk carbon isotopes of saturated and aromatic hydrocarbons and n-alkane-specific carbon isotopes identified Thorntonia(!), Arthur Creek(!) and Hagen(.) Petroleum Systems. The latter petroleum system is characterised by relatively high gammacerane, indicating an evaporitic depositional environment. Alternatively, an evaporatic organic facies from an Arthur Creek Formation source may have sourced the Hagen Member oil stains, considering that other oil stains reservoired within the Arrinthrunga Formation show a close affinity with oil stains from the Arthur Creek(!) Petroleum System, suggesting an inter-formational Arthur Creek-Hagen Petroleum System at Elkedra-2. An Arthur Creek-Hagen(!) petroleum system is evident at Elkedra-7A while there is a mixed Thorntonia Limestone and Arthur Creek source contribute to the oil stain at Ross-1.

Methane is present in all coals, but a number of geological factors influence the potential economic concentration of gas. The key factors are (1) depositional environment, (2) tectonic and structural setting, (3) rank and gas generation, (4) gas content, (5) permeability, and (6) hydrogeology. Commercial coal seam gas production in Queensland has been entirely from the Permian coals of the Bowen Basin, but the Jurassic coals of the Surat and Clarence-Moreton basins are poised to deliver commercial gas volumes. Depositional environments range from fluvial to delta plain to paralic and marginal marine coals in the Bowen Basin are laterally more continuous than those in the Surat and Clarence-Moreton basins. The tectonic and structural settings are important as they control the coal characteristics both in terms of deposition and burial history. The important coal seam gas seams were deposited in a foreland setting in the Bowen Basin and an intracratonic setting in the Surat and Clarence-Moreton basins. Both of these settings resulted in widespread coal deposition. The complex burial history of the Bowen Basin has resulted in a wide range of coal ranks and properties. Rank in the Bowen Basin coal seam gas fields varies from vitrinite reflectane of 0.55% to >1.1% Rv and from Rv 0.35-0.6% in the Surat and Clarence-Moreton basins in Queensland. High vitrinite coals provide optimal gas generation and cleat formation. The commercial gas fields and the prospective ones contain coals with >60% vitrinite. Gas generation in the Queensland basins is complex with isotopic studies indicating that biogenic gas, thermogenic gas and mixed gases are present. Biogenic processes occur at depths of up to a kilometre. Gas content is important, but lower gas contents can be economic if deliverability is good. Free gas is also present. Drilling and production techniques play an important role in making lower gas content coals viable. Since the Bowen and Surat basins are in a compressive regime, permeability becomes a defining parameter. Areas where the compression is offset by tensional forces provide the best chances for commercial coal seam gas production. Tensional setting such as anticline or structural hinges are important plays. Hydrodynamics control the production rate though water quality varies between the fields.

An inverted phase (polar to non-polar) column set has been compared with a non-polar to polar column set for the GC-GC separation of petroleum hydrocarbons crude oil. This is shown to provide greatly enhanced resolution for less polar compounds and makes greater use of the two-dimensional separation space. This column configuration improves resolution of a greater number of components within one analysis and offers new possibilities for crude oil fingerprinting.

This is a collection of conference program and abstracts presented at AOGC 2010, Canberra.

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 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.