<p>Organic matter in sedimentary rocks changes physical properties and composition in an irreversible and often sequential manner after burial, diagenesis, catagenesis and metagenesis with increasing thermal maturity. Characterising these changes and identifying the thermal maturity of sedimentary rocks is essential for calculating thermal models needed in a petroleum systems analysis. <p>In the Isa Superbasin, the thermal history of the sediments is difficult to model due to erratic thermal maturity profiles, which are often inverted with depth (e.g. Glikson et al. 2006; Gorton & Troup, 2018). In previous studies, these erratic profiles have been attributed to multiple fluid flow events through the basin (Glikson et al. 2006). However, another reason to explain some of these results may be due to low statistical significance and quality control of legacy data. The Australian Standard for reflectance measurements Australian Standard AS2856.3-1998. Coal petrography: Method for microscopical determination of the reflectance of coal macerals requires a minimum of 30 reflectance measurements to be taken on a sample for statistical significance and to maintain confidence in the results. However, Barker & Pawlewicz (1993) suggest a minimum of 20 measurements in sedimentary rocks which may have fewer macerals than coals. The numbers of reflectance measurements are not always provided with legacy data, however some core samples have very low values (n < 5) suggesting low confidence in some results. <p>In order to maintain confidence in the legacy data, Geoscience Australia contracted CSIRO Energy to conduct a thorough organic petrological analysis of 22 shale samples from two drill cores; Amoco DDH 83-4 and Desert Creek 1 from the Fickling and McNamara groups of the Isa Superbasin. These two wells were selected as Geoscience Australia has recently conducted a full suite of organic geochemistry on these wells and there is legacy reflectance data available. <p>The estimated organic matter (OM) content of the samples analysed ranged from <0.1% to 30% by volume. The majority of the OM is bitumen that occurs as fine disseminations throughout the mineral matrix in addition to infilling inter-granular porosity of carbonates and other minerals. The abundance of bitumen resulted in reflectance measurements consistent with Australian Standards for most samples, ensuring high confidence in the results. <p>In Amoco DDH 83-4, the reflectance data generated in this study show a broadly linear increase with depth down core, ranging from thermally mature to overmature. The outliers in the down core trend represent samples with low OM, a minimum amount of bitumen to conduct reflectance measurements on and hence, low statistical significance and low confidence in the results. These results highlight the need to work within the guidelines specified by the Australian standard to maintain confidence in the data. In Desert Creek-1, samples studied are mature for dry gas generation. Although still broadly consistent with previously published work, the down well reflectance profile produced for this study is much less erratic compared with reflectance profiles generated from legacy data. This is likely due to the careful analysis of the same OM type in the samples. For the legacy Desert Creek 1 data, neither reflectance histograms nor the number of reflectance measurements are provided and therefore reasons for the differences between results are not certain. <p>The results of this study have major implications in a petroleum systems modelling context, as thermal and burial history modelling requires reliable equivalent vitrinite reflectance data for calibration purposes. In the Fickling Group, the new results show that hydrocarbon generation has occurred. As the thermal maturity in the previous study was largely immature, the hydrocarbon prospectivity of the area has been upgraded. The statistically significant results of this study provide a more robust calibration dataset for use in petroleum systems models in the Isa Superbasin. Similar studies on other wells in the basin may be necessary to further reduce uncertainty.

<div>The Gas Chromatography-Mass Spectrometry (GC-MS) biomarker database table contains publicly available results from Geoscience Australia's organic geochemistry (ORGCHEM) schema and supporting oracle databases for the molecular (biomarker) compositions of source rock extracts and petroleum liquids (e.g., condensate, crude oil, bitumen) sampled from boreholes and field sites. These analyses are undertaken by various laboratories in service and exploration companies, Australian government institutions and universities using either gas chromatography-mass spectrometry (GC-MS) or gas chromatography-mass spectrometry-mass spectrometry (GC-MS-MS). Data includes the borehole or field site location, sample depth, shows and tests, stratigraphy, analytical methods, other relevant metadata, and the molecular composition of aliphatic hydrocarbons, aromatic hydrocarbons and heterocyclic compounds, which contain either nitrogen, oxygen or sulfur.</div><div><br></div><div>These data provide information about the molecular composition of the source rock and its generated petroleum, enabling the determination of the type of organic matter and depositional environment of the source rock and its thermal maturity. Interpretation of these data enable the determination of oil-source and oil-oil correlations, migration pathways, and any secondary alteration of the generated fluids. This information is useful for mapping total petroleum systems, and the assessment of sediment-hosted resources. Some data are generated in Geoscience Australia’s laboratory and released in Geoscience Australia records. Data are also collated from destructive analysis reports (DARs), well completion reports (WCRs), and literature. The biomarker data for crude oils and source rocks are delivered in the Petroleum and Rock Composition – Biomarker web services on the Geoscience Australia Data Discovery Portal at https://portal.ga.gov.au which will be periodically updated.</div>

The Energy component of Geoscience Australia’s Exploring for the Future (EFTF) program is aimed at improving our understanding of the petroleum resource potential of northern Australia, including the Lawn Hill Platform region of the Isa Superbasin. The Paleoproterozoic Isa Superbasin in northwestern Queensland contains organic rich sedimentary units with the potential to host both conventional and unconventional petroleum systems (Gorton & Troup, 2018). On the Lawn Hill Platform, the River and Lawn supersequences of the Isa Superbasin host the recently discovered Egilabria shale gas play and are considered highly prospective shale gas targets. However, the lateral extent of these plays is currently unknown due to the limited well and associated geochemical data. To aid in the identification of new areas with the potential to host active petroleum systems, this work assesses the burial and thermal history of the Lawn Hill Platform (Figure 1) by using organic richness, quality and thermal maturity of source rocks of the Isa Superbasin. This assessment is based on a compilation of updated and quality controlled publicly available total organic carbon (TOC), Rock-Eval pyrolysis and organic matter reflectance data, and combines revised assessments of the depth structure and isopach mapping by Bradshaw et al., (2018, in press). Burial-thermal relationships in the basin have been difficult to determine in the past, usually attributed to multiple hydrothermal events which has resulted in erratic, and occasionally inverted, maturity reflectance profiles (Gorton and Troup, 2018; Glikson, 1993). Additional difficulties that contribute large uncertainties to our understanding are estimating the burial history across the basin, especially the maximum depth of burial and hence the estimated amount of erosion. Initial modelling suggests erosion amounts could range anywhere from several hundreds of meters to several thousands of meters across the Lawn Hill Platform region (Figure 2). Burial and thermal history modelling is calibrated using paleo-maturity data (reflectance profiles as mentioned above, Figure 2), which is poorly constrained. Because of the age (Paleoproterozoic) of the organic matter, reflectance values of alginite and bitumen were used, which are not always comparable to the standard vitrinite reflectance profiles that are typically used for burial and thermal history modelling calibration. In this study other options of burial-thermal model calibrations were assessed to aid in characterising the petroleum potential of this region, including; bottom hole temperature, developing an improved Tmax conversion equation specific to the Isa Superbasin region, using published conversion equations to convert alginite and bitumen reflectance to vitrinite equivalent reflectance, using HI as an indicator of thermal history, oxygen isotopes (δ18O), and fluid inclusion geothermometry. Abstract and poster for presentation at the Australian Organic Geochemistry Conference 2018

The discovery of bitumen on beaches and rocky points between Bathurst Island and Elcho Island dates back to at least 1922 when a Reverend Jennison found a deposit on a beach near Elcho Island Mission. This was later described by Arthur Wade in 1924 as "flat cakes filling lenticular cavities on the flaggy beds". These have since been again recorded several times between 1965 and 1984. Some people think the bitumen near the old mission is in situ whereas others have seen bitumen draped all over the wave cut platform at low tide all along the island.