<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.

The ca. 1.5–1.3 Ga Roper Group of the greater McArthur Basin is a component of one of the most extensive Precambrian hydrocarbon-bearing basins preserved in the geological record, recently assessed as of 429 million bbl oil (68 million cubic meters of oil) and between 8 and 118 TCF (222.56 billion cubic meters) of gas (in place). It was deposited in an intracratonic sea, referred to here as the McArthur-Yanliao gulf. The Velkerri Formation forms the major deep-water facies of the Roper Group. Trace metal redox proxies from this formation indicate that it was deposited in stratified waters, in which a shallow oxic layer overlay suboxic to anoxic waters. These deep waters became episodically euxinic during periods of high organic carbon export. The Velkerri Formation has organic carbon contents that reach ∼10 wt. %. Variations in organic carbon isotopes are consistent with organic carbon enrichment being associated with increases in primary productivity and export, rather than flooding surfaces or variations in mineralogy. Although deposition of the Velkerri Formation in an intracontinental setting has been well established, recent global reconstructions show a broader mid to low latitude gulf, with deposition of the Velkerri Formation being coeval with the widespread deposition of organic-rich rocks across northern Australia and northern China. The deposition of these organic-rich rocks may have been accompanied by significant oxygenation associated with such widespread organic carbon burial during the Mesoproterozoic. <b>Citation:</b> Grant M. Cox, Alan S. Collins, Amber J. M. Jarrett, Morgan L. Blades, April V. Shannon, Bo Yang, Juraj Farkas, Philip A. Hall, Brendan O’Hara, David Close, Elizabeth T. Baruch; A very unconventional hydrocarbon play: The Mesoproterozoic Velkerri Formation of northern Australia. <i>AAPG Bulletin</i> 2022;; 106 (6): 1213–1237. doi: https://doi.org/10.1306/12162120148

Presentation delivered on 8 March 2012 at the Tasman Frontier Petroleum Industry Workshop, Geoscience Australia, Canberra.

The Mesozoic Beagle Sub-basin is in the Northern Carnarvon Basin, offshore Western Australia. Oil discovered at Nebo 1 in 1993 highlights an active petroleum system. The central Beagle Sub-basin, this study's focus, has a north-south trending horst-graben architecture. Detailed mapping of the 1529 km2 Beagle Multi-client 3D seismic survey gave insight into its geological history. The Rhaetian to Valanginian syn-rift succession comprises fluvio-deltaic and marine sediments deposited during low rates of crustal extension. During post-rift thermal subsidence, sediments onlapped eroded and tilted fault blocks formed during the syn-rift phase. Consequently, the Early Cretaceous regional seal is absent in the central study area. Overlying sedimentary successions are dominated by a prograding carbonate wedge. Potential source, reservoir and seal facies are present from the Triassic to earliest Cretaceous. 1D burial history modelling indicates that in Nebo 1, potential source rocks from the Middle Jurassic to Early Cretaceous became oil mature after the emplacement of the regional seal. At Manaslu 1, these sediments are immature. Potential source rocks are currently at maximum burial depth and thermal maximum. Trap integrity in the pre and syn-rift succession could be jeopardized by fault reactivation, however post-rift traps may be preserved. Potential plays include compaction folds over tilted horst blocks, anticlines, basin-floor fans and intra-formational traps. Hydrocarbons could use deep faults to migrate into Early Cretaceous plays. Younger sediments lack migration pathways so are unlikely to host significant hydrocarbons. Poor quality source rocks and reservoirs, and poor source rock distribution may also contribute to disappointing exploration results.

In this study detailed mapping of seismic data from the 1529 km2 Beagle multi-client 3D seismic survey was undertaken to provide a better understanding of the geological history of the central Beagle Sub-basin. Situated in the Northern Carnarvon Basin, oil discovered at Nebo 1 in 1993 indicated the presence of at least one active petroleum system. The central part of the sub-basin has a N-trending horst-graben architecture. Two rifting events from the Hettangian to Sinemurian and the Callovian to Oxfordian were identified. A series of tilted fault blocks formed by the rifting events were locally eroded and progressively draped and buried by post-rift thermal subsidence sedimentation. Mapping indicated the Post-rift I Lower Cretaceous Muderong Shale regional seal is anomalously thin or absent in the intra-horst graben area. Burial history 1D modelling indicates that at Nebo 1, the most rospective potential source rocks within the Middle-Upper Jurassic section where in the early oil window; however, if present within the Beagle and Cossigny trough depocentres, these sediments would have entered the oil window prior to the deposition of the Muderong Shale regional seal. Upper Jurassic shales provide seal for the oil pool intersected in Nebo 1. The Tertiary section is dominated by a prograding carbonate wedge which has driven a second phase of thermal maturation observed in the Paleogene (Nebo 1) and Miocene (Manaslu 1). Potential source rocks are currently at their maximum depth of burial and maximum thermal maturity. Modest inversion on some faults prior to the Early Cretaceous has created traps and if source rocks retain generative potential, favourable traps could be now actively receiving hydrocarbon charge. Potential plays include compaction folds over tilted horst blocks, drape and small inversion induced anticlines, basin-floor fans and intra-formational traps. Deep faults may act as conduits for hydrocarbons migrating from mature potential source rocks into Jurassic to Cretaceous plays. Younger sediments appear to lack access to migration pathways provided by deeper faults.