This report highlights results of petroleum systems analysis undertaken on the northern Lawn Hill Platform area of the Isa Superbasin, specifically focusing on burial and thermal history modelling. A second report will highlight the results of the source rock analysis and maturity modelling.

The northern Lawn Hill Platform (nLHP) is considered an emerging region with less than 15 wells drilled to date. With renewed interest in unconventional gas, new exploration opportunities exist in this early Proterozoic region. Petroleum systems analysis is presented here to improve the understanding of burial history, source rock richness and maturity of the nLHP of the Isa Superbasin, far NW Queensland. A pseudo-3D geological model was built and calibrated, in combination with 1-D burial and thermal history modelling of Desert Creek 1 and Egilabria 1. These were combined with source rock characteristics (e.g., Rock Eval and kerogen kinetics) which helped assess the hydrocarbon generation potential by source rock, allowing a broader assessment of petroleum prospectivity of the nLHP. The study focussed on two potential source rocks; the Lawn 4 Sequence and the River Supersequence. Maturity modelling of the Lawn 4 Sequence at Desert Creek 1 and Egilabria 1 predicted equivalent vitrinite reflectance (EqVR) of over 1.2% and 2%, respectively. The River Supersequence was modelled as overmature at both wells. Combining these results with the pseudo-3D model and source rock characteristics demonstrates that the highest maturities are encountered in the deepest depocentres to the east and gradually decrease in maturity to the west, indicating some potential for wet gas. Modelling results show generation of varying amounts of gas and oil from each potential source rock. Overall, due to the age of the sediments, maximum depth of burial and high paleotemperatures, the most likely hydrocarbon phase is gas from primary generation and supplemented by secondary gas from oil cracking. In spite of high maturities, encouraging gas shows from the Egilabria prospect support continued exploration interest in this region for unconventional hydrocarbons.

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.

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

<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

<div>NDI Carrara 1 is a 1750 m stratigraphic drill hole completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI) in collaboration with Geoscience Australia under the Exploring for the Future program and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a recently discovered depocentre in the South Nicholson region. The drill hole intersected Cambrian and Proterozoic sediments consisting of organic-rich black shales and a thick sequence of interbedded black shales and silty sandstones with hydrocarbon shows. A comprehensive analytical program carried out by Geoscience Australia on the recovered core samples from 283 m to total depth at 1751&nbsp;m provides critical data for calibration of burial and thermal history modelling.</div><div>Using data from this drilling campaign, burial and thermal history modelling was undertaken to provide an estimate of the time-temperature maxima that the sub-basin has experienced, contributing to an understanding of hydrocarbon maturity. Proxy kerogen kinetics are assessed to estimate the petroleum prospectivity of the sub-basin and attempt to understand the timing and nature of hydrocarbon generation. Combined, these newly modelled data provide insights into the resource potential of this frontier Proterozoic hydrocarbon province, delivering foundational data to support explorers across the eastern Northern Territory and northwest Queensland.</div> <b>Citation:</b> Palu Tehani J., Grosjean Emmanuelle, Wang Liuqi, Boreham Christopher J., Bailey Adam H. E. (2023) Thermal history of the Carrara Sub-basin: insights from modelling of the NDI Carrara 1 drill hole. <i>The APPEA Journal</i><b> 63</b>, S263-S268. https://doi.org/10.1071/AJ22048

<div>Lateral variation in maturity of potential Devonian source rocks in the Adavale Basin has been investigated using nine 1D burial, thermal and petroleum generation history models, constructed using existing open file data. These models provide an estimate of the hydrocarbon generation potential of the basin. Total organic carbon (TOC) content and pyrolysis data indicate that the Log Creek Formation, Bury Limestone and shale units of the Buckabie Formation have the most potential as source rocks. The Log Creek Formation and the Bury Limestone are the most likely targets for unconventional gas exploration.</div><div>The models were constructed using geological information from well completion reports to assign formation tops and stratigraphic ages, and then forward model the evolution of geophysical parameters. The rock parameters, including facies, temperature, organic geochemistry and petrology, were used to investigate source rock quality, maturity and kerogen type. Suitable boundary conditions were assigned for paleo-heat flow, paleo-surface temperature and paleo-water depth. The resulting models were calibrated using bottom hole temperature and measured vitrinite reflectance data.</div><div>The results correspond well with published heat flow predictions, although a few wells show possible localised heat effects that differ from the basin average. The models indicate that three major burial events contribute to the maturation of the Devonian source rocks, the first occurring from the Late Devonian to early Carboniferous during maximum deposition of the Adavale Basin, the second in the Late Triassic during maximum deposition of the Galilee Basin, and the third in the Late Cretaceous during maximum deposition of the Eromanga Basin. Generation in the southeastern area appears to have not been effected by the second and third burial events, with hydrocarbon generation only modelled during the Late Devonian to early Carboniferous event. This suggests that Galilee Basin deposition was not significant or was absent in this area. Any potential hydrocarbon accumulations could be trapped in Devonian sandstone, limestone and mudstone units, as well as overlying younger sediments of the Mesozoic Eromanga Basin. Migration of the expelled hydrocarbons may be restricted by overlying regional seals, such as the Wallumbilla Formation of the Eromanga Basin. Unconventional hydrocarbons are a likely target for exploration in the Adavale Basin, with potential for tight or shale gas from the Log Creek Formation and Bury Limestone in favourable areas.</div>

<div>The Adavale Basin is located approximately 850 km west-northwest of Brisbane and southwest of Longreach in south-central Queensland. The basin system covers approximately 100,000 km2 and represents an Early to Late Devonian (Pragian to Famennian) depositional episode, which was terminated in the Famennian by widespread contractional deformation, regional uplift and erosion. </div><div>Burial and thermal history models were constructed for nine wells using existing open file data to assess the lateral variation in maturity and temperature for potential source rocks in the Adavale Basin, and to provide an estimate of the hydrocarbon generation potential in the region.</div>

<div>Lateral variation in maturity of potential Devonian source rocks in the Adavale Basin have been investigated using nine 1D burial thermal and petroleum generation history models, constructed using existing open file data. These models provide an estimate of the hydrocarbon generation potential of the basin. Total organic carbon (TOC) content and pyrolysis data indicate that the Log Creek Formation, Bury Limestone and shale units of the Buckabie Formation have the most potential as source rocks. The Log Creek Formation and the Bury Limestone are the most likely targets for unconventional gas exploration.</div><div>&nbsp;</div><div>The models were constructed used geological information from well completion reports to assign formation tops and stratigraphic ages to then forward-model the evolution of geophysical parameters. The rock parameters, including facies, temperature, organic geochemistry/petrology, were used to investigate source rock quality, maturity and kerogen type. Suitable boundary conditions were assigned for paleo-heat flow, paleo-surface temperature and paleo-water depth. The resulting models were calibrated using bottom hole temperature and measured vitrinite reflectance data.</div><div>&nbsp;</div><div>The results correspond relatively well with published heat flow predictions, however a few wells show possible localised heat effects that differ from the overall basin average. The models indicate full maturation of the Devonian source rocks with generation occurring during the Carboniferous and again during the Late Cretaceous. Any potential accumulations may be trapped in Devonian sandstone, limestone and mudstone units, as well as overlying younger sediments of the Mesozoic Eromanga Basin. Accumulations could be trapped by localised deposits of the Cooladdi Dolomite and other marine, terrestrial clastic and evaporite units around the basin. Migration of the expelled hydrocarbons may be restricted by overlying regional seals, such as the Wallumbilla Formation of the Eromanga Basin. Unconventional hydrocarbons are a likely target for the Adavale Basin with potential either for tight or shale gas in favourable areas from the Log Creek Formation and Bury Limestone.</div> This Abstract was submitted/presented to the 2023 Australian Exploration Geoscience Conference 13-18 Mar (https://2023.aegc.com.au/)