Apart from within the Arumbera Sandstone that spans the Ediacaran-Cambrian boundary, the entire Neoproterozoic succession of the Amadeus Basin has been generally believed to be devoid of metazoan fossils, despite features of possible biogenic origin having been described in the earliest geological mapping reports. Herein are described a suite of curious, rounded impressions preserved upon the surface of a sandstone bed from the basal Neoproterozoic unit, the quartzitic Heavitree Formation that dates to ca 850 Ma. Compared with rounded structures of both organic and inorganic origin, these features resemble fossils of stranded medusae, both modern and ancient, and thereby add a potentially pelagic lifeform to previously described burrowing and sessile forms of likely metazoans, which are preserved as fossils/trace fossils within the Tonian period of the Neoproterozoic elsewhere in the basin. An organic origin for these features would support the contention that the Amadeus Basin harbours the earliest evidence that macroscopic life flourished, albeit briefly, some 215 million years prior to the start of the Ediacaran period and 250 million years before metazoans successfully colonised the late Ediacaran seas.

In the Beetaloo Sub-basin, the Kyalla Formation is unconformably overlain by a late Mesoproterozoic to early Neoproterozoic sandstone to mudstone succession comprising three formations/units: the lower Jamison sandstone, the upper Jamison sandstone, and the Hayfield mudstone (Munson, 2016; pers. comm. 2022). Gorter and Grey (2013) subdivided the Jamison sandstone into two mappable units separated by an unconformity. The Jamison sandstone and overlying Hayfield mudstone represent a marked change in provenance and were deposited after the Musgrave Orogeny in a basin dominated by silciclastic sedimentation that may have formed a shallow, long-wavelength foreland basin to areas uplifted during the Musgrave Orogeny.

Summary The Cunaloo Limestone Member of the Locker Shale (Kockatea Shale facies) from the Carnarvon Basin contains a distinctive conodont zone also seen in the informally named ‘Limestone Marker’ in the lower Kockatea Shale of the northern Perth Basin. The boundary between the Induan (Dienerian) and the Olenekian (Smithian) is selected at the base of the incoming of the conodont Novispathodus waageni eowaageni in this core and provides an important biostratigraphic correlation point between the two basins. The Cunaloo Limestone Member contains Novispathodus dieneri-Neospathodus waageni- Scythogondolella milleri conodont zone species and this correlates with upper Bed 32 at the type section of the Permian-Triassic transition at the Meishan Permian-Triassic stratotype section D in China, dated by zircon U/Pb as about 251.5 Ma. This suggests an absolute age correlation of the lower part of the Kraeuselisporites saeptatus palynological zone in the southern Carnarvon Basin. This conodont zone is Smithian in age. A thin, apparently discontinuous, previously un-named limestone appears above the Cunaloo Limestone Member and is within the K. saeptatus zone. This carbonate unit becomes more prominent towards the north and contains conodonts, mostly fragmentary, of Smithian age. It is here named the Lawley Limestone Member. The Chiosella timorensis conodont zone occurs within Core 1 in the Candace Member of Cunaloo-1 and lies within the basal Tigrisporites playfordii palynozone. The First Appearance Datum (FAD) of the conodont C. timorensis has been proposed as an index for the worldwide recognition of the Olenekian-Anisian Boundary (OAB), although the species occurs first with upper Spathian Haugi Zone ammonoids. Nevertheless, it is a good approximation of the OAB, and therefore places the earliest occurrence of the T. playfordii palynozone in Western Australia at around the end of the Spathian-earliest Anisian (Aegean), about 247.2 Ma. A younger limestone, the Sholl Limestone Member of the Locker Shale facies, is recognised only from the Carnarvon Basin. This carbonate lies within the T. playfordii zone, but conodonts recovered from the unit are not age diagnostic. The Sholl Limestone is missing in several wells below sandstones of younger Triassic age, and in one case may be faulted out (e.g. Hampton-1). Recognition of these Early Triassic limestones allows a better stratigraphic understanding of those regions from the marine realm in the northern Perth and Carnarvon basins.

High-precision radioisotopic dating using Chemical Abrasion-Isotope Dilution Thermal Ionisation Mass Spectrometry (CA-IDTIMS) has been undertaken to allow the recalibration of the numerical ages of Permian and Triassic spore-pollen palynozones. These changes have been significant, with some zonal boundaries in the Permian changing by as much as 6 million years, and some in the Triassic changing by more than twice as much. Most of the samples analysed have come from Eastern Australian coal basins (Sydney, Gunnedah, Bowen) where abundant ash beds are scattered through the coal-bearing successions. The recalibrations of these widely used palynozones have implications for the timing of stratigraphic events far beyond the basins whence the samples came. Our revised dates for the Permian and Triassic palynozones can now be applied to all Permian and Triassic basins across Australia, from the Perth, Carnarvon, Roebuck, Canning, and Bonaparte basins along the western and northern continental margins, the Cooper and Galilee basins in central Australia, and the Bowen, Gunnedah and Sydney basins in eastern Australia. Revised regional stratigraphic frameworks presented here include the Perth, Bonaparte, Cooper, Galilee and Sydney basins. The impact of an improved calibration of biostratigraphic zones to the numerical timescale is broad and far-reaching. For example, accurate stratigraphic ages are required for reliable burial history modelling, impacting on the prediction of kerogen maturation, hydrocarbon expulsion and migration. Basin models that utilise these improved age interpretations will more closely approximate the true basin history. These improvements can in turn be expected to translate in to better exploration outcomes. So far, we have focused on the Permian and Triassic, but plan to expand recalibrations to include the Jurassic and Cretaceous successions. Preliminary data indicates that significant changes to these calibrations are also likely.

PreviousNext You have accessInternational Conference and Exhibition, Melbourne, Australia 13-16 September 2015A Geochemical Overview of Gippsland Basin Hydrocarbon AccumulationsAuthors: Dianne S. Edwards*Manzur AhmedTom BerneckerChristopher J. BorehamJunhong ChenSe GongLouise Goldie-DivkoJohn GorterLisa HallRobert P. LangfordCameron MitchellHerbert VolkDianne S. Edwards* Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Manzur Ahmed Energy Flagship, CSIRO, Sydney, New South Wales, Australia.Search for more papers by this author, Tom Bernecker Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Christopher J. Boreham Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Junhong Chen Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Se Gong Energy Flagship, CSIRO, Sydney, New South Wales, Australia.Search for more papers by this author, Louise Goldie-Divko Earth Resources, Geological Survey of Victoria, Melbourne, Victoria, Australia.Search for more papers by this author, John Gorter Exploration & Production Division, ENI, Milan, Italy.Search for more papers by this author, Lisa Hall Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Robert P. Langford Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, Cameron Mitchell Resources Division, Geoscience Australia, Canberra, Australian Capital Territory, Australia.Search for more papers by this author, and Herbert Volk Energy Flagship, CSIRO, Sydney, New South Wales, Australia.Search for more papers by this authorhttps://doi.org/10.1190/ice2015-2210785 SectionsAbout ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract In the 50 years since the first commercial discovery in 1965 at Barracouta-1, and 46 years since production commenced from the Barracouta field, a total of 16.5 TCF of gas, 4026 MMbbl of oil, 385 MMbbl of condensate and 752 MMbbl of LPG have been found in the Gippsland Basin (Estimated Ultimate Recovery, as at the end of 2012). Despite these extensive resources, all from Cretaceous–Paleogene Latrobe Group reservoirs, there are questions regarding the operating petroleum systems, contributing source rock units, and the migration pathways between source and reservoir. Resolution of these uncertainties is essential to improve our understanding of the remaining prospectivity and for creating new exploration opportunities, particularly in the eastern, less explored part of the basin, but also for mitigating risk for the potential sequestration of carbon dioxide along the southern and western flanks. Geochemical fingerprinting of reservoir fluids has identified that the oil and gas originate from multiple sources. The most pervasive hydrocarbon charge into the largely produced fields overlying the Central Deep has a terrestrial source affinity, originating from lower coastal plain facies (Kingfish, Halibut, Mackerel), yet the oils cannot be correlated using source-related biomarker parameters to source rocks either within the Halibut Subgroup (F. longus biozone) at Volador-1, one of the deepest penetrations of the Upper Cretaceous section, or to older sections, penetrated on the flanks of the basin. However, within the underlying Santonian–Campanian Golden Beach Subgroup an oil-source correlation has been established between the Anemone-1A oil and the marginal marine Anemone Formation (N. senectus biozone) at Anemone-1/1A and Archer-1. A similar correlation is indicated for the Angler-1 condensate to the Chimaera Formation (T. lilliei biozone) in the deepest section at Volador-1 and Hermes-1. In the Longtom field, gas reservoired within the Turonian Emperor Subgroup, potentially has a source from either the lacustrine Kipper Shale or the Albian portion of the Strzelecki Group. The molecular and carbon isotopic signatures of oil and gas from the onshore Wombat field are most similar to hydrocarbons sourced from the Aptian–Albian Eumeralla Formation in the Otway Basin, also implicating a Strzelecki source in the Gippsland Basin. These results imply that sediments older than the Paleocene are significant sources of petroleum within the basin. Keywords: Gippsland Basin, geochemical, hydrocarbonPermalink: https://doi.org/10.1190/ice2015-2210785FiguresReferencesRelatedDetailsCited byThe story of Esso Australia’s push to explore the frontier Gippsland Basin with the ultra-deep water Sculpin-1 exploration well13 May 2022 | The APPEA Journal, Vol. 62, No. 2 International Conference and Exhibition, Melbourne, Australia 13-16 September 2015ISSN (online):2159-6832Copyright: 2015 Pages: 564 publication data© 2015 Published in electronic format with permission by the Society of Exploration Geophysicists and the American Association of Petroleum GeologistsPublisher:Society of Exploration Geophysicists HistoryPublished Online: 16 Sep 2015 CITATION INFORMATION Dianne S. Edwards*, Manzur Ahmed, Tom Bernecker, Christopher J. Boreham, Junhong Chen, Se Gong, Louise Goldie-Divko, John Gorter, Lisa Hall, Robert P. Langford, Cameron Mitchell, and Herbert Volk, (2015), "A Geochemical Overview of Gippsland Basin Hydrocarbon Accumulations," SEG Global Meeting Abstracts : 281-281. https://doi.org/10.1190/ice2015-2210785 Plain-Language Summary KeywordsGippsland BasingeochemicalhydrocarbonLoading ...

Gas was discovered in intra-Mt Goodwin Sub-group sandstones (Ascalon Formation) of the southeastern Bonaparte Basin in Blacktip–1 in 2001 from a zone characterised by a discrete seismic amplitude anomaly. This integrated study uses wireline logs, cores, cuttings, palynology, micropaleontology and geochemical analyses to determine the depositional environment of the Mt Goodwin Sub-group reservoirs and the source rock potential of this large, latest Permian (Changhsingian) to Early Triassic (Induan Olenekian) section of the Bonaparte Basin in northern Australia. Specific outcomes include a better understanding of the Early Triassic reservoir sandstone depositional environment and recognition of marker horizons on electric logs and seismic profiles, resulting in a more consistent regional interpretive framework for the uppermost Permian (Changhsingian) and Early Triassic (Induan Olenekian), in the Bonaparte Basin.

Several sedimentary basins in Western Australia contain petroleum reservoirs of Late Permian or older age that are overlain by thick shaly sequences (400–2,000 m) that have been assigned an Early Triassic age. The age of the base of the Triassic shales has been, and continues to be, contentious with strata being variously ascribed to the latest Permian (Changhsingian Stage) or wholly in the earliest Triassic (Induan Stage). In the Perth Basin the Permian-Triassic boundary appears to be located somewhere in the Hovea Member of the Kockatea Shale. In the Bonaparte Basin, the boundary would appear to be either in the uppermost Penguin Formation or at the boundary between the Penguin and Mairmull formations. The uncertainty of the boundary placement relates to the interpretation of the sedimentological, biostratigraphic and geochemical record in individual sections and basins. Major problems relate to the recognition, or even the presence of unconformities, complications related to the presence of reworked sediments and paleontological material (both conodonts and spore-pollen) and to the significance of geochemical shifts. The age of the basal Kockatea Shale (northern Perth Basin) and the basal Mt Goodwin Sub-group (Bonaparte Basin) is reassessed using palaeontological data, augmented by carbon isotopic measurements and geochemical analyses, supported by wireline log correlations and seismic profiles. The stratigraphy of the latest Permian to Early Triassic succession in the Bonaparte Basin is also revised, as is the nomenclature for the Early Triassic Arranoo Member of the Kockatea Shale in the northern Perth Basin. The Mt Goodwin Sub-group (new rank) is composed of the latest Permian Penguin Formation overlain by the Early Triassic Mairmull, Ascalon and Fishburn formations (all new).

Several sedimentary basins in west Australia contain petroleum reservoirs of Late Permian or older age that are overlain by thick shaly sequences (400–2,000 m) that have been assigned an Early Triassic age. The age of the base of the Triassic shales has been, and continues to be, contentious with strata being variously ascribed to the latest Permian (Changhsingian Stage) or wholly within the earliest Triassic (Induan Stage). In the Perth Basin the Permian-Triassic boundary appears to be located somewhere in the Hovea Member of the Kockatea Shale. In the Bonaparte Basin, the boundary would appear to be either in the uppermost Penguin Formation or at the boundary between the Penguin and Mairmull formations. The uncertainty of the boundary placement relates to the interpretation of the sedimentological, biostratigraphic and geochemical record in individual sections and basins. Major problems relate to the recognition, or even the presence of unconformities, complications related to

Glacial deposits within the Lower Kulshill Group (Late Carboniferous-Early Permian) were initially recognised in cores from onshore wells in the southeastern Bonaparte Basin in the 1960s. Subsequent offshore wells have extended the distribution of the glaciogene units 100 km to the north. Their capacity to entrap oil and gas was proven by the Turtle and Barnett wells, located on the offshore Turtle High. Similar age glaciogene rocks occur within the Cooper Basin of central Australia, where they contain oil and gas reserves, and in the Canning, Carnarvon and Perth basins of Western Australia. Using sparse cores, electric logs, palynology and a sequence stratigraphic interpretation of 2D seismic data, the distribution of potential reservoir sandstones and sealing lithologies of the glaciogenic strata has been mapped for the offshore southeastern Bonaparte Basin. This study highlights the petroleum trapping potential associated with sub-glacial ice tunnel valley features, which are widespread in the offshore part of the basin.

A fauna of reworked conodonts from a lithic sandstone in the Ellery Creek Fan of the Late Devonian Brewer Conglomerate comprises mostly unidentifiable, elongate, rounded fragments indicating erosion to discrete grain particles prior to redeposition. The fauna is of mixed age, consisting of Early Ordovician (Aloxoconus iowaensis) and Furongian, latest Cambrian, (Hirsutodontus simplex) elements implying sourcing from multiple stratigraphic units. The latter species has not been recovered previously from the Amadeus Basin despite extensive sampling of Cambro-Ordovician units. Another small conodont fauna obtained from a large limestone clast from a conglomerate in the Late Devonian Hermannsburg Sandstone includes Oepikodus cleftus, previously recorded from the lower part of the Early Ordovician Horn Valley Siltstone. These conodonts suggest that the northern depositional edge of the Amadeus Basin lay far to the north of the present structural and erosional northern margin of the basin. The elements have a conodont color alteration index (CAI) of 1 indicating that they have never been deeply buried, either originally or after reworking.

Pre-Middle Devonian conodonts recovered from ten wells and drillholes in the Carnarvon Basin provide improved age control for, and are the basis for a revision of, the Silurian stratigraphy and depositional history in the basin: The lithologically distinctive siliciclastic unit at the base of the Dirk Hartog Group, in the Ajana Formation, is called the Marron Member (new name). The Yaringa Evaporite is re-named the Yaringa Formation in recognition of the limited portion of the basin in which evaporites dominate this unit. The uppermost unit of the Dirk Hartog Group is renamed the Coburn Formation. Age control is provided by six conodont faunas: a fauna of probable Early Ordovician Age from the middle part of the Ajana Formation in Wandagee 1 may be reworked and thus not age diagnostic. The upper, un-named, part of the Ajana Formation and the overlying Yaringa Formation contain a Silurian base be as upper Formation siludcus upper-most part Amydrotaxis n. sp. to Pridoli the

The Hooray Sandstone (Namur Sandstone Member and overlying Murta Member) was deposited during the Early Cretaceous in southwestern Queensland and northeastern South Australia. A sequence stratigraphie model for the Hooray is proposed. The basal beds of the Hooray Sandstone are the braided fluvial deposits of the Namur Sandstone Member, deposited during the late Berriasian and earliest Valanginian on a Type 1 sequence boundary developed during the 131.5 Ma sea level lowstand. Two sequences are recognised within the Namur (Namur Nl and N2) with a Type 1 sequence boundary interpreted within the member (128.5 Ma sea level fall). The upper Namur is gradational with the lower Murta Member M6 which forms a transgressive systems tract. The M5 and M4 are highstand systems tract sediments deposited over the maximum flooding surface at the base of the M5 (127.5 Ma condensed section). Low sea levels led to incision of channels basinwards of exposed basement rocks at the end of M4 time (about 126 Ma). Sea level rise led to the gradual Willing of these channels until the southeastern highlands were drowned but islands in the southeast contributed vitrinitic material during mid M3 time, which formed the source for the oil in the Nockatunga area. Reservoir sandstones are developed within the basal M3 incised valley fill sands and in the transgressive microtidal barrier facies sands at the top of the M3. The former can produce stratigraphic traps, whereas the latter form structural traps. Reservoir quality is probably best in the thicker mid 'estuarine' sands due to tidal reworking, and generally poorer in the barrier facies due to little winnowing of fines because of the low tidal range, weak wave activity, and gene-contemporaneous carbonate cementation. During later M3 time, transgression led to the landward movement of barrier bars, forming a generally sheet-like sand body. The top M2 and M3 barriers probably formed in a microtidal environment under a seasonal climate with periodic storm conditions. Following inundation of the islands during M2 and Ml times, organic matter supplied to the Nockatunga area was dominantly finely comminuted, bacterially-altered plant matter and algal material that forms a potentially rich but immature oil source. The 'hot gamma' shales of the Ml are interpreted as the 123.5 Ma condensed section.

The quantity of organic matter in the source beds within the Horn Valley Siltstone, as defined by the Total Organic Carbon content, increases westward from low values in the south and east of the Basin to maximum values in the Mt Winter and Mereenie areas. This westerly enrichment trend is paralleled by an improvement in source rock quality, as defined by the Hydrogen Index and Tmax crossplot of samples analysed by Rock-Eval pyrolysis.Earlier attempts to measure thermal maturation levels of source rocks in the Basin relied on the reflectivity of coalified graptolites but this method was only applicable to unweathered material obtained from the few and scattered bore holes in the Basin. In this study, conodont colour alteration is used to define organic maturation levels. This technique, newly applied in Australia, was used principally on samples collected from the Horn Valley Siltstone and has the practical advantage of being applicable to samples from both outcrop and subsurface localities.The study indicates that the conodont colour alteration isograds in the Amadeus Basin are primarily related to events of the Alice Springs Orogeny, when the thick mass of molasse sediments (Pertnjara Group) resulting from erosion of the uplifted Arunta Block was deposited. Anomalies in the conodont colour isograds are closely related to timing of structural growth during the orogeny and also possibly to the growth of salt structures.In addition, the study shows that burial at depths below 1500 m will have led to the catagenetic breakdown of reservoired oil and the production of only gaseous hydrocarbons from source beds.In combination, these two factors lead to the conclusion that the most prospective area for oil sourced by the Horn Valley Siltstone is north and west of the Mereenie Oil Field in areas of shallow burial.

Examination of conodont colour alteration (CAI) in samples from more than 40 petroleum exploration wells and extensive outcrop collections along the northern margin of the Lennard Shelf forms the basis for a study of the thermal maturation and geothermal history of the Canning Basin of Western Australia. The thickness of the measured CAI intervals is variable and does not conform to the 1200 m standard of the Appalachian Basin. The CAI interval 1 is thick and indicates a low geothermal gradient in the basin but CAI intervals 1.5 and 2 are thin and indicate higher geothermal gradients. A major thermal event of Miocene Age, associated with the intrusion of the Fltzroy Lamproites in the Fitzroy Graben and Lennard Shelf, may be the source of the increased heat flow and also explain an area of high heat flow in some parts of the Graben and shelf.Using the vertical and horizontal distribution of trends of the CAI intervals it is suggested that over large areas of the basin the oil generation window is restricted to an interval about 1100 m thick and, except where migration has taken place, that liquid hydrocarbons will be restricted to the interval between 1600 and 3000 m. In areas affected by the intrusion of the Fitzroy Lamproites, the top of the oil generation window may be as shallow as 800 m.