Australia is about to become the premier global exporter of liquefied natural gas (LNG), bringing increased opportunities for helium extraction. Processing of natural gas to LNG necessitates the exclusion and disposal of nonhydrocarbon components, principally carbon dioxide and nitrogen. Minor to trace hydrogen, helium and higher noble gases in the LNG feed-in gas become concentrated with nitrogen in the non-condensable LNG tail gas. Helium is commercially extracted worldwide from this LNG tail gas. Australia has one helium plant in Darwin where gas (containing 0.1% He) from the Bayu-Undan accumulation in the Bonaparte Basin is processed for LNG and the tail gas, enriched in helium (3%), is the feedstock for helium extraction. With current and proposed LNG facilities across Australia, it is timely to determine whether the development of other accumulations offers similar potential. Geoscience Australia has obtained helium contents in ~800 Australian natural gases covering all hydrocarbon-producing sedimentary basins. Additionally, the origin of helium has been investigated using the integration of helium, neon and argon isotopes, as well as the stable carbon (13C/12C) isotopes of carbon dioxide and hydrocarbon gases and isotopes (15N/14N) of nitrogen. With no apparent loss of helium and nitrogen throughout the LNG industrial process, together with the estimated remaining resources of gas accumulations, a helium volumetric seriatim results in the Greater Sunrise (Bonaparte Basin) > Ichthys (Browse Basin) > Goodwyn–North Rankin (Northern Carnarvon Basin) accumulations having considerably more untapped economic value in helium extraction than the commercial Bayu-Undan LNG development.

The Browse Basin is located offshore on Australia's North West Shelf and is a proven hydrocarbon province hosting gas with associated condensate; however, oil reserves are small. The assessment of a basin's oil potential traditionally focusses on either the presence or absence of oil-prone source rocks. However, light oil can be found in basins where the primary hydrocarbon type is gas-condensate and oil rims form whenever these fluids migrate into reservoirs at pressures below their dew point (or saturation pressure). The relationship between dew point pressure and condensate-gas ratio (CGR) depends on the liquid composition and is therefore a petroleum system characteristic (Fig. 1). By combining geochemical studies of source rocks and fluids with petroleum systems analysis, the four Mesozoic petroleum systems identified by their geochemical fingerprints (Rollet et al., 2016) can be correlated with several gas-prone (dew point) petroleum systems: 1. Gas-condensates generated and reservoired within the Lower-Middle Jurassic Plover Formation are derived from terrestrial organic matter in fluvio-deltaic to pro-deltaic environments. Such gas is dominated by methane (gas dryness* = 91%), with ideal gas condensate ratios (CGRs) ranging between 7 and 35 bbl/MMscf. Liquids recovered from wells tested along the Scott Reef Trend (e.g. Calliance, Brecknock and Torosa) comprise pale yellow condensates (49-53° API gravity), as do those from the deepest (Plover) reservoirs within the Ichthys gas accumulation (e.g. Gorgonichthys). These liquids plot on Figure 1 as dew point fluids. The molecular and carbon isotopic signatures of these condensates are similar, classifiying them into a single family (W1_1BRO) in Figure 2. The biomarkers providing the strongest discrimination are the high relative abundances of C29 sterane and C19 tricyclic triterpane, coupled with an enrichment in delta13C of their saturated and aromatic hydrocarbon fractions testifies to their terrestrial organic origin. 2. Fluids with similar bulk properties (gas dryness = 91%; ideal CGRs 27-52 bbl/MMscf) to those of the aformentioned Plover-sourced fluids are found in the greater Crux accumulation in the Heywood Graben. The pale yellow condensates (47°API gravity) also exhibit similar biomarker assemblages as the W1_1BRO family. However, due to their greater enrichment in delta13C, the condensates plot as a separate family (W1_2BRO) in Figure 2. A difference in thermal maturity is also noted, with the Crux accumulation having lower maturity (calculated vitrinite reflectance# [Rc] = 0.77%) relative to the condensates on the Scott Reef Trend (av Rc = 1.18%). The most likely source rocks for the Crux fluids are the terrestrially-dominated Plover Formation coals and shales, but shaly coals also occur within the thick Upper Jurassic section in the northern part of the basin. These fluids are categorised as a separate dew point system within the Heywood Graben (Fig. 1). 3. Gas-condensates reservoired within the Brewster Member of the upper Vulcan Formation in the Ichthys/Prelude and Burnside accumulations have a greater liquid content than the aformentioned gases, with ideal CGRs of 22-151 bbl/MMscf at Titanichthys 1 and a gas dryness of 84%. The pale yellow condensates have API gravities of 55° and are potentially a separate intraformational dew point petroleum system within the central Caswell Sub-basin. Their biomarker and isotopic signatures indicate derivation from mixed marine and land-plant organic matter and plot as another family (W2W3_1BRO; Fig. 2). The source of these fluids is probably the organic-rich shales of the Upper Jurassic-Lower Cretaceous Vulcan Formation that encase the Brewster Member sandstone reservoir. PVT data for Brewster-reservoired fluids is affected by synthetic mud contamination, which has an impact on the measured dew point pressures. In the absence of measured values, a similar phase behaviour to North Sea (UK) gas-condensates (England, 2002) is assumed. 4. The Cretaceous reservoir in Caswell contains an unbiodegraded brown 'light oil' (47°API gravity) but PVT data are not available. Biomarker and isotope signatures show that the liquids were generated from source rocks containing both marine and terrigenous organic matter lying within the early oil window (Rc# = 0.75%). They correlate with the Yampi Shelf biodegraded oils (W3_1BRO, Fig. 2), gas at Adele, and with extracts of the Lower Cretaceous Echuca Shoals Formation (Boreham et al., 1997). However, these marine shales have low hydrogen indices (~200 mg hydrocarbons/gTOC) and hence may only be able to expel sufficient hydrocarbons to sustain migration over short distances. Since biodegraded solution gases in the Yampi Shelf accumulations contain neo-pentane - a highly resistant compound - with isotopic affinity to Plover Formation generated fluids, it is possible that Cretaceous-sourced liquids were mobilised and carried to the shelf edge by co-migrating Plover-derived gas.

<div>The bulk oils database table contains publicly available results from Geoscience Australia's organic geochemistry (ORGCHEM) schema and supporting oracle databases for the bulk properties of petroleum liquids (e.g., condensate, crude oil, bitumen) sampled from boreholes and field sites. The analyses are performed by various laboratories in service and exploration companies, Australian government institutions, and universities using a range of instruments. Petroleum is composed primarily of hydrocarbons (carbon and hydrogen) with minor quantities of heterocyclic compounds containing either nitrogen, oxygen or sulfur. Data includes the borehole or field site location, sample depth, shows and tests, stratigraphy, analytical methods, other relevant metadata, and various data types including; API gravity, elemental composition and photographs of the samples. The stable carbon (¹³C/¹²C) and hydrogen (²H/¹H) isotopic ratios of crude oil and derivative saturated and aromatic hydrocarbon fractions are presented in parts per mil (‰) and in delta notation as &delta;¹³C and &delta;²H, respectively. Results are also included from methods that separate crude oils into bulk components, such as the quantification of saturated hydrocarbon, aromatic hydrocarbon, resin, and asphaltene (SARA) fractions according to their polarity.</div><div><br></div><div>These data provide information about the petroleum fluid’s composition, source, thermal maturity, secondary alteration, and fluid migration pathways. They are also useful for enhanced oil recovery assessments, petroleum systems mapping and basin modelling. Hence, these sample-based datasets are used for the discovery and evaluation 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 bulk oils data are delivered in the Petroleum Bulk Properties and Stable Isotopes web services on the Geoscience Australia Data Discovery Portal at https://portal.ga.gov.au which will be periodically updated.</div>

<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>

<div>The Paleo- to Mesoproterozoic Birrindudu Basin is an underexplored frontier basin straddling the Northern Territory and Western Australia and is a region of focus for the second phase of Geoscience Australia’s Exploring for the Future (EFTF) program (2020–2024). Hydrocarbon exploration in the Birrindudu Basin has been limited and a thorough assessment of the basin's petroleum potential is lacking due to the absence of data in the region. To fill this data gap, a comprehensive analytical program including organic petrology, programmed pyrolysis and oil fluid inclusion analysis was undertaken on cores from six drill holes to improve the understanding of the basin’s source rock potential and assess petroleum migration. Organic petrological analyses reveal that the primary maceral identified in the cores is alginite mainly originating from filamentous cyanobacteria, while bitumen is the most common unstructured secondary organic matter. New reflectance data based on alginite and bitumen reflectance indicate the sampled sections have reached a thermal maturity suitable for hydrocarbon generation. Oil inclusion analyses provide evidence for oil generation and migration, and hence elements of a petroleum system are present in the basin. Presented at the Australian Energy Producers (AEP) Conference & Exhibition (https://energyproducersconference.au/conference/)