Natural or native molecular hydrogen (H2) can be a major component in natural gas, and yet its role in the global energy sector’s usage as a clean energy carrier is not normally considered. Here, we update the scarce reporting of hydrogen in Australian natural gas with new compositional and isotopic analyses of H2 undertaken at Geoscience Australia. The dataset involves ~1000 natural gas samples from 470 wells in both sedimentary and non-sedimentary basins with reservoir rocks ranging in age from the Neoarchean to Cenozoic. Pathways to H2 formation can involve either organic matter intermediates and its association with biogenic natural gas or chemical synthesis and its presence in abiogenic natural gas. The latter reaction pathway generally leads to H2-rich (>10 mol% H2) gas in non-sedimentary rocks. Abiogenic H2 petroleum systems are described within concepts of source–migration–reservoir–seal but exploration approaches are different to biogenic natural gas. Rates of abiogenic H2 generation are governed by the availability of specific rock types and different mineral catalysts, and through chemical reactions and radiolysis of accessible water. Hydrogen can be differently trapped compared to hydrocarbon gases; for example, pore space can be created in fractured basement during abiogenic reactions, and clay minerals and evaporites can act as effective adsorbents, traps and seals. Underground storage of H2 within evaporites (specifically halite) and in depleted petroleum reservoirs will also have a role to play in the commercial exploitation of H2. Estimated H2 production rates mainly from water radiolysis in mafic–ultramafic and granitic rocks and serpentinisation of ultramafic–mafic rocks gives a H2 inferred resource potential between ~1.6 and ~58 MMm3 year-1 for onshore Australia down to a depth of 1 km. The prediction and subsequent identification of subsurface H2 that can be exploited remains enigmatic and awaits robust exploration guidelines and targeted drilling for proof of concept.

Subsurface microorganisms may respond to increased CO2 levels in ways that significantly affect pore fluid chemistry. Changes in CO2 concentration or speciation may result from the injection of supercritical CO2 (scCO2) into deep aquifers. Therefore, understanding subsurface microbial responses to scCO2, or unnaturally high levels of dissolved CO2, will help to evaluate the use of geosequestration to reduce atmospheric CO2 emissions. This study characterized microbial community changes at the 16S rRNA gene level during a scCO2 geosequestration experiment in the 1.4 km-deep Paaratte Formation of the Otway Basin, Australia. One hundred and fifty tons of mixed scCO2 and groundwater was pumped into the sandstone Paaratte aquifer over four days. A novel U-tube sampling system was used to obtain groundwater samples under in situ temperature and pressure conditions for geochemical analyses and DNA extraction. Decreases in pH and temperature of 2.6 log units and 5.8oC, respectively, were observed. Polyethylene glycols (PEGs) were detected in the groundwater prior to scCO2 injection and were interpreted as residual from drilling fluid used during the emplacement of the CO2 injection well. Changes in microbial community structure prior to scCO2 injection revealed a general shift from Firmicutes to Proteobacteria concurrent with the disappearance of PEGs. However, the scCO2 injection event, including changes in response to the associated variables (e.g., pH, temperature and salinity), resulted in increases in the relative abundances of Comamonadaceae and Sphingomonadaceae suggesting the potential for enhanced scCO2 tolerance of these groups. This study demonstrates a successful new in situ sampling approach for detecting microbial community changes associated with an scCO2 geosequestration event.

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 non-hydrocarbon 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 critical success factors that control hydrocarbon prospectivity in the Otway Basin have been investigated using petroleum systems approaches. It have revealed that greater than 99% of the discovered hydrocarbons in the Victorian Otway Basin have been sourced from Austral 2 (Albian-Aptian) source rocks and that these Austral 2-sourced hydrocarbon accumulations either directly overlie—or are located within 3,000 m—of actively generating Austral 2 source rock kitchens. Importantly, the zones of greatest prospectivity are located where these source rocks have been actively generating and expelling hydrocarbons throughout the Late Paleogene, primarily as a result of sediment loading associated with progradation of the Heytesbury shelfal carbonates. This peak generation window occurs at an average depth of approximately 2,500–3,500 m sub-mud across much of the basin, which has allowed prospective hydrocarbon fairways to be mapped out, thereby highlighting areas of greatest prospectivity. The close spatial proximity of the actively generating source rocks to the accumulations is due to several factors, which include overall poor fault seal in the basin (success cases occur where charge rate exceeds leakage rate) and relatively complex and tortuous migration fairways (which means that large volumes of hydrocarbons are only focussed and migrate for relatively short distances). In areas within which the Austral 2 system comprises the sole hydrocarbon charge—such as across the inner Mussel Platform—the reservoired gas compositions are typically very dry. In contrast, the gas compositions in accumulations sited along or immediately inboard of the Mussel-Tartwaup Fault Zone (La Bella, Geographe and Thylacine) are significantly wetter and also have higher CO2 contents. Throughout this area, the wetter components of the reservoired hydrocarbon inventory may have a source contribution from within the basal (Turonian) part of the younger Austral 3 system, in sequences that have been confirmed by dTLogR analysis to be significantly enriched in total organic carbon content. This observation has significantly upgraded the potential of the upper shelf areas, where a relatively more liquids-rich hydrocarbon inventory might be expected. The CO2 in accumulations located along the Mussel-Tartwaup Fault Zone is interpreted, based upon new helium isotope data, to be of mixed deep crustal-magmatic origin. This CO2 is believed to have migrated from great depth up the crustal-scale fault arrays into the shallower Late Cretaceous reservoirs. Here, the CO2 mixed with crustal gases, typified by helium with a mixed magmatic-crustal isotopic signature. Throughout this area, the traps tend to be large and hence—even though their CO2 contents are only 8–12%—the total CO2 volumes contained in these accumulations are much greater than those in the very CO2-rich—but volumetrically small traps—located onshore (e.g. Boggy Creek). Hydrocarbon accumulations located on the inner shelf, such as Minerva and Casino, have distinctly lower CO2 contents, perhaps because large displacement, through-going faults are lacking in this area. These observations collectively provide a predictive regional framework for understanding the likely distribution of commercial hydrocarbon accumulations in the offshore Otway Basin, as well as for forecasting the gas wetnesses and CO2 contents of undrilled exploration targets in both well-explored and frontier parts of the basin.

As part of the Australian Government’s Energy Security Initiative, a new tectono-stratigraphic and petroleum systems study has been carried out in the Vlaming Sub-basin on Australia’s southwest continental margin. The study has included: biostratigraphic revisions for key wells; seismic interpretations of new and reprocessed data; geochemical assessments of key source rock intervals and liquid hydrocarbons; structural restoration of key seismic sections; and, 3D burial history modelling. Results have significantly improved our understanding of the Vlaming Sub-basin’s evolution and provide a basis for future exploration. New exploration opportunities in the southern Vlaming Sub-basin are open to explorers through the Australian Government’s 2008 Acreage Release.

The Gippsland Basin is one of the most prolific petroleum provinces in Australia, yet the understanding of source, migration and secondary alteration of petroleum is often based on data and concepts that have been developed decades ago. For instance, the Gippsland Basin is commonly cited as an explicit example of a province dominated by oil from coal, yet there is no literature using molecular and isotope geochemistry explicitly demonstrating that generation and expulsion has been from the coal seams and not the intervening carbonaceous mudstones. In this study we will present insights from the evaluation of quantitative analyses of aromatic hydrocarbons, which will be evaluated together with low molecular weight hydrocarbon distributions from whole oil gas chromatography and aliphatic biomarker distributions of the oils. Oils are commonly incrementors of different charge events, and hence extending molecular and isotopic information from a wide molecular weight range offers a more detailed insight into the charge history of an oil field. Oil-bearing fluid inclusions are additional archives that hold keys to the fill history of petroleum reservoirs, and this contribution will also present new data on the distribution and composition of palaeo-oils trapped in fluid inclusions. Lastly, examples will be presented of how modern tools for analysis such as compound specific isotopic analysis (CSIA) of n-alkanes and isoprenoids as well as how understanding relationships between organic facies and source rock kinetics can contribute to refining our understanding of petroleum systems in the Gippsland Basin.