Hydrogen in Australian natural gas: occurrences, sources and resources

Keywords: Australian craton, hydrogen exploration, hydrogen isotopes, natural gas, natural/native hydrogen, resource potential, serpentinisation, water radiolysis.

Molecular hydrogen (i.e. H₂) is the most energy-rich gas. The global energy sector is transforming and hydrogen is likely to play an increasingly prominent role as a clean energy carrier. Countries, such as Germany, Japan and South Korea, that are heavily reliant on imported fossil fuels, have identified hydrogen as a key pathway to decarbonise their transport, industry processes, heating and energy storage sectors (see FMEAE 2020, METI 2017 and MOTIE 2019, respectively). Fossil fuel exporting countries, such as Australia, have ambitions to develop large-scale hydrogen export industries (COAG Energy Council Hydrogen Working Group 2019; AusH2 2020). Hydrogen is almost exclusively manufactured for industrial use, with around 70 million metric tonnes (840 Bm³) per year being produced worldwide (Wood Mackenzie 2021). It can be produced artificially via a variety of different pathways (Nikolaidis and Poullikkas 2017) with the primary methods for production of hydrogen with low carbon emissions being (a) water electrolysis using renewable energy (green hydrogen), (b) steam reformation of natural gas paired with carbon capture and storage (CCS; blue hydrogen) and (c) coal gasification combined with CCS (also blue hydrogen) (Adolf et al. 2017; Bruce et al. 2018; Nuttall and Bakenne 2020). The majority of produced hydrogen originates from hydrocarbon-based feedstock without CCS (grey hydrogen) since the economics for the electrolytic production of green hydrogen (0.1% of total H₂ production) requires improvement (Wood Mackenzie 2021). As of January 2021, there were over 50 hydrogen projects in development around Australia (AusH2 2020). For a large-scale hydrogen industry to develop, hydrogen storage is key. Hydrogen storage in salt caverns is considered the most promising approach for large-scale seasonal storage (HyUnder 2013; Caglayan et al. 2020). Examples of hydrogen storage in salt can be found in the United Kingdom (e.g. Teesside) and the United States of America (e.g. Clemens Dome, Spindletop and Moss Bluff). Hydrogen storage in depleted gas reservoirs is also being explored due to the greater spatial distribution of these underground geological resources, although impurity gases already contained within the gas field and reduction of sulfate to H₂S remain potential problems (Amid et al. 2016; Flesch et al. 2018; Caglayan et al. 2020).

Hydrogen is seemingly ubiquitous in the subsurface, being classified as either natural or native or geological – trivial names are white (https://www.beceptum.com/projects/detail/white-hydrogen/) and gold (Pizzo 2020) hydrogen – (hereafter referred to as natural). Hence, hydrogen is an integral component of natural gas but it is not generally considered in the accounting of H₂ resources for industrial usage (Nikolaidis and Poullikkas 2017). Moreover, it is important to understand H₂ sources and inferred resources, and to identify and characterise new and potential occurrences of natural H₂ from a geological perspective, as is highlighted herein by three case studies from the Australian continent. In the inventory of global H₂ inferred resources, Australian H₂ has been either under-represented (Truche et al. 2020; Zgonnik 2020) or not specifically estimated (Sherwood Lollar et al. 2014). Nevertheless, a recent multi-continent structural analysis of surface features that may indicate active H₂ seepage has suggested that Australia is one of the most promising regions for future exploration for natural H₂ (Moretti et al. 2021a). Our paper addresses deficiencies in the Australia-wide coverage, presents the H₂ content of a large dataset of Australian natural gases, and gives a first-order estimate of H₂ inferred resources from abiogenic sources. Our work also aims to assist with the development of a more robust H₂ exploration guideline that recognises natural H₂ as an increasingly attractive exploration target in Australia.

Natural hydrogen is present in a range of geological environments. For example, it occurs in crystalline basement, volcanic, ultramafic and peralkaline igneous complexes, geothermal and mineral systems, graphite, evaporite deposits and anoxic sediments, as well as in conventional and unconventional gas and oil fields, and coal seam gas (Gregory et al. 2019 and references therein). Hydrogen is recognised as a common component of natural gases (Goebel et al. 1984), although H₂-rich (i.e. >10 mol% H₂; Coveney et al. 1987) natural gases from sedimentary basins are rare (Smith et al. 2005; Zgonnik 2020). This is in part due to experimental/sampling bias because H₂ concentration is not routinely analysed. Since H₂ is mobile and chemically active, gases stored for millennia in reservoir rocks may require a continuous replenishment of H₂ from disparate source(s) (Dubessy et al. 1989; Zgonnik 2020). Interestingly, H₂ contents within gas and oil fields, in general, are commonly lower than surrounding rocks suggesting a chemical reaction between H₂ and the emplaced organic matter (Zgonnik 2020).

Zgonnik (2020) classified natural H₂ sources into two groups: primordial (primary) hydrogen stored within the earth’s hydridic core and mantle (Larin 1993; Walshe et al. 2005; Walshe 2006), and secondary hydrogen generated from chemical reactions within the mantle and crust. Natural H₂ can be regarded as having either an abiogenic (Reeves and Fiebig 2020 and references therein) or a biogenic source, of which the latter includes both thermogenic (Tissot and Welte 1984; Hunt 1996) and microbial (Nandi and Sengupta 1998; Hallenbeck and Benemann 2002) processes. The isotopic signature of H₂ can be used to help determine its origin. Fig. 1 shows the extensive range for δ²H H₂ of around –850 to –100‰, depending on the processes involved during H₂ liberation from secondary sources. Further, hydrogen isotopic equilibrium between H₂, hydrocarbons and water can alter the δ²H of the initially generated H₂. Nevertheless, serpentinisation and volcanism show the highest depletion and enrichment in ²H in H₂, respectively.

Fig. 1.  Hydrogen isotopic values (δ²H ‰) for H₂ measured for different geological environments, processes and rock types (modified after Hao et al. 2020). For each H₂ source, the δ²H H₂ range is displayed with the vertical dash line representing the mode(s). Atmospheric (troposphere) H₂ from Batenburg et al. (2011). From petroleum studies, the hydrogen isotopic composition of hydrocarbons include Australian natural gases (as reported herein), Australian methane (Boreham and Davies 2020) and Australian (topped) oil (Schimmelmann et al. 2004). The δ²H H₂ range for the Boomer deposit gases, Frog’s Leg Gold Camp, Western Australian goldfields (Boreham et al. 2021) complements the work provided herein. ‘CO₂ corrosion’ is data from Thiessen et al. (2009) on H₂ produced from steel drill pipe in the presence of natural gas with a high CO₂ content. ‘Corrosion’ in Hao et al. (2020) corresponds to potential corrosion of steel well casing from exposure to H₂S (Lyon and Hulston 1984), and to a long exposure of steel well casing at pH 2 (Feldbusch et al. 2018).

Hydrogen and helium (He) on earth have their roots in the formation of the universe and the solar system. Primordial H₂ was initially captured then dissociated to form a hydritic core and lower mantle during the formation of the earth (Rumyantsev 2016), estimated to be some 4.54 billion years ago ±50 million years (National Geographic 2021). Some consider primary H₂ resources infinite for human usage, if only accessible (Larin 1993; Zgonnik 2020; Moretti et al. 2021b).

Ultramafic rocks dominate the mantle and fluids in the lower mantle are likely to contain methane (CH₄), H₂ and water (H₂O), whereas in the upper mantle they comprise carbon dioxide (CO₂) and water. This primordial source of hydrogen is in the form of stored primary metal hydride and is considered the dominant form of hydrogen on earth (Zgonnik 2020 and references therein). These metal hydrides release H₂ through processes resulting in the continuous and intermittently violent injections into the upper mantle and crust. Such large-scale fluid migration can have major impacts on all earth processes within the upper lithosphere, biosphere, hydrosphere and atmosphere (Walshe et al. 2005; Walshe 2006).

Abiogenic sources of natural hydrogen are potentially the largest yet-to-find resources, although exploration for petroleum and the recovery of biogenic natural gas (with non-commercial H₂) is the largest currently exploited resource. Abiogenic H₂ might influence crustal redox chemistry that control deposition of ore mineralisation (Walshe et al. 2005; Zgonnik 2020), and hence the analysis of gases from mines would be beneficial (Boreham et al. 2021).

Numerous abiogenic sources of natural H₂ are summarised in Table 1, with serpentinisation, radiolysis and volcanic and hydrothermal vents being considered some of the most important geological processes. Fluid–rock interactions involving the generalised reactions with ferrous iron (Fe²⁺):H₂ stoichiometry of 3:1 (Eqn 1) and 2:1 (Eqn 2) (Holland 2002; Sleep and Bird 2007) follow:

Table 1.  Abiogenic sources of hydrogen

Serpentinisation is the most studied reaction pathway to H₂ in the subsurface (Table 1) and is discussed here in more detail. Serpentinisation occurs with the circulation of hydrothermal fluids through mafic–ultramafic rocks on the seafloor at deep-sea hydrothermal vents and in continental ophiolites. In the serpentinisation of fayalite (Fe-olivine end-member), Eqn 1 is followed liberating H⁺. In general, with increasing magnesium (Mg) content in olivine and Mg-silicates, the resulting fluids often become alkaline (Holland 2002). Thus, hydrous alteration of minerals such as olivine and pyroxene produces serpentine, brucite, magnetite and H₂ (Eqn 3; McCollom and Seewald 2013; Worman et al. 2016) while still maintaining Fe:H₂ in a 3:1 ratio.

Serpentinisation can occur at temperatures from just above ambient to 330–400°C, depending on pressure (Evans et al. 2013; Mayhew et al. 2013; McCollom and Seewald 2013). The mantle lithosphere could also support serpentinisation (Brovarone et al. 2017). Low temperature (<100°C) H₂ production is associated with a spinel reactant (e.g. M²⁺(M³⁺)₂O₄; magnetite Fe₃O₄ and chromite FeCr₂O₄) and a cubic crystal structure. The spinel can either be as impurities in the initial reactant or the serpentinisation product (Mayhew et al. 2013). Hydrogen yield from serpentinisation is directly linked with the fraction of reduced iron in the reactant mineral (e.g. olivine or pyroxene with variable Fe/Mg ratios) and the proportion converted to Fe³⁺ (McCollom and Seewald 2013; Murray et al. 2020). Given the stoichiometry between H₂ and magnetite production, the lower magnetite (and associated H₂) yield in the early stages of serpentinisation is likely offset by release of Fe²⁺ into the hydrothermal fluid where it is available for water hydrolysis (see below) (Cannat et al. 2010). The aqueous chemistry of Fe²⁺ is also likely to play an important role, for example, Fe(OH)₂ may disproportionate to Fe and magnesite with the subsequent hydrolysis of the Fe liberating H₂ (Blesa and Matijević 1989). A critical factor for serpentinisation is a highly reducing environment, i.e. below the low O₂ fugacity/high H₂ activity associated with the fayalite–magnetite–quartz buffer (Shock et al. 2019 and references therein). Such redox conditions are likely to be maintained in rock-dominated environments where oxidising meteoric water recharge is restricted (Abrajano et al. 1990) and silica activity is low (Katayama et al. 2010). The discharged aqueous fluids change from highly alkaline to moderately acidic with increasing temperature (McCollom and Seewald 2013; Schrenk et al. 2013; Murray et al. 2020) with the high temperature fluids having highly elevated H₂ and CH₄ concentrations (Schrenk et al. 2013). Serpentinisation of ultramafic rocks typically generate higher concentration of H₂ than basalt–water reactions (Hao et al. 2020). For example, Fe²⁺ is excluded from the ultramafic-altered minerals while basalt-altered minerals (e.g. chlorite and amphibole) readily accommodate Fe²⁺ (Murray et al. 2020). Serpentinisation is likely limited to the shallow crust i.e. the upper ~4–6 km corresponding to the 400°C isotherm (Andreani et al. 2007), although optimum temperature-depth for serpentinisation reaction is likely around 10 km (Donze et al. 2020).

In felsic rocks (e.g. granites), biotite can also hydrate to generate H₂ (Table 1). Here, the lower proportion of this Fe²⁺-rich mineral compared to the proportions of Fe²⁺-minerals in basic rock makes granites a less effective source of H₂ compared to mafic–ultramafic rocks on a volume per volume basis (however, see Case study 2). Nevertheless, high redox potentials, low temperatures and the addition of CO₂ can increase H₂ yield from granites (Murray et al. 2020).

Radiolysis of water (Table 1) in the geosphere is another significant mechanism of generating natural H₂ that is amenable to modelling and resource estimation (Sherwood Lollar et al. 2014; Warr et al. 2019; Boreham et al. 2021; also see H₂ inferred resource potential of onshore Australia) employing the reaction:

Interestingly, the H₂ yield from water radiolysis is suppressed in the presence of metal ions (Fe²⁺ and Fe³⁺) compared to pure water (Christensen and Bjergbakke 1982). However, even in basic rocks with lower radiogenic minerals contents, radiolytic splitting of water is considered providing more electron donors than Fe²⁺ in old (>10 Ma) basement basalt (Dzaugis et al. 2016). Depth limits to water access is likely to be around 10 km where rock fractures anneal and H₂O flow is significantly retarded (Oze and Sharma 2005; Sherwood Lollar et al. 2014).

Zgonnik (2020) considers volcanic and hydrothermal vents to be the most dominant H₂ source, having the highest estimated natural H₂ production rates. Further, a cataclastic source (Table 1) of natural H₂ is also unconstrained, with estimates of H₂ production rates ranging up to many orders of magnitude greater than from serpentinisation and water radiolysis combined (Ménez et al. 2019; Truche et al. 2020; Worman et al. 2020; Zgonnik 2020). Parnell and Blamey (2017) suggest that H₂ released from fluid inclusions is widespread in Precambrian basement rocks, particularly granites, and their eroded remnants deposited in sedimentary basins, and hence, a likely significant H₂ resource. Artificial H₂ production associated with drilling operations and metal corrosion (Table 1) typically give low concentrations of H₂ (Erzinger et al. 2006) but occasionally high concentrations (up to 90 mol%) can be produced (Mørkved et al. 2009; Thiessen et al. 2009; Guélard et al. 2017). A hydridic source from the lower mantle and core are theorised to be the ultimate largest ‘H’ reservoir (Zgonnik 2020, and references therein), where H₂ can either continually migrate upwards or be released with episodic injection into the upper mantle/crust where the metal hydrides can undergo metasomatism and water hydrolysis (Table 1).

Biogenic sources of natural hydrogen include both thermogenic and microbial origins. In the former, H₂ is a by-product of diagenesis and thermal maturation, while in the latter, H₂ producers and H₂ consumers generally work in consortia (Boone et al. 1989; Noar et al. 2015; Gregory et al. 2019) and provide an important H₂ sink (see H₂ sinks below).

During diagenesis, the polymerisation of hydrocarbon C–C bonds results in the formation of kerogen and minimal release of H₂. Thermogenic liberation of H₂ occurs during subsequent catagenic scission of hydrocarbon C–C bonds during the generation of gas and oil, coal seam gas (Gregory et al. 2019, and references therein) and petroleum cracking (Briere et al. 2017). During metagenesis, the progressive aromatisation of the residual kerogen also leads to production predominantly of CH₄ but also some H₂ (Tissot and Welte 1984; Hunt 1996). Thermolysis of alkanes and CH₄ at >200°C and >500°C, respectively (Tissot and Welte 1984) also result in the release of H₂.

Hydrogen sinks within the lithosphere–hydrosphere–atmosphere are such that H₂ excess over geological H₂ sinks is effectively utilised either by microbes or their enzymic by-products (Sleep and Zoback 2007; Ehhalt and Rohrer 2009; Worman et al. 2020). This leads to a balance between source and sink that helps maintain a relatively steady-state atmospheric H₂ concentration at trace levels of ~0.5 ppm (Ehhalt and Rohrer 2009; Batenburg et al. 2011). Soil uptake by carbon and abiontic enzymes (i.e. catalytic enzymes stabilised in the soil matrix but that are no longer associated with viable cells) is considered the major H₂ sink (Nannipieri et al. 2018). Deep earth H₂-utilising microbes (e.g. associated with the biodegradation of petroleum and production of microbial CH₄), H₂ dissolved in water and consumption by abiotic reactions (e.g. oxidation by OH) are volumetrically, at best, estimated to be around an order of magnitude lower than the H₂ soil sink (Ehhalt and Rohrer 2009, 2011; Truche et al. 2020; Worman et al. 2020; Zgonnik 2020). Due to the high reactivity of H₂, reservoired petroleum can act as a potential sink with hydrogenation improving hydrocarbon quality and volume, masking any H₂ input. Further, organic-rich rocks within the hydrocarbon generation zone are even considered an impenetrable sink via chemical reaction (Apps and van de Kamp 1993).

Primary abiogenic H₂ within the lower mantle is considered to be widely distributed but volumetrically unknown, while the upper mantle–crust has an estimated mostly secondary H₂ annual production rate of around 254 ± 91 Bm³ (8.97 ± 3.21 Tcf) year⁻¹ (Zgonnik 2020). Another recent estimate gave a much lower global H₂ resource of 31 Bm³ year⁻¹ (1.1 Tcf) from continental and oceanic crust sources, water radiolysis, volcanism and volcanic degassing (Truche et al. 2020). In the above two estimates, the H₂ production rate from cataclasis (rock fracturing; see Geological occurrences, sources and sinks of H₂) is grossly under-represented (Hirose et al. 2011, 2012; Parkes et al. 2019). Zgonnik (2020) combined data from the Western and Eastern (former Soviet bloc) literature to conclude that global H₂ occurrences have been under-estimated. Nevertheless, the most optimistic H₂ resource estimate is still lower than the industrial H₂ production and is around two orders of magnitude lower than the 4.1 Tm³ (145 Tcf) of natural gas production in 2019 (IEA 2019). Even the atmospheric load of 1.7 Tm³ (Truche et al. 2020) would not sustain increasing global H₂ demands, unlike the large atmospheric potential for He extraction (Boreham et al. 2018 and references therein). Although the above annual production rates of natural H₂ are underwhelming, it must be taken into account that abiogenic H₂ production is relatively continuous for millions to billions of years and over a wide temperature range (Zgonnik 2020 and references therein), unlike petroleum generation with shorter timespans within specific narrow temperature windows (Tissot and Welte 1984; Hunt 1996). Reserves of natural H₂ from petroleum fields are modest, estimated to be around 20 Bm³ using 197 Tm³ of global natural gas proven reserve (BP 2019) and an average H₂ content of around 0.01 mol%. The recent discovery of abiogenic H₂-rich over-pressurised gas (97.4 mol% H₂) from the shallow Bougou 1 well, in the Southern Taoudeni Megabasin, Mali, West Africa, has resulted in small-scale gas production for electricity generation (Briere et al. 2017; Prinzhofer et al. 2018). There is a strong appetite for continued niche H₂ exploitation and for natural H₂ to be directly blended – up to initially 10% hydrogen by volume – in gas distribution networks (Melaina et al. 2013; COAG Energy Council Hydrogen Working Group 2019). Hence, the prediction of subsurface H₂ that can be exploited remains enigmatic and awaits a wider range of viable analogues and robust exploration guidelines.

Historically, there are a few reports of H₂-rich (>10 mol% H₂) Australian natural gases (Fig. 2). For example, up to 89 mol% H₂ (air-free) gas was analysed in shallow bores on the Yorke Peninsula and Kangaroo Island, South Australia (Ward 1917, 1932, 1933, 1944; Woolnough 1934; see Case study 2). Dissolved gases in artesian groundwaters from the Mesozoic Great Artesian Basin in eastern Australia recorded around 16 mol% H₂ and variable CH₄ content (Woolnough 1934). With the advent of extensive petroleum exploration programs and with ad hoc inclusion of H₂ in the chemical analysis of natural gases, other instances of high hydrogen concentrations have been reported across the continent. While drilling in sedimentary rocks in the Canning Basin, Western Australia (WA) in 1958, Meda 1 recorded up to 95 mol% H₂ (https://wapims.dmp.wa.gov.au/WAPIMS/Search/Wells), and 38.2 mol% H₂ was measured in Golden Beach 1 drilled in 1967 in the Gippsland Basin, Victoria (http://geoscience-web.s3-website-ap-southeast-2.amazonaws.com/well/goldenbeach1.htm). In Tasmania, Lonnavale 1 encountered 85 mol% (air-free) H₂ (Burrett and Tanner 1997). A degree of caution concerning the validity of these historic geological sources needs to be applied to these archival H₂-rich gases given the prevalence of H₂ artefacts from drilling operations (Table 1), and where re-sampling and analysis using current technologies is recommended.

Fig. 2.  Location map showing exploration well, mine and groundwater samples with measurable concentrations of H₂ (mol%). Well names are displayed for gases with >1 mol% H₂ (air-free).

In a compilation of Australian natural gas data from petroleum exploration wells, Boreham et al. (2001) proposed that gases with elevated H₂ contents have mixed origins from a deep inorganic source and from organic matter (kerogen) decomposition at high maturities. In Australia, past petroleum exploration activities have been typically focused on sedimentary basins with little penetration into, for example, fractured basement rocks where abiogenic hydrocarbons and H₂ most likely originate and potentially accumulate (Etiope and Whiticar 2019, and references therein; Zgonnik 2020, and references therein). Nevertheless, high concentrations of H₂ (11 mol%; McInnes et al. 2017) were discovered in Precambrian basement at the Mt Kitty 1 exploration well, Amadeus Basin, Northern Territory in 2015. Further, mud gases (collected in Isotubes™) analysed after the 2013 drilling of Wyworrie 1 (McArthur Basin, Northern Territory) contained H₂ up to 11.7 mol% (air-free) in the shales of the Precambrian Velkerri Formation (https://geoscience.nt.gov.au/gemis/ntgsjspui/handle/1/79187).

Notwithstanding the above limited occurrences of H₂-rich gas, natural H₂ might yet be found in depositional settings not previously considered suitable for petroleum exploration (Coveney et al. 1987). For example, in recent ore mining operations, H₂-rich gases have been found at the Cobar copper underground mine, New South Wales (~75% H₂ and ~25% CH₄; Stack and Rabone 2018) and up to 61.7 mol% (air-free) at the Boomer deposit, Frog’s Leg Gold Camp, Eastern Goldfields Superterrane, WA (Boreham et al. 2021; see Case study 3).

Geoscience Australia’s Isotope and Organic Geochemistry Laboratory routinely analyses onshore and offshore Australian natural gases. Of these, ~1000 natural gases from 470 wells with reservoir rocks ranging in age from Neoarchean to Cenozoic have H₂ contents above the detection limit of 0.0002 mol% and up to 91.9 mol% (air-free) (for experimental procedure see Boreham et al. 2021). The well locations of these gases are shown in Fig. 2, while the frequency distribution of H₂ mol% together with the data for Western Australian gold deposit gases and H₂-rich natural gases from Ward (1917, 1933) are shown in Fig. 3a. The H₂ mol% (air-free) frequency mode for the Australian natural gases is between 0.001 and 0.01 mol%, indicating that H₂ mol% is very low in natural gas. Having said this, there are enough examples of H₂ >0.1 mol% to warrant further investigation and to recommend that future analysis of H₂ in natural gases becomes a routine exploration industry-wide practice.

Fig. 3.  Hydrogen concentration (mol%) of Australian biogenic natural gases and WA gold deposit gases analysed at Geoscience Australia, and historic data (H₂ >10 mol%) displayed as (a) frequency plot and (b) versus methane/(ethane + propane).

The plot of H₂ mol% (air-free) versus C₁/(C₂ + C₃) ratio in Australian natural gases shows a general decrease in the ratio with increasing H₂ mol% (air-free) (Fig. 3b). The WA gold deposit gases are generally drier (higher C₁/(C₂ + C₃) ratio) than Australian natural gases with similarly high H₂ mol% (air-free). These WA gold deposit gases have C₁/(C₂ + C₃) ratios of 23–67, typical of abiogenic gas (Etiope and Ionescu 2015 and references therein).

The hydrogen isotopes (δ²H in ‰) of selected Australian natural gases with H₂ contents between 0.58 and 6.91 mol% (for experimental procedures see Boreham et al. 2021) is given in Table 2 and their range displayed in Fig. 1, together with the hydrogen isotopic range of H₂ sources from a variety of geological and biological sources and artefacts (i.e. iron corrosion). The δ²H_H2 values for Australian natural gases cover a very wide H-isotopic range from –995.9 to –388.8‰ (Table 2), with the former value being the most ²H-depleted H₂ so far presented in the literature. There is no overall correlation between H₂ mol% and δ²H_H2, although the isotopic range is narrower for H₂ content >2 mol% with δ²H_H2 average = 793 ± 62‰. These values are consistent with migrated H₂ derived from serpentinised sources. The two gases with δ²H_H2 –388.8‰ (Pinelands 3, Surat Basin) and –369.6‰ (Katandra 1, Bonaparte Basin) (Table 2) are likely sourced from volcanics and/or water radiolysis. However, given that natural gas with extreme depletion in ²H is unusual compared to known sources (Fig. 1), these values may point to an artefact accompanying gas production and/or collection and/or storage in stainless steel cylinders and Isotubes™; this needs further experimentation. Using the accompanying hydrogen isotopes of CH₄ (δ²H_C1) and assuming isotopic equilibrium between CH₄ and hydrogen, the calculated (with extrapolated) equilibrium temperatures are listed in Table 2. Such extremely low and high calculated temperatures show that there is neither an association nor isotopic equilibrium between the generation of CH₄ and hydrogen, and the sources of H₂ remain highly speculative in the present limited sample set. Given that the sample collection medium and the timing of analysis are considered important (Goebel et al. 1984) (e.g. hydrogen isotopic analysis of H₂ at Geoscience Australia was years after sample collection with storage mainly in stainless steel cylinders), protocols for the measurement of accurate H₂ content and hydrogen isotopes of H₂ in natural gas need to be expedited.

Table 2.  Hydrogen isotopes of H₂ for Australian natural gases
Tcalc = calculated temperature for H₂–CH₄ hydrogen isotopic equilibrium (Horibe and Craig 1995)

Hydrogen has had a ubiquitous presence since the earth was formed with potentially extreme concentration in the very early atmosphere (up to 30 mol% H₂; Wordsworth and Pierrehumbert 2013) to a relatively pseudo steady-state present-day concentration (av. 5.31 × 10⁻⁵ mol%; Novelli et al. 1999) where atmospheric input, from mainly surficial and aerial chemical processes (Adushkin et al. 2006) is balanced by atmospheric loss into the upper atmosphere and into space (Zgonnik 2020 and references therein). Abiogenic H₂ is a source of energy for chemotrophic ecosystems and may have contributed to the development of early life on earth (Ménez 2020 and references therein) and other planets in our solar system (Glein and Zolotov 2020 and references therein). Soil is the major sink for H₂ so this can mask geologically supplied inputs. Where point source outweighs sink, then H₂ seepage occurs which can be a positive indicator of subsurface H₂ systems. The large isotopic enrichment in ²H in tropospheric H₂ (Fig. 1) compared to other terrestrial occurrences is predominantly associated with ²H/¹H isotopic fractions of atmospheric OH-induced destruction of H₂ and generation of H₂ from CH₄ photolysis (Ehhalt and Rohrer 2009; Batenburg et al. 2011).

Petroleum system concepts of source–migration–reservoir (alteration)–seal developed for conventional natural gas are valid for abiogenic gas but appropriate exploration guidelines will need significant updating (see Towards an H₂ exploration guideline) if the commercial success of abiogenic H₂ is to be realised. For example, for an organic-rich source rock, the timing of thermogenic petroleum generation (gas and oil) is governed by the time-temperature history and the organic matter (kerogen) type (Tissot and Welte 1984). Sulfur-rich kerogen generates petroleum at a lower temperature than does sulfur-poor kerogen (Tegelaar and Noble 1994). This could be considered analogous to Fischer–Tropsch type gas-phase reaction of H₂ with CO₂ (Sabatier reaction) producing hydrocarbons where rhodium- and ruthenium-rich minerals catalyse the reaction at lower temperatures than iron-, chromium- and nickel-containing minerals (Etiope and Whiticar 2019 and references therein). Additionally, serpentinisation can lead to increased porosity, transforming a tight mantle rock into a potential reservoir (Smith et al. 2005).

Migrating hydrogen and gaseous hydrocarbons do not necessarily co-concentrate (become trapped) below the same migration barriers. For example, H₂ is trapped by aquifers (Dugamin et al. 2019) and igneous rocks are effective seals for H₂, where this is not the case for natural gas. In contrast, thick carbonates retain hydrocarbon gases better than H₂ (Prinzhofer et al. 2018). Clay minerals can be an effective adsorbent of H₂ (Truche et al. 2018). Hydrogen can be trapped either within or below evaporite seals (Smith et al. 2005). Salt can also act as a buffer withstanding reservoir breaching during prolonged periods of tectonic activity (Johns et al. 2017). Even more effective H₂ trapping can occur in alternating layers of salt and clay (Zgonnik 2020). Evaporites are distributed across many Australian sedimentary basins and intersected in numerous wells, as shown in Fig. 4 (Wells 1980; Australian Occidental 1982; Mory 1988, 1991; Felton et al. 1993; Plescia et al. 1994; Simeonova and Apak 2003; Simeonova and Iasky 2004; Kovalevych et al. 2006; Gill and Cowan 2008; Korsch and Kositcin 2010; Carr et al. 2012; Bruce 2015; Gill 2017; Mory 2017; Haines and Allen 2020). Halite-bearing formations were formed during the Neoproterozoic in the Amadeus, Officer, Polda, Arkaringa and Stansbury basins, and in the Paleozoic in the Adavale, Amadeus, Canning, Carnarvon and Bonaparte basins (Fig. 4).

Fig. 4.  Australian basins with major halite discoveries (thickness >100 m) of Precambrian age (brick red colour) and Paleozoic age (green colour). Both Precambrian and Paleozoic halite deposits (yellow) occur in the Amadeus Basin. Basins that have either minor or limited known occurrences of evaporites are shown in grey. Wells penetrating halite/evaporite beds are indicated by black dots. Note: only the onshore extent of the Canning Basin is displayed.

There are many examples of a close association of H₂ anomalies with faults, most likely accessing crystalline basement (Larin et al. 2015, and references therein; see Case studies 2 and 3), where the latter is considered a significant geological source for H₂ and He (Flude et al. 2019). Potential locations of H₂ sources can be associated with mineral deposits, remotely identified using geophysical techniques (gravity and magnetic anomalies) (Dugamin et al. 2019; see Case study 1). Additionally, the surface expression of subsurface H₂ source rocks is commonly characterised by rounded to oval depressions observed from satellite imagery (Zgonnik 2020 and references therein; Moretti et al. 2021a). These characteristic surface expressions have been identified at Pingrup, WA (Larin et al. 2015) and more widely across southern WA and southern South Australia (Rezaee 2020; Moretti et al. 2021a) and may be indicators for deeper H₂ sources. A major advantage for H₂ derived from an abiogenic source compared to petroleum generated from an organic carbon-based (biogenic) source is that the former can be generated continuously over a longer timeframe and a wider temperature range.

Three case studies are presented below designed to highlight important attributes of surface to subsurface geochemical, geological and geophysical methodologies that should be utilised together, or in part, to understand potential H₂ systems with increasing levels of confidence. Case study 1 is in the South Nicholson Basin, a vast frontier area that crosses the Northern Territory–Queensland border and for which gas compositional data are not available but has active exploration and stratigraphic drilling programs. Here, H₂ potential is inferred from rocks of similar age in the adjacent Beetaloo Sub-basin of the McArthur Basin where high-H₂ gases were found in natural gas from Wyworrie 1 (Fig. 2). Case study 2 is in southern South Australia where a H₂ ‘hot spot’ was identified in the early 20th century within sedimentary rocks of the Stansbury Basin overlying Archean basement rocks of the Gawler Craton, but not examined thereafter. Case study 3 is in the Western Australian Archean Yilgarn Craton, Eastern Goldfields Superterrane and close to the township of Kalgoorlie, where recent chemical and isotopic analyses of H₂-rich and CH₄-rich natural gases have allowed the delineation of their abiogenic sources (Boreham et al. 2021).

This case study focuses in the South Nicholson Basin where Geoscience Australia has acquired new deep-crustal reflection seismic data (Carr et al. 2020; Fomin et al. 2020) to assess the hydrocarbon and mineral resources potential between two prospective Paleoproterozoic provinces: the Mt Isa Province to the southeast and the McArthur Basin to the northwest. The new seismic data linked the stratigraphy with correlation of prospective stratigraphic units across the region, including the Isa and Roper superbasins and South Nicholson Group (Fig. 5). The recently completed drilling at Carrara 1 (MinEx CRC 2020) aims to stratigraphically correlate key rock units to the seismic packages and compositional analyses will be performed on the recovered gas and gas released from fluid inclusions. The Isa Superbasin is largely concealed beneath the region and includes rocks that are prospective hosting the world class Mount Isa Cu-Pb-Zn deposit and a number of other regional base metal deposits (Fig. 5a). Recent exploration for unconventional hydrocarbons in the northern Lawn Hill Platform (NW Mt Isa Province) identified gas in the organic-rich shale units of the Lawn and River supersequences (Bradshaw et al. 2018), demonstrating significant unconventional potential in the underexplored Isa Superbasin. These Mt Isa Province and McArthur Basin prospective regions are underlain by the edge of thick lithosphere. The global Lithosphere–Asthenosphere Boundary reveals a striking relationship between major sediment-hosted mineral deposits and the edge of the thicker lithosphere, as outlined by the 170 km depth contour (Czarnota et al. 2020; Hoggard et al. 2020). Major pre- to syn-Paleozoic faults and shear zones of the North Australian Craton wrap around blocks of thick lithosphere, indicating that they have influenced strain partitioning and ore forming processes through multiple tectonic cycles (Czarnota et al. 2020).

Fig. 5.  Case study 1 in the South Nicholson Basin showing (a) gravity anomalies imaged within the crust (Lane et al. 2020) showing relationships between the edge of the thick lithosphere and the location of seismic lines, major interpreted faults, waterbodies extracted from Digital Earth Australia and major known mineral deposits across the South Nicholson Basin study area, and (b) correlation between the upper 4 km of the seismic line 19GA-B1 and the location of the borehole NTGS02/1 Lake Sylvester with updated stratigraphy from Carson et al. (2020). F1–F8 indicate fault locations interpreted from seismic, gravity and magnetic data. The red rectangular box in (a) is a plan view showing the co-location of the seismic and AEM lines and where the former is shown in a vertical display in (b).

The integration of gravity (Fig. 5a) and magnetic anomaly lineaments with deep seismic reflection data allows the mapping of pre-existing major crustal structures that have controlled the basement architecture and subsequent basin’s evolution (Rollet et al. 2020). These major crustal structures provide potential conduits for large-scale, paleo-fluid migration, some being inferred to be prospective for sediment-hosted base metal deposits most likely sourced from mafic igneous rocks hosted within the early sedimentary basin fill (Fig. 5b: Paleoproterozoic Leichhardt and Calvert superbasins). Magnetotelluric data collected across the region reveal anomalous conductivity structures that extend from deep within the lower crust to the uppermost crust (Duan et al. 2020; Jiang et al. 2020). These conductive structures are interpreted to represent fluid conduits that altered/hydrated the crust. They are prospective for iron oxide–copper–gold (IOCG) deposits and have been the focus of many recent investigations (Czarnota et al. 2020; Murr et al. 2020; Schofield et al. 2020). Such zones, considered to be the most favourable areas for potential mineralisation and H₂ sources, correlate with magnetite and hematite alteration proxies using 3D gravity and magnetic inversion (Goodwin and Skirrow 2019), as well as major crustal structures and edges of basement highs (Rollet et al. 2020) (Fig. 6a).

Fig. 6.  Case study 1 in the South Nicholson Basin showing (a) basement depth (m) interpreted from seismic reflection data (Rollet et al. 2020) overlain with modelled alteration (hematite-rich and magnetite-rich) contact zones considered to be the most favourable areas for potential IOCG mineralisation (Goodwin and Skirrow 2019), (b) image over the Sylvester salt lake showing relationships with the deep structures imaged on the seismic (displayed in Fig. 5b) with borehole NTGS02-1 location and (c) the shallow conductivity imaged from the AusAEM1 line 1200003-1. F1–F8 indicate fault locations interpreted from seismic, gravity and magnetic data. The red rectangular box in (a) is a plan view showing the co-location of the seismic and AEM lines that are shown in 3D in (b) in vertical section with faults and well location in (c) to indicate the relationships between the various datasets.

Further investigation in this area could help better understand the potential relationships between structural and mineralogical elements that are observed elsewhere in intra-cratonic basins and are associated with natural H₂ migration from deep-seated sources. Donze et al. (2020) have demonstrated the relationship between H₂ occurrences and other geological elements, such as (i) a relatively high geothermal gradient, (ii) deep faults delineating horst and graben structures, which affect the entire sedimentary sequence and (iii) Archean to Paleoproterozoic basements enriched in radiogenic elements and displaying mafic and ultramafic units. Furthermore, salt lakes exist (Fig. 6b) between these conducive areas for mineralisation and hydrocarbon generation, that have up to 20 times more enrichment in potassium (K) compared with sea water (Mernagh et al. 2016). This K enrichment enhances H₂ generation potential from the hydrolysis of water by Ca from the ⁴⁰K radioactive decay (see Geological occurrences, sources and sinks of H₂) in areas where ancient salt lakes are deeply buried and there is a possible karst reservoir-seal (i.e. Middle Cambrian limestone within the Georgina Basin overlying the Paleoproterozoic provinces) located 400 m below the surface (Fig. 6c).

This case study focuses on the central Yorke Peninsula in South Australia (Fig. 2) where multiple hydrogen gas discharges were observed during drilling of the Minlaton Oil Bore (Ward 1944). The Minlaton Oil Bore (Fig. 7a) was drilled in 1931 (recorded as the Ramsay Oil Bore 1 in the SARIG database; https://map.sarig.sa.gov.au/) and is located ~10 km east of the Minlaton township within map section 112 Ramsay (Fig. 7b). The first gas show was recorded in the sludge below 370 ft (112.78 m). Three gas samples were collected from the bailer at the surface from the following depths: 790 ft (240.79 m), 860 ft (262.13 m) and 1666 ft (507.8 m). They revealed significant H₂ content of 76, 64.4 and 84 mol%, respectively, with nil to minor CH₄ (7.5, 7 and 0 mol%, respectively) and nil to minor air contamination (based on 0, 2.4 and 1.2 mol% oxygen, respectively) with the balance being nitrogen and ≤0.8 mol% CO₂. There are no wireline logs available for the Minlaton Oil Bore. Visitors to the site on 21 September 1931 described one of the hydrogen gas influxes:

After the slush pump was raised to the surface it would then begin to bubble getting stronger and stronger until it resembled a boiling pot with fine spray jumping clear out of the water 5 to 6 inches above the surface of the water. It also raised the water in slush pump 4 to 5 inches and cause it to overflow the gas thus displacing 4 to 5 inches of space. It also had a rainbow colouring vily^# scum on water and would ignite the bubbles with a match and in one instance the flame shot all over the full surface of the slush pump it was so strong. At times an odour like carbide could be positively detected.

^#Likely a typo for oily.

Fig. 7.  Case study 2 in the Gawler Craton-Stansbury Basin showing (a) well correlation between Minlaton Stratigraphic 1, Minlaton Oil Bore and Minlaton Stratigraphic 2 and (b) interpreted basement geology in the vicinity of the Minlaton Oil Bore (modified from Raymond 2002).

The Minlaton Oil Bore penetrated a Cambrian succession of the Stansbury Basin to a total depth of 1800 ft (548.64 m). The section is dominated by limestone and mudstone units with some red bed clastics. The nearest offset wells are Minlaton Stratigraphic 1 drilled in 1956 and Minlaton Stratigraphic 2 drilled in 1968 (Fig. 7b). Neither of these stratigraphic wells encountered gas shows and none reached crystalline basement. At Minlaton Oil Bore, the Cambrian succession is interpreted to unconformably overlie predominantly moderately to strongly magnetic granitoids of the Hiltaba Suite and some Walaroo Group metasediments. This interpretation is confirmed by the historical note (in a document held with the Ramsay Oil Bore 1 in the SARIG database) on two possible core samples from Minlaton Northwest 1. The first sample allegedly recovered from 1700 ft (518.1 m) consists of fine-grained red granite and the second allegedly recovered from 1900 ft (579.12 m) being of fine-grained amphibolite. This description suggests these two samples belong to the Tickera Granite of the Hiltaba Suite. The Tickera Granite is described as an intensely foliated orange granite, a white leucogranite, and a red granite at outcrop in the Point Riley area. Mineral grains within the intensely foliated orange granite comprise K-feldspar (70%), quartz (15%), biotite and amphibole (10%) and plagioclase (<5%) while hematite alterations are evident through the red/orange colour and hematite-filled veins that cut all minerals (Brotodewo 2016).

The Minlaton Oil Bore encountered moderately saline (NaCl-rich with 9.44 g/L total salts) groundwater at 160 ft (48.77 m). Water radiolysis associated with a high radioactive element content of the granite basement is the most likely source for the H₂. However, a contributing H₂ source possibly results from the interaction of the heavy brines with the biotite granite within the fractured basement rocks of the Tickera Granite. The available seismic data suggest that the basement faults in the vicinity of Minlaton Oil Bore extend into the Cambrian sediments (Fig. 8a). These faults could provide migration pathways for downward movement of heavy brines from the saline swamps as confirmed by the fact that the saline aquifer was penetrated by the the Minlaton Oil Bore. There are many saline pink lakes in the area, some of them, like Ramsay Park, are in the direct proximity of the Minlaton Oil Bore (Fig. 8b). The pink colouration can be associated with microbial hydrogenotrophic methanogenesis (Formolo 2010). Similar saline pink lakes are found in the surrounds of Pingrup, WA (https://www.albanygateway.com.au/towns/pingrup/), which are associated with clusters of circular depressions identified using satellite imagery (Larin et al. 2015; Rezaee 2020) and/or bleached vegetation termed fairy circles (Myagkiy et al. 2020; Moretti et al. 2021a, 2021b). Within the Yorke Peninsula including around the Minlaton Oil Bore, Moretti et al. (2021a) mapped 365 structures as fairy circles, likely indicating the pervasive nature of surface H₂ seepage. A study of the Soultz-sous-Forêts geothermal site in France demonstrates that heavy brines circulating through biotite granite may lead to the generation of abiogenic H₂ (Murray et al. 2020). Their simulations show that generation of natural H₂ is possible in an open system by hydrothermal alteration of biotite as a source of Fe²⁺, which oxidises to Fe³⁺ leading to the precipitation of Fe³⁺ minerals and reduction of H⁺. Hence, this region in South Australia warrants further evaluation for its H₂ resource potential.

Fig. 8.  Case study 2 in the Gawler Craton-Stansbury Basin showing (a) seismic data in the vicinity of Minlaton Oil Bore and a possible mechanism of H₂ generation within the biotite-rich Tickera Granite, and (b) satellite image of the area in the vicinity of Minlaton Oil Bore showing the extend of the Cambrian limestone outcrop and the pink lake in the proximity.

The Eastern Goldfields Superterrane is Australia’s premier gold mining region (Cassidy et al. 2006; Huston et al. 2012). Past gas discharges of CH₄ and CO₂ were recorded in the early 20th century (Simpson 1912), with CO₂ flowing for many years, highlighting the potential for gas production at shallow depths. For example, the world’s only H₂-producing field, represented by the Bougou 1 pioneer well (in Mali, western Africa), flowed H₂ from 112 m (Prinzhofer et al. 2018). Hydrogen is also commonly found in ore deposits globally, including gold deposits (Zgonnik 2020). However, it was not until recently that H₂-rich (generally with subordinate CH₄) natural gas was found in Australian exploration drilling (to a maximum depth of 255 m) associated with the Frog’s Leg Gold Camp, about 20 km west of Kalgoorlie. Based on molecular and isotopic compositions of the gas components, H₂ has an abiogenic source from a combination of serpentinisation of mafic–ultramafic rocks at minimum depths between 1.4 and 2.7 km (42.2–57°C) and from water radiolysis mediated by the radioactive decay of U-, Th- and K-bearing minerals in mainly basic rocks (Fig. 9; Boreham et al. 2021). The relative shallow depth and low temperature (where H₂ is at its lowest solubility in aqueous solution; Lopez-Lazaro et al. 2019) of H₂ generation suggests that free gas as microbubbles is likely available for advective migration (Boreham et al. 2021). In the region, gas generation has likely been continuous from ~2.7 billion years ago to present. Therefore, the potential for a larger volume of a deeper H₂ resource exists, buoyed further by the presence of surface seepage of CH₄ over gold deposits elsewhere in the Eastern Goldfields (Polito et al. 2002). Significant volumes of H₂ may also be related to an extensive surface expression of potential H₂ seepage across the Yilgarn region (Larin et al. 2015; Rezaee 2020; Moretti et al. 2021a).

Fig. 9.  Case study 3 from the Eastern Goldfields, Western Australia showing a conceptual model for gas generation and migration at the Frog’s Leg gold camp and surrounds; (a) cross-section of the seismic line 99AGS-Y3 line representation in Drummond et al. (2004), 18 km SE of the Frog’s Leg mine, and with mafic-ultramafic rocks dominating the top 6 km and granites below 6 km, and (b) cross-section representing the local stratigraphy surrounding the Frog’s Leg Gold Camp. Modified from Boreham et al. (2021).

Herein, splitting of water due to interaction with radiation (radiolysis) and serpentinisation (hydration) are considered to be the only reactions leading to the production of H₂ through time for onshore Australia. The relative contribution of these two H₂ production pathways has been previously evaluated globally using the concentrations and decay rate of U, Th and K radioactive elements (Lin et al. 2005a, 2005b) with a small proportion (around 1%; Hofmann 1992; Boreham et al. 2021) of the released energy available for splitting of water to produce H₂ plus H₂ produced by serpentinisation (Sherwood Lollar et al. 2014). Calculations of hydration H₂ production rates are either indirect, using the difference between measured and calculated H₂/radiogenic noble gas (⁴He and ⁴⁰Ar) ratios (Warr et al. 2019; Boreham et al. 2021) or direct, from the FeO content (i.e. 10 weight%) of the source rocks with 100% hydration or progressively decreasing percentage hydration with depth (Sherwood Lollar et al. 2014).

In the radiolysis H₂ model, Sherwood Lollar et al. (2014) applied the average radioelement content of the upper and middle crust together and the depth-related porosity change to calculate the ratio of H₂ (from ppm U, ppm Th, % K and porosity) and ⁴He (from ppm U and ppm Th) with H₂/He of 117 and 15 for average upper and middle continental crust, respectively; the latter was excluded from their further calculations. They derived a crust fracture porosity related radiolytic H₂ production rate of 1.6 × 10¹⁰ moles H₂ year⁻¹ (358 MMm³ H₂ year⁻¹ at STP) for global Precambrian continental rocks. In their direct ferrous iron hydration component, Sherwood Lollar et al. (2014) have bundled Australia within the global surface area of the Precambrian continental lithosphere of 1.06 × 10⁸ km² (86% Proterozoic and 14% Archean) where mafic and ultramafic rocks account for 36% (⅓ Proterozoic and ⅔ Archean) of the total surface area. Using an average FeO content of 10% for the mafic and ultramafic rocks, this resulted in a maximum annual hydration H₂ production rate of 2.25 and 3.83 (using maximum values in Extended Data Tables 1 and 2 in Sherwood Lollar et al. 2014) times higher than H₂ from water radiolysis at 1 and 5 km, respectively. From the data of Sherwood Lollar et al. (2014), the H₂ inferred resource potential for the Australian craton is presented here by applying the following input parameters: Precambrian Australia has a surface area of ~5 060 000 km² (~82% of onshore Australia) (Raymond et al. 2018) of which ~20% is Archean, and up to 15% is mafic and/or ultramafic with average 10 weight% FeO. This surface area corresponds to ~5% of global surface area provided by Sherwood Lollar et al. (2014) giving an onshore Australian Precambrian H₂ (radiolysis + hydration) H₂ production rate of between ~58 and ~254 MMm³ H₂ year⁻¹ to depths of 1 and 5 km, respectively. These numbers would be a maximum as the percentage of mafic and ultramafic rocks is considered to be lower in Australia than the 36% used by Sherwood Lollar et al. (2014).

In our alternative method, H₂ yield was determined by calculating zonal statistics for radiometric U, K and Th radiometric concentrations and rock density data with the 1:1 000 000 scale surface geology map of Australia (Wilford and Kroll 2019; Supplementary Table S1). Our radiolytic H₂ generation model adopts the approach of Lin et al. (2005b) as applied in Tarnas et al. (2018, 2020). Individual data are assigned to each 100 m × 100 m grid cell extending across onshore Australia. The porosity at the surface is assigned a constant 1600 kg m⁻³ with an exponential decrease in porosity with depth (Sherwood Lollar et al. 2014; Tarnas et al. 2018, 2020). A porosity of 1.45 volume% is used here representing the porosity at 0.5 km. The calculated radiolysis H₂ production rate (molecules H₂ kg⁻¹ year⁻¹; Table S1) is shown in Fig. 10. The summed total radiolysis H₂ production rate is 499.2 Mm³ year⁻¹, assuming a constant rock type over a depth range from surface to a depth of 1 km. The top four areas in order of decreasing radiolysis H₂ production rates are the Mount Isa region under the Georgina Basin, the Georgetown region under the Carpentaria Basin, the King Leopold and Halls Creek Orogens and the Pine Creek Orogen.

Fig. 10.  Radiolytic H₂ production rate (molecules H₂ kg⁻¹year⁻¹) over onshore Australia. Table S1 presents the data and calculations employed (radiometrics were used to measure concentration of potassium, thorium and uranium at the surface to a depth of 50 cm). Areas of interest are (A) King Leopold and Halls Creek orogens have anomalous hydrogen production rates and warrant further investigation to determine potential trap sites, (B) Pine Creek Orogen has anomalous hydrogen production rates that warrant further investigation to determine potential trap sites, (C) the area west of the Georgetown Inlier under the Carpentaria Basin would be a potential hydrogen play and (D) the area south of the Mt Isa Inlier under the Georgina Basin would be a potential hydrogen play.

Our calculated radiolytic H₂ production value for onshore Australia is considerably lower than the estimated maximum radiolytic H₂ production rate of ~25.6 MMm³ year⁻¹ for Australian Precambrian continental crust where radiolytic H₂ contribution is 44% (using minimum values in Table 2 in Sherwood Lollar et al. 2014) to the total H₂ production rate (i.e. total = ~58 MMm³ year⁻¹ derived above) (Sherwood Lollar et al. 2014). The wide difference (here ~51 fold) in calculated radiolysis H₂ production rate using different methods was noted previously. Sherwood Lollar et al. (2014) found their estimate of global H₂ production rate was 52 times higher than that of Lin et al. (2005b). The main reason given by Sherwood Lollar et al. (2014) was the absence of appropriate scaling methods for extrapolation from well-understood local scales to relatively unconstrained continental/global scales. Such limitations still exist today.

The ratio of summed total molecules radiolytic H₂ kg⁻¹ year⁻¹/summed total atoms ⁴He kg⁻¹ year⁻¹ is 77 ± 13 (Table S1). Therefore, the calculate radiolytic H₂ production rate (0.5 MMm³ year⁻¹) is considered a minimum while it is only ~50% higher again using the crustal average H₂/⁴He of 117 (Sherwood Lollar et al. 2014). An integral component of the calculation of the H₂ production rate is the number of H₂ molecules generated per 100 eV absorbed (G-H₂, Tarnas et al. 2018, 2020). All calculations are based on G-H₂ of pure water but saline water and absorbed H₂O layers on minerals would have significantly higher G-H₂ (Hofmann 1992; Wang et al. 2019). We have not assigned FeO contents to the same level of completeness as with the radioelements for onshore Australia. Thus, a hydration H₂ production rate was not calculated by the direct approach. Instead, we assume the hydration H₂ production rate is a maximum 225% of the radiolysis H₂ production rate to a depth of 1 km (Sherwood Lollar et al. 2014), resulting in an H₂ inferred total production rate of ~1.6 MMm³ year⁻¹. Hence, the range in the calculated minimum H₂ production rate for onshore Australia compares unfavourably elsewhere with measured, localised surface H₂ seepage rates up to ~7 Mm³ day⁻¹ (~2.5 MMm³ year⁻¹) over a small 0.4 km² structure (Moretti and Webber 2021) where serpentinisation and other (not including water radiolysis) H₂ sources most likely predominate. The preceding highly variable estimates of H₂ production rates highlight major limitations that current models have in numerical estimations of H₂ production rates at the regional to global scales.

Here, the H₂ assessment could be improved by using measured radioelement contents, by machine learning geochemical grid (e.g. Wilford et al. 2020) and levelled geochemistry (Main and Champion 2020). This would better reflect surface geochemistry for U, Th, K and Fe (potentially Fe²⁺ to Fe³⁺ ratio). Further, an estimated Australia-wide coverage of the relative proportions of ferrous (magnetite) and ferric (hematite) iron contents could be made by integrating regional gravity and magnetic datasets (e.g. Fig. 6a). In this way, the extent of the hydration reaction using the calculated weight% of magnetite based on total iron weight% can be assigned as an alternative to the FeO weight% direct method. The above total H₂ inferred production rates do not account for H₂ potentially generated within fluid inclusions (Sherwood Lollar et al. 2014) or other mechanisms (Table 1).

The extreme mobility of H₂ facilitates its migration from depth to possible shallower reservoirs by both diffusive and advective mechanisms, primarily driven by buoyancy and concentration gradients (Etiope 2015) but still requires the H₂ generation rate to exceed the H₂ rate of uptake in sinks, for example, layered silicates, salt formations and organic-rich deposits. Surface H₂ seepage observed directly (measurable) or indirectly (e.g. circular-oval depressions and fairy circles; Prinzhofer et al. 2019, and references therein; Myagkiy et al. 2020; Rezaee 2020; Moretti et al. 2021a, 2021b) is an expression of either an absence of an effective seal or a leaking seal. A key to H₂ in elevated surface concentrations appears to be the presence of an aquifer near a fault zone (Dugamin et al. 2019). However, the most important parameter to be gleaned from H₂ seepage is its magnitude, which is a good guide to the size of the underlying H₂ resource and to its sustainability (Cathles and Prinzhofer 2020). However, spot surface sampling is discouraged. Instead a program of continuous monitoring for at least 24 h at multiple, closely spaced monitoring sites is highly recommended (Moretti et al. 2021b). Sustainable, renewed hydrogen accumulations are likely emphasised with the presence of carbon monoxide (Prinzhofer et al. 2018). The large variety of H₂ sources with their accompanying rocks types and fluids (see Geological occurrences, sources and sinks of H₂; Table 1) will ensure that future explorationists for natural H₂ will need to rely on a more extensive guidebook.

Natural H₂-rich gas occurs predominately outside petroleum-focused exploration in sedimentary basins. However, recent exploration drilling specifically for natural H₂ has focused on areas with known occurrences of H₂-rich natural gas that were discovered decades before as a consequence of conventional drilling for oil and gas (Prinzhofer 2018; Zgonnik 2020). A recent comprehensive review outlining where H₂-rich natural gases are found provides obvious (ibid) pointers where to look for future potential natural H₂ resources – these areas include:

1. onshore igneous rocks provide a wide range of environments with H₂-rich gas occurring as free gas, dissolved gas and trapped in fluid inclusions within ophiolites, rift zones, faults and atmospheric degassing in volcanic gases, geysers, hot springs and surface gas seeps;

2. kimberlite pipes are rarely associated with H₂-rich gas but where found host high flow rates (0.1 MMm³ day⁻¹) of natural H₂;

3. ore bodies are a major site of H₂-rich gas in both igneous and sedimentary rocks;

4. coal seams (absorbed) and/or carbonates (adsorbed) offer high H₂ storage capacity;

5. within gas–water fluid inclusions where the older the rock the higher the H₂ abundance, because time is a primary control on the extent of water radiolysis involving ^{235, 238}U,²³²Th and ⁴⁰K radioactive decay;

6. evaporitic sulfates can store high abundance of H₂ (up to 20–30% by volume) while halite with high K content (e.g. K-potash deposits) also provides a radiogenic-hydrolytic source of H₂ through a calcium (Ca) metal intermediate together with salt being a good seal rock; and

7. oil and gas fields typically do not contain high H₂, nevertheless for those with elevated H₂ contents H₂ production may be viable via association with liquefied natural gas (LNG; see below).

The reactive nature of H₂ affects the structure and chemical composition of the rock it transverses, for example, the mechanical strength of carbonates decreases (Levshounova 1991), potentially accelerating the development of fractures under stress regimes with the creation of additional migration pathways. Downhole H₂ contents commonly increase with depth (Parnell and Blamey 2017). Zgonnik (2020) suggests that H₂ is too diffusive and too reactive to accumulate in significant concentration in geological traps. However, the goal to the development of a robust exploration guideline is to provide a range of potential targets each with their specific characteristics for H₂ generation, migration and retention (Fig. 11).

Fig. 11.  Systematic of source-migration-accumulation for H₂ exploration in conventional and non-conventional settings. The H₂ contents in petroleum fields (1 and 2) are likely supplemented by H₂ from abiogenic sources (3). H₂a = advective migration and H₂d = diffusive migration of H₂.

Truche and Bazarkina (2019) and Donze et al. (2020) have outlined a preliminary H₂ exploration guide, based heavily on ore-targeting approaches and globally high H₂ occurrences, condensed into three key factors associated with onshore occurrences with elevated H₂ contents; all of which (together with the preceding dot points above) are directly applicable to H₂ exploration in Australia, as outlined below:

1. the presence of Fe-rich rocks, particularly Archean basement rocks as potential sources for both radiolytic and hydrolytic H₂ generation (e.g. Case studies 1–3);

2. deep-rooted basement faults that can provide the migration pathways and the focus for diffuse H₂ sources (e.g. Case studies 1–3; Fig. 11); and

3. reservoir potential at depth at the interface between basement and sedimentary rocks (Fig. 11). For example, natural gas from the Mt Kitty 1 well (Amadeus Basin) has 11 mol% H₂ within fractured igneous basement directly overlain by sedimentary rocks (McInnes et al. 2017).

Note: H₂ generation with no genetic link to neither ultramafic rocks nor faults requires broader guidelines (Truche and Bazarkina 2019).

Additionally, and from the Australian perspective, Australia’s enormous endowment in mineral and natural gas reserves/resources provides an advantage and solid foundation for multiple potential H₂ systems in the geological settings outlined herein. The local volumetric bias towards Precambrian cratons allows optimum resident time and, together with high heat producing granites (Huston et al. 2012), should maximise radiolytic H₂ generation. Opportunities lay under evaporite seals for H₂ accumulations (Figs 4 and 11). Based on limited well penetration from petroleum exploration, for example, thick (>100 m) halite sequences are concentrated in central and western Australia (Fig. 4). Although evaporite seals (halite) are a priority for He entrapment, especially in the Amadeus and Officer basins (Haines and Allen 2020), dual natural H₂ and He prospects should also be considered, not only in these two basins but also in the surrounding Precambrian basins (Fig. 4). Furthermore, evaporitic rocks beside halite, e.g. potash and gypsum, may also provide H₂ storage and sealing opportunities in other sedimentary basins (e.g. Georgina Basin). Future discoveries of thick evaporites in under-represented eastern Australia should raise opportunities for natural H₂ exploitation closer to major population centres.

Although natural H₂ content in Australian natural gases is generally low, H₂ enrichment will occur during LNG processing. H₂ contents in Australian natural gases can exceed He concentrations. There is an estimated He resource of around 100 Bcf based on analysed He contents in offshore and onshore wells (Boreham et al. 2018). Given that a large proportion of Australian natural gas to market is in LNG, potential opportunities may exist for LNG-linked H₂ recovery, as there are presently for He. For example, in Australia’s only He processing plant (Darwin Helium, Darwin, Northern Territory) the He feedstock gas (i.e. tail gas from the Darwin LNG plant) has around 3 mol% He, i.e. concentrated by around 30 times to that of the LNG plant’s feed gas (from the offshore Bayu-Undan offshore gas field), whereas there the H₂ content was considerably lower (Boreham et al. 2018). Finally, the development of predictive H₂ exploration guidelines will greatly assist natural H₂, in particular from an abiogenic source, becoming an increasingly attractive exploration target.

Most Australian natural gases contain natural H₂, although H₂ concentrations in the majority of these gases are at low to trace levels (i.e. less than 0.01 mol%). Encouragingly, there are a few with very high H₂ contents (i.e. >10 mol%) that are mainly associated with Precambrian H₂ sources. The stable hydrogen isotopic composition of H₂ in the small number of Australian gases analysed in this study is highly depleted in ²H, supporting a predominant abiogenic source. The wide range in natural H₂ sources necessitates diverse exploration strategies that must take into account migration pathways and trapping mechanisms. An obvious starting point for H₂ exploration is with the characterisation of H₂ surface seepage proxies using remote sensing techniques coupled with physical sample collection. Although H₂ surface flow rates are relatively low, their intensity points to similarly scaled undercover H₂ resources. Such an approach mimics the state of play at the beginning of petroleum exploration in the late 19th Century. Needless to say, the first oil explorers could only imagine the vast petroleum resources of today.

Precambrian basement rocks are the obvious exploration choice given the large number of known H₂ discoveries globally, their composition and the excessive time available for serpentinisation and radiolysis processes; two of the main H₂ producing reactions in the geosphere and amenable to modelling. Based on these two reactions, onshore Australia is estimated to support a maximum H₂ inferred resource potential of ~1.6 to ~58 MMm³ year⁻¹ down to a depth of 1 km.

With the aid of geochemical, geophysical and petrophysical techniques, the identification of substantial sedimentary thickness above basement with associated magmatic intrusions, would be a paramount requirement to increase the possibility of large occurrences of natural H₂ in continuous reservoirs and tight seals. Further, fault-accessible reservoirs can readily accept deep advective H₂, while diffuse H₂ may not necessarily enhance H₂ concentration within petroleum reservoirs due to its high reactivity.

Hydrogen is carbon-free, but unlike fossil fuels it is continuously being generated from the same source over a wider range of depths and temperature providing ‘timeless hydrogen’. Given the enormous, cumulative amount of H₂ that has been generated since the earth was formed, the likelihood of potentially large H₂ reservoirs is considered high, awaiting discovery using proven exploration guidelines.

Table S1. Data used to estimate H₂ resource potential for onshore Australian to a depth of 1 km are available on the journal’s website as Supplementary material to this paper.

The authors declare no conflicts of interest.

No funding from external organisations was received for this research.