Winter 2025
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Winter 2025 Volume 4 Number 4 ISSN 2977-1927 03 Comment
21 Maintaining momentum in hydrogen
research
04 A new energy chapter
Phil Longhurst, Cranfield University, UK, considers how hydrogen research centres can maintain momentum amidst setbacks and challenges posed by global policies.
Miro Cavkov, Euro Petroleum Consultants (EPC), discusses how the Middle East and Africa are positioning themselves as dominant players in the global clean energy transition.
24 Unlocking Europe’s hydrogen future
Valentina Di Mauro, Honeywell, UK, discusses why liquid organic hydrogen carriers present a scalable, infrastructure-ready solution for Europe’s hydrogen economy.
27 Lessons from the field
Jeff Grant, HTEC, Canada, outlines the important considerations involved in building a hydrogen hub for heavy-duty transport, using the Metro Vancouver area as a case study.
31 Material matters
Mario Esche, Herose, Germany, explains the development process behind designing specialised valves for safe and reliable use in hydrogen systems.
35 Caverns of opportunity
Bilal Hassan and Nigel Curson, Penspen, UK, analyse the potential of salt caverns in providing long-term, cost-effective hydrogen storage.
10 Charting a path through APAC’s new
energy commodity economy
39 Staying on the path
Thomas Koller and Keelan O’Neil, DNV, navigate the balance of production, transport, and use to strengthen connectivity across Asia Pacific’s clean energy economy.
Adam Schleyhanhn, Fluid Components Intl, a Dwyer Omega Brand, discusses hydrogen gas flow measurement and functional safety on the pathway to net zero.
15 Beneath our feet
45 Safety meets efficiency
Andrew Hume, Thor Energy PLC, analyses the rise of natural hydrogen and South Australia’s leadership in the sector.
Gregory Shahnovsky, Gadi Briskman, and Gregory Yakhnin, Modcon Systems Ltd, UK, discuss how advanced analysers and AI-driven optimisation can enable safe, efficient, and cost-effective hydrogen production.
19 Going for gold
Owain Jackson, H2Au, explores the potential of gold (also known as white or natural) hydrogen as a clean fuel and the importance of actively searching for it.
53 Digital duplicates
Menica Antonelli, Daniela Boni, Salvatore Romagnuolo, and Nicola Tamburriello, KT Tech S.p.A, a NEXTCHEM company (MAIRE group), consider how digitalisation tools can be transformative for hydrogen production in chemical plant operations.
Endress+Hauser is a global leader in measurement instrumentation, services, and solutions for industrial process engineering. With expertise spanning flow, level, pressure, temperature, gas, and liquid analysis, the company helps customers optimise processes for efficiency, safety, and sustainability. Serving various industries, Endress+Hauser combines innovation with deep application knowledge and a commitment to quality. Through continuous technological advancement and specialised know-how in hydrogen, the company drives reliable, precise, and sustainable process measurement and control worldwide.
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M
uch of the media focus surrounding the hydrogen sector centres on blue and green hydrogen production. And rightly so. Both offer scalable, lower-carbon pathways that can support the energy transition at industrial levels. However, another clean energy option is lying right below our feet: natural hydrogen. The buzz around white (or gold) hydrogen – to give natural hydrogen its place on the hydrogen colour spectrum – has been growing in recent years. Scientists have discovered that naturally occurring hydrogen is more widespread than previously thought, leading some to believe that it could offer a cheap, clean energy source. A 2024 study by the US Geological Survey (USGS) suggests that there could be between 1 billion and 10 trillion t of hydrogen in the Earth’s subsurface – trapped under rocks with low permeability. Best guesses estimate that there is likely to be around 5.6 trillion t. And while most of this hydrogen is likely to be “in accumulations that are too deep, too far offshore, or too small to be economically recoverable”, according to the study’s authors, Geoffrey Ellis and Sarah Gelman, if just 2% of this geologic hydrogen was recoverable, it could meet projected global hydrogen demand for approximately 200 years. Indeed, Ellis and Gelman believe that it would contain approximately twice as much energy as is stored in all of the proven natural gas reserves on Earth.1 What’s more, white hydrogen is likely to have a significant cost benefit over its colourful cousins. According to Rystad Energy, Canada-based producer Hydroma Inc. extracts white hydrogen at an estimated cost of just US$0.5/kg in Mali (more on that project later), while projects in Spain and Australia are aiming for a cost of approximately US$1/kg.2 All of this has sparked a bit of a gold (hydrogen) rush, with at least 60 companies publicly announcing that they are exploring for natural hydrogen, and exploratory efforts underway in a number of countries including the US and Australia. In France, scientists have uncovered a massive 46 million t reserve of hydrogen beneath the soil of Folschviller, worth an estimated US$92 billion. However, all of this excitement must be met with a sense of caution. At present, no commercially viable wells have been discovered. In fact, the only place on Earth that currently uses white hydrogen is the small village of Bourakebougou in Western Mali, at a project operated by Hydroma Inc. Here, natural hydrogen was accidentally discovered back in 1987 after an unfortunate worker lit a cigarette while digging a water well, and it is now used to produce electricity for the village. Uncertainty still hangs over the role that natural hydrogen will play in the energy transition, with questions surrounding how much hydrogen can realistically be recovered from the ground, and whether natural hydrogen is a genuinely renewable resource at scale. But if a commercially viable hydrogen well is discovered in the coming years, then we could be on the brink of a new age of energy exploration. For a deeper dive into the potential of the natural hydrogen sector, turn to pages 15 and 19 of this issue for detailed articles from Thor Energy PLC and H2Au.
1. FARAND, C., ‘The precious ‘white gold’ fuel buried in the Earth’, BBC, (24 July 2025), https://www.bbc.co.uk/future/article/20250723-the-worlds-race-to-drill-for-natural-white-hydrogen 2. The white gold rush and the pursuit of natural hydrogen, Rystad Energy, (13 March 2024), https://www.rystadenergy.com/news/white-gold-rush-pursuit-natural-hydrogen
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Miro Cavkov, Euro Petroleum Consultants (EPC), discusses how the Middle East and Africa are positioning themselves as dominant players in the global clean energy transition.
T
he Middle East and Africa (MEA) are entering into the next transformative stage in the global energy transition. The region is redefining its role in a low-carbon world by leveraging its natural advantages to become a central player in hydrogen, its carriers, and sustainable derivatives. Hydrogen, and the broader family of hydrogen carriers such as ammonia and methanol, has emerged as a cornerstone of global decarbonisation strategies. Its potential to decarbonise hard-to-abate sectors, including refining, chemicals, metallurgy, aviation, and heavy sea transport, makes it an indispensable player for achieving net zero ambitions by 2050. Few regions are better positioned than MEA to lead this transformation. The combination of abundant renewable, solar and wind resources, vast land availability, advanced industrial infrastructure, and significant investment capacity provides a strong foundation for developing and implementing a competitive and sustainable hydrogen driven economy.
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A new energy chapter: from legacy grey hydrogen to low-carbon pathways
Hydrogen is not new to the region. For decades, it has been a vital input in refining, petrochemical and fertilizer industries, primarily produced from natural gas through the steam methane reforming (SMR) process. However, this traditional ‘grey hydrogen’ production process emits significant carbon dioxide, so it is now evolving to another stage. The shift underway is toward lower-carbon hydrogen production, where both blue hydrogen (produced via the SMR process equipped with carbon capture, utilisation, and storage (CCUS) systems) and green hydrogen (produced via water electrolysis powered by renewable energy) play the core role in this shift. Many downstream facilities in the Gulf are already adopting CCUS integration, capturing emissions from hydrogen production units and industrial furnaces. These investments not only cut operational emissions but also extend the lifespan of existing assets while aligning with net zero commitments. In parallel, countries are advancing large scale green hydrogen projects powered by renewable energy. Electrolyser facilities are now being built adjacent to solar and wind farms, creating integrated production hubs capable of generating clean hydrogen for domestic use and export. Additionally, membrane separation and hydrogen recovery technologies are gaining attention as intermediate solutions for recovering hydrogen from refinery or petrochemical off-gases, improving efficiency, and minimising waste. These technologies allow for incremental progress toward decarbonisation, harvesting the hydrogen molecule from downstream streams, while preserving the integrity of existing industrial operations.
Regional strengths: building on natural advantage
The MEA region possesses a combination of unique strengths that make it exceptionally well-suited for hydrogen production. The area benefits from some of the world’s highest solar radiation levels during day times and strong suitable wind conditions during night times, particularly across North Africa and the coastal zones of the Arabian Peninsula. These abundant renewable resources provide an ideal foundation for large scale, low-cost hybrid power generation and energy preservation. Vast stretches of uninhabited land further enable the deployment of utility scale solar and wind projects, ensuring the availability of ample space for integrated renewable and hydrogen developments. In addition, the region’s well-established industrial infrastructure, including already built extensive port networks, export terminals, and energy distribution corridors, offers a ready-made backbone for building a complete hydrogen value chain. This is complemented by the region’s strong financial capacity and technical experience from national oil companies, sovereign
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wealth funds, and regional energy developers which have decades of expertise in delivering complex downstream and energy mega-projects, allowing them to attract investment, mobilise partnerships, and manage risk efficiently. Together, these advantages position Middle Eastern and African nations among the world’s lowest-cost producers of green hydrogen. As economies of scale expand and electrolyser technologies continue to advance, hydrogen from the region is expected to become globally competitive within the coming decade.
Country strategies: diverse and unique paths with shared common goals
While the region shares the common objective to lead in low-carbon energy transition, each country follows a pathway tailored to its resources, industrial, local, and export market landscapes. Saudi Arabia has positioned hydrogen as a pillar of its Vision 2030 economic diversification plan. Through flagship projects and partnerships, the Kingdom is advancing both blue and green hydrogen production integrated with renewable power, ammonia synthesis, and storage, transport, and export infrastructure. The UAE has developed a multi-pathway hydrogen strategy combining blue, green, and pink hydrogen, produced using nuclear energy which is now considered as one of the best net zero enablers during the transition, due to the lack of carbon emissions while generating electricity from nuclear powered steam turbines. Supported by major partnerships between ADNOC, Masdar, and global technology providers, the UAE aims to establish itself as a reliable global supplier while decarbonising domestic industries. Oman has taken a structured, policy-driven approach through its state-owned company, Hydrom, coordinating hydrogen development zones powered by hybrid systems combining wind and solar sources. The country’s strategy focuses on local industrial participation, downstream integration, and export to Asian and European markets. Qatar continues to emphasise blue hydrogen, aligning with its existing gas infrastructure and carbon management expertise. The integration of hydrogen with ammonia and methanol production supports its export-oriented energy strategy while lowering life-cycle emissions. In North Africa, countries such as Egypt and Morocco are capitalising on their renewable potential and proximity to Europe to develop green hydrogen and ammonia export projects. Egypt’s Suez Canal Economic Zone has become a focal point for international investment in large scale hydrogen and green ammonia facilities. Morocco is similarly developing renewable-based hydrogen projects that build on its strong solar and wind base, with an eye toward European interconnections. Elsewhere in Africa, countries like Namibia, South Africa, and Mauritania are progressing early stage hydrogen hubs, seeking to
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combine renewable development with industrialisation and green export opportunities. Despite the lack of a unified regulatory framework across MEA, most countries align their national strategies with the global net zero goals. Each party applies tailored policy instruments reflecting local industrial and market capacities, supply chain maturity, and strategic priorities such as collaborations through joint ventures.
Hydrogen carriers and derivatives: expanding the value chain
Beyond hydrogen itself, its derivatives, particularly ammonia, methanol, and methyl-cyclo-hexane, are gaining importance as flexible carriers and low-carbon fuels. Ammonia offers a practical solution for large scale hydrogen transport and storage, while methanol provides a feedstock opportunity for sustainable fuels and chemicals. The integration of hydrogen with nitrogen or carbon-based feedstocks opens multiple pathways for decarbonisation. Ammonia can serve as a zero-carbon marine fuel or fertilizer feedstock, while methanol supports sustainable aviation fuel (SAF) production through alcohol-to-jet processes. By leveraging hydrogen to produce these commodities, the MEA region can extend its legacy of global energy trader into a new sustainable era, by evolving into exporting not only just molecules but also expanding decarbonisation know how and unlocking the net zero potential globally.
Challenges, hurdles, and structural considerations
Despite strong progress, the region must navigate several challenges to scale hydrogen production sustainably and competitively. Regulatory alignment is one of the key hurdles. The absence of common certification standards, emission measurement protocols, and guarantees of origin complicates export negotiations. Establishing regional and international harmonisation will be critical for long-term market confidence. Water availability presents another challenge. Electrolysis requires significant volumes of purified water, and many Middle Eastern countries face chronic water scarcity. However, coupling electrolysis with desalination and water recycling systems can significantly mitigate this, though it gives a pinch of higher project complexity and energy consumption. Infrastructure readiness is a further constraint. Existing oil and gas pipelines and terminals require adaptation for hydrogen handling. Developing dedicated hydrogen corridors, storage facilities, and port infrastructure will be essential for scaling exports and meeting expected higher future demand. While the market demand is expected to grow by mandates, it still remains in its infancy.
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Although European and Asian off takers are emerging, long-term contracts and pricing frameworks are still evolving, so sustained policy support and international collaboration will be required to close this gap.
Investment and policy making outlook
Despite these challenges, hydrogen investment across MEA is accelerating rapidly. Public-private partnerships are at the core of most major developments, bringing together national energy companies, international contractors, global utilities, and technology providers. Sovereign wealth funds and institutional investors are increasingly allocating capital to hydrogen and renewable linked energy projects as part of broader ESG commitments. International financial institutions are also recognising hydrogen as a key component of sustainable development portfolios. Governments across the region are adopting enabling frameworks, including land allocation for renewable projects, financial incentives, and infrastructure planning. These policies aim to create a predictable environment that de-risks the early stages of investment and promotes industrial stability through diversification. As certification systems mature and carbon pricing mechanisms expand, MEA hydrogen projects are expected to attract even greater global participation, establishing the region as a cornerstone of the global hydrogen economy.
Pathways to 2050: hydrogen as a catalyst for net zero
Hydrogen and its derivatives are not just seen as an energy alternative anymore, rather they are becoming an essential instrument in achieving global net zero emissions by mid-century. For the Middle East and Africa, the hydrogen economy represents both a decarbonisation tool and an economic transformation opportunity. The region’s ability to generate renewable energy at scale, apply legacy knowledge, integrate new and advanced technologies, and leverage existing industrial ecosystems offers a distinct competitive advantage. With coordinated policy frameworks, continued investment, and international cooperation, MEA nations can transition from being traditional energy exporters to leaders of the low-carbon era. In doing so, they can supply the world with the clean fuels, chemical building blocks and materials essential for balancing the global energy sustainability and ensuring that the energy legacy of the region evolves further in the decades ahead. The Middle East and Africa hold the keys to a global hydrogen future. The region’s abundant renewable potential, strategic geography, and proven industrial capabilities position it to not only meet its own net zero commitments but also to fuel the world’s transition toward a cleaner and more resilient energy system.
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Thomas Koller and Keelan O’Neil, DNV, navigate the balance of production, transport, and use to strengthen connectivity across Asia Pacific’s clean energy economy.
E
lectrification is the foundation of global decarbonisation, but it is not enough to deliver the energy transition. Achieving net zero requires more by addressing the deep challenges of slashing emissions in heavy industries like aviation, steel, shipping, and cement. Of the 14 countries included in the Asia Pacific (APAC) scope for this article – Australia, Brunei Darussalam, Cambodia, Indonesia, Japan, Lao PDR, Malaysia, Myanmar, New Zealand, the Philippines, Singapore, South Korea, Thailand, and Vietnam – 11 have set net zero targets, covering 92% of regional emissions. For this to happen, new energy commodities (NECs) – hydrogen, ammonia, sustainable fuels, and carbon capture and storage (CCS) – must provide over a quarter of regional emissions reductions. Their adoption, however, creates a geographic mismatch. Demand centres like Japan, South Korea, and Singapore lack land for major renewable projects.
Supply will hinge on countries with abundant renewable potential such as Australia, Indonesia, and Malaysia. This imbalance demands new international trade routes and region-wide energy policies. The region’s NEC landscape will also be shaped by its neighbouring giants. China is scaling green hydrogen, and India is advancing on green ammonia. While focused domestically now, their manufacturing scale and future export potential will inevitably influence costs, technology adoption, and trade flows across the entire region. Furthermore, competition from blue hydrogen producers in the Middle East and North America adds another layer to the strategic calculus for import-dependent nations.
Understanding the new energy tools
Success depends on a practical understanding of these commodities, their value chains, and infrastructure.
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Hydrogen Hydrogen is versatile, serving as both an energy carrier and a critical feedstock for other NECs like ammonia and synthetic fuels. Its production, especially from renewable sources, is central to the new energy economy. While the principle of splitting water with electricity is simple, large scale production relies on advanced electrolysis methods, each with distinct operational strengths. Alkaline electrolysis offers mature, stable technology for large scale projects. Proton exchange membrane (PEM) systems respond well to intermittent power from solar and wind, but may have higher costs. Solid oxide electrolysis (SOEC) operates at high temperatures, boosting efficiency near waste heat sources. The choice depends on the offtake requirements, which dictate the necessary scale, power source, and hydrogen output purity. This includes blue hydrogen from natural gas or coal with carbon capture, particularly from suppliers outside the region.
Sustainable aviation fuel (SAF) SAF is the main option for decarbonising long-haul aviation, as it can be blended with conventional aviation fuels in existing aircraft and infrastructure. There are eight approved production pathways, which may be divided into three main categories. The most mature method, Hydroprocessed Esters and Fatty Acids (HEFA), refines waste oils and fats. The Alcohol-to-Jet (AtJ) pathway converts ethanol into fuel but has limited commercial use. Power-to-Liquid (PtL) processes offer a long-term solution by combining green hydrogen with captured carbon dioxide (CO2). All SAF pathways remain more expensive than conventional fuel, though blending mandates are spreading the cost across all travellers to help scale production. This creates a strategic challenge. Current HEFA production faces hard supply limits, while scalable solutions like PtL require massive investment in renewables, CO2 capture, and hydrogen infrastructure. The sector is making gradual progress, but without stronger policy support and risk-sharing for scaling these technologies, aviation will face a fuel shortage that prevents it from meeting its climate targets.
CCS CCS is a vital tool for decarbonising sectors with process emissions that cannot easily be solved by electrification or fuel switching. It involves capturing and purifying CO2 from industrial waste gas streams and intermediate storage at hubs to achieve scale before transport to permanent storage.
Table 1. The economic reality of new
energy commodities
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Commodity
Cost per unit of energy (US$/GJ)
Carbon storage
15
Hydrogen
41
Ammonia
41
SAF
50
Methanol
56
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The concentrated CO2 is then moved by pipeline or ship to geological storage sites, like saline aquifers or depleted oil and gas fields. Emitters need revenue streams to cover their investment in capture facilities, which can come from carbon taxes or tax credits. The value chain often involves a complex network of actors, from emitters and hub developers to transport and storage operators.
A new map for energy trade
Mapping supply and demand for emerging energy commodities shows a major shift in the region’s economic geography. Modelling indicates that a small group of countries will dominate supply, with others relying almost entirely on imports. This split is rooted in natural resources and land availability. Australia’s exceptional solar and wind endowment, combined with abundant space for large scale projects, positions it to supply approximately 75% of NECs, while Malaysia and Indonesia offer the geological capacity for large scale carbon storage. Demand is concentrated in Japan, South Korea, Singapore and Indonesia. The most significant trade flows will run between Australia and these economies, accounting for roughly 74% of regional NEC trade. Japan and South Korea will require hydrogen and ammonia for power and green steel; Singapore will need ammonia and methanol for shipping. These shifts reshape regional energy geopolitics. In steel, new plants can use hydrogen-based direct reduction, whereas existing facilities will depend heavily on carbon capture, underscoring the importance of developing a regional CO2 transport and storage network.
Turning plans into pipelines
The shift to new energy carriers brings engineering challenges. Repurposing natural gas pipelines for hydrogen, for example, introduces the risk of hydrogen embrittlement. Full scale test rigs now simulate real operating conditions to verify material integrity under high-pressure hydrogen, while non-destructive methods such as ultrasonic and magnetic particle testing identify flaws and help maintain safety. Safe handling is equally critical. Ammonia is a global commodity with well-established risk controls, but its toxicity demands strict measures for new use cases. As a major maritime hub, Singapore is already developing unified safety standards for ammonia bunkering. Partnerships between the Global Centre for Maritime Decarbonization (GCMD) and the Maritime and Port Authority of Singapore (MPA) are producing the training, rules, and emergency procedures needed for ports and vessels.
Real-world project catalysts
Pilot projects and joint ventures are already testing the technical and commercial feasibility of NEC value chains. The JOGMEC CCS projects in Japan show the country is planning for both domestic and cross-border carbon transport and storage. Of the nine projects chosen in 2024, four plan to store CO2 elsewhere in the APAC, confirming the need for a regional trade network.
But at the risk of stating the obvious, the scale of infrastructure needed to deliver the energy transition is enormous. 12 billion solar panels, 2.7 million wind turbines, 189 new ports, and 1221 carriers will be required by 2050, meaning a project-by-project approach is too slow to meet the region’s goals. Despite technical progress, NECs face a major economic barrier insofar as all the options cost far more than fossil fuels. The marginal abatement cost for the region is projected at US$386/t of CO2, well above any planned carbon pricing in the region. The total annual cost gap with fossil fuels is estimated at US$407 billion. The financial burden falls mostly on governments and financiers, not end-consumers as the ‘green premium’ is small for final products like cars, houses and food. Energy is only a small part of the final cost, so passing the premium to consumers will not drive a market-led transition. This means market forces alone cannot spur the required investment and deployment of NECs. Strong policy action through carbon taxes, subsidies, and mandates are required to de-risk high-capital projects and make them viable. A fragmented geographic approach may create inefficiencies and slow regional supply chains. DNV’s 2024 ‘ASEAN Interconnector Study’ found that coordinated regional planning could cut decarbonisation costs by US$800 billion by 2050 compared to each country acting alone. Resource sharing and interconnected grids would optimise renewable deployment and minimise land use, creating a compelling economic argument for regional cooperation.
The strategic imperative for a new alliance
The challenge for APAC is no longer about technical barriers; successful projects across the region demonstrate technological viability. The path forward now lies in practical bilateral and multilateral agreements to build trade corridors, harmonise standards, and align carbon accounting: y Establishing trade corridors to connect resource-rich and demand-centre economies while managing long-term infrastructure dependencies. y Aligning safety and technical standards to enable safe cross-border trade of hydrogen and ammonia. y Implementing coordinated carbon mechanisms to create investment signals for carbon capture and closing the cost gap with fossil fuels. Regional cooperation offers the most practical path to a secure energy transition. Without it, APAC faces higher costs and delayed progress. The opportunity for coordinated action begins now.
Note
This article summarises key findings from DNV’s whitepaper, ‘The Role of New Energy Commodities in Decarbonising Asia Pacific.’ The authors would like to thank Magnus Killingland for his contribution to this article.
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Andrew Hume, Thor Energy PLC, analyses the rise of natural hydrogen and South Australia’s leadership in the sector.
T
he net zero transition is accelerating, but decarbonising heavy industry remains one of the toughest challenges. Petrochemical refining, fertilizer production, and chemical manufacturing are the backbone of modern economies, whilst also being some of the hardest industrial processes to decarbonise. All of these ‘hard-to-abate’ industries depend on hydrogen as a key feedstock, and more than 99% of that hydrogen supply is still sourced from fossil fuels. In 2023, the International Energy Agency reported that 97 million t of hydrogen was manufactured, leading to 920 million t of CO2 being directly released into the atmosphere, a figure that appears to be continuing on an upward trajectory, year-on-year.1 Whilst green and blue hydrogen have received attention in recent years, green is far from ‘green’, with only a fraction of the renewable energy being converted to hydrogen; and the technology is currently uneconomically expensive to develop at scale. Blue hydrogen takes a ‘dirty process’ that manufactures hydrogen from natural gas and aims to transfer as much of the
harmful CO2 emissions as possible into permanent underground storage facilities. Beyond industrial uses of hydrogen, once harnessed, it is also one of the cleanest energy sources which burns to form water, and nothing else. As a result, the world is now searching for this truly net zero, natural form of hydrogen which has the potential to be produced at scale and at lower costs than manufactured hydrogen. Natural hydrogen occurs continuously beneath our feet and provides the opportunity to both deliver mass decarbonisation of hard-to-abate sectors, and liberate the ultimate clean energy source. Natural hydrogen challenges assumptions about what ‘clean’ really means. Early discoveries in Africa and North America suggest that this naturally occurring gas may be more abundant than previously thought; at economically viable concentrations. It offers the promise of truly clean hydrogen to provide clean feedstocks to industry and can provide a real ‘net zero’ energy source to deliver clean power to all. As global interest rises in this burgeoning sector, attention is turning to South Australia, where its favourable geology and forward-looking,
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nurturing policies and environment could combine into a perfect location to demonstrate and grow the large scale production of clean hydrogen. No longer would hydrogen need to be manufactured, but rather a new age of low environmental impact hydrogen discovery and production may take over, benefitting the entire planet.
What is natural hydrogen?
Natural hydrogen, also known as ‘white’, ‘gold’, or ‘geologic’ hydrogen, refers to hydrogen gas that occurs naturally in the Earth’s subsurface. Unlike hydrogen produced via electrolysis or from fossil fuels, natural hydrogen requires no energy-intensive manufacturing process, nor does it emit greenhouse gases (GHG). It is generated by natural geological processes deep within the Earth, whereby conventional oil and gas drilling methods are being cleanly repurposed for environmentally sound uses to extract this versatile resource and energy source. Despite its promise, natural hydrogen is sometimes misunderstood, often getting confused with the economically challenged green hydrogen or incorrectly bundled with natural gas and oil due to its subterranean origins. The reality is that it is neither of these, but rather provides both the cost advantages of the cheapest hydrogen generating processes, alongside or eclipsing the environmental benefits and zero emissions of green hydrogen. Green hydrogen, whilst clean in its end use, requires substantial renewable electricity input for its production. Blue hydrogen relies on fossil gas, with a post-production effort made to sequester, in underground gas storage facilities, some of the huge volumes of CO2 that are generated. Unlike fossil fuels, natural hydrogen extraction is an extremely low-intensity activity and delivers clean materials for industrial or energy purposes as it releases minimal carbon and only minor surface infrastructure. Since the gas is produced continuously by natural geological processes, it represents an opportunity to provide long-term, and perhaps even perpetual production. So, natural hydrogen challenges conventional thinking, with the earth able to provide this most elemental of substances via ongoing geological processes deep underground. In the future, natural hydrogen may even replace manufactured hydrogen, and perhaps deliver the promise of the wholesale use of hydrogen as a global energy source, a substance so pure that it ‘burns’ to form pure water, and nothing else. For industrial decarbonisation, the solution does not lie in producing hydrogen, but in discovering it, and thus, mother nature really does have the answers.
Hydrogen’s role in industry
When natural hydrogen is discussed in the media, the focus often falls on its potential as a new clean energy source. While this represents an exciting step forward in the clean energy transition, its most urgent and important role may well be the decarbonisation of many carbon-intensive industries. Currently, around 97 million t of hydrogen are used each year in fertilizers, refining, and chemical production. These applications alone account for roughly 2.5% of global CO2 emissions. With demand expected to more than double
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by 2050, relying on fossil-based hydrogen threatens to lock in even higher emissions. Natural hydrogen is emerging as a practical solution. At estimated production costs of US$1/kg or less compared with US$2 - 4 for grey hydrogen (from natural gas), and an average of more than US$8 for green hydrogen, it presents a cost-effective, cleaner way for heavy industry to reduce emissions without upending existing processes. For sectors where electrification is not viable, this could be the first scalable low-carbon alternative.
Why South Australia?
Few places are watching this more closely than South Australia, a region already renowned for its leadership in renewables. The region’s geological history plays a crucial role in this potential. Much like the hydrogen exploration efforts currently underway in Kansas in the US, South Australia is home to ancient crystalline basement rocks and large geological fault structures. These features are known to be conducive to the formation and trapping of natural hydrogen deposits. Hydrogen can be generated through several natural processes, including hydrolysis, where iron-rich rocks chemically react deep underground with water, and radiolysis, where water is split into hydrogen in the presence of rocks such as granite. Other sources may include the degassing of primordial gases, incorporated into the Earth during the solar system’s formation and slowly released over time, or from shallow biological processes. South Australia’s geology offers promising conditions for all these processes, as well as several other proposed mechanisms, thanks to its abundant ancient rock formations and tectonic features. Recent discoveries of natural hydrogen in countries like Mali and the ongoing exploratory successes in Kansas, US, and in South Australia, have demonstrated that significant reserves of natural hydrogen can be found in areas with comparable geological characteristics. These developments are encouraging for South Australia, suggesting that commercially viable hydrogen deposits can be uncovered.
Industry players and activity
Exploration companies are beginning to assess South Australia’s hydrogen potential, supported by the increasing evidence of natural hydrogen systems in comparable regions around the world, and the encouraging drilling results and potential of South Australia. Several exploration firms, including Thor Energy, have secured exploration licences and are beginning investigations to assess South Australia’s hydrogen potential, encouraged by the increasing evidence of natural hydrogen systems in comparable regions around the world. Thor Energy has already seen strong soil geochemistry results, with natural hydrogen readings up to several thousand times above background levels. This increase in activity in the region aligns with the broader shift in the mining and energy sectors, as firms look to diversify into sources critical to decarbonisation in response to shifting investor expectations and climate-related regulatory changes. What also distinguishes South Australia from many other exploratory regions is the degree of governmental support underpinning these efforts. The South Australian Government has a proven track record of progressive energy policy,
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often positioning the state at the forefront of renewable energy deployment in Australia. The South Australian Government’s willingness to foster new industries through targeted policy frameworks and exploration incentives makes it a promising environment for emerging clean technologies.
Infrastructure and strategic advantages
South Australia’s position as a potential global leader in natural hydrogen is also supported by its well-established infrastructure network. Recognising the need to liberate energy transportation as well as storage technologies and infrastructure, the state is underway with numerous pilot projects. This means that hydrogen produced in the region could be easily integrated into these domestic decarbonisation efforts or exported to key international markets. The financial commitment to developing this infrastructure is also significant. The government has committed over half a billion dollars into hydrogen projects, infrastructure, modelling tools, and developer support.2 There is also a ‘Hydrogen Jobs Plan’ aiming to deploy electrolysers, power generation and storage facilities, such as the 250 MW of electrolysers and 200 MW of generation and storage in the Whyalla region, as part of this broader push.3 Additionally, South Australia boasts existing pipeline infrastructure, deep-water ports, and established transport corridors that can be adapted for hydrogen distribution. The state’s proximity to growing clean energy markets
both domestically and in Asia also presents a compelling export opportunity. Perhaps most importantly, South Australia has a skilled workforce already familiar with resource exploration, drilling, and related engineering disciplines, owing to its long history of mineral and energy extraction. This presents a crucial advantage in developing a nascent industry like natural hydrogen, where expertise in geology and subsurface resource management is essential.
Looking ahead
If natural hydrogen proves commercially viable, it could rewrite the decarbonisation playbook. But it will also force a new conversation about what ‘clean’ really means. Is it time to admit that the cleanest hydrogen might not need to be made at all? The energy transition has always been a mix of technology, geology, and politics. Natural hydrogen sits right at the intersection of all three, and South Australia may soon be where that debate moves from theory to reality. For industries running out of options to decarbonise, it is important to consider that the next great hydrogen revolution might not be engineered – it might be discovered.
References
1. ‘Global Hydrogen Review’, International Energy Agency, (2024). 2. ‘Hydrogen in South Australia’, Government of South Australia, https://www.energymining.sa.gov.au/industry/hydrogen-andrenewable-energy/hydrogen-in-south-australia 3. ‘South Australia’, HyResource, https://research.csiro.au/hyresource/ policy/australia/south-australia/
The premier source of technical and analytical information for the renewable energy industry Register for free at www.energyglobal.com
Owain Jackson, H2Au, explores the potential of gold (also known as white or natural) hydrogen as a clean fuel and the importance of actively searching for it.
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ound by net zero commitments, the vast majority of the world’s countries are looking for clean energy to displace fossil fuels from their energy mix. Much of the focus is on renewable electricity, but for energy-intensive sectors and those that are hard to decarbonise, hydrogen is the clear alternative. Much attention has been focused on the so-called rainbow. For instance, green hydrogen can be commercially manufactured through electrolysis or plasmolysis – provided the process is powered by renewable energy – whereas blue, turquoise, and grey hydrogen can be synthesised from a range of fossil fuels. There is even pink hydrogen, generated using nuclear-powered electrolysis. Despite this bewildering range of manufactured hydrogen sources and processes, it is doubtful that any single option could achieve sufficient volumes or economics to match growing hydrogen hype.
These reserves of gas can be trapped by impermeable layers, accumulating into significant volumes over time. As a primary, rather than manufactured energy source, natural hydrogen is abundant, low cost, low carbon, and sustainable. The world has long known of this resource. 100 years ago Australian drillers discovered significant amounts of hydrogen at the Ramsey and American Beach wells. It has been found accidentally whilst drilling for oil and gas reserves since then, but it was not until 1987 – with the discovery of a hydrogen well in Bourakebougou, Mali – that people sought to proactively exploit natural hydrogen’s potential value. And what potential? The US Geological Survey has estimated that around 5.6 trillion t of geologic hydrogen is already trapped underground around the world, and that another 15 - 31 million tpy are created. That, it says, is “twice the amount of energy in all the proven natural gas reserves on Earth”.1
An abundant energy source
A ready solution
In recent years, however, an alternative source of hydrogen has re-emerged that could exceed the world’s demand – potentially for hundreds of years. Natural geologic hydrogen, also known as gold or white, is exactly that: pockets of the gas created within certain rock formations, theoretically just waiting to be extracted and used. Geologic hydrogen is produced naturally within the earth as the result of several processes, but as much of 80% of it is thought to be the result of serpentinisation. Here, water reacts with rocks rich in iron and magnesium in the earth’s crust, or on the ocean floor.
Importantly, extracting this hydrogen is not an unrealistic fantasy. The International Energy Agency (IEA) assesses the technology readiness level (TRL) for natural hydrogen extraction at 6 - 7 (where nine is the highest). Indeed, much of the required expertise and equipment for hydrogen extraction already exists in the petrochemical industry and there is arguably no ‘first of a kind’ technology required to develop and scale the natural hydrogen industry. That is a stark contrast to the manufactured hydrogen sector, where many plays rely on novel technologies, yet to be de-risked and proven at scale.
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Figure 1. Much of the required expertise and equipment for hydrogen extraction already exists in the petrochemical industry.
Figure 2. 80% of geologic hydrogen is produced through serpentinisation when water reacts with iron and magnesium-rich rocks or on the ocean floor.
Figure 3. Similarity to established oil and gas industry practices, means hydrogen investment and risk depends on a well understood exploration hit rate.
Figure 4. The US Geological Survey has estimated that 5.6 trillion t of geologic hydrogen is already trapped underground.
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Natural hydrogen is entirely viable as a primary energy source. It has already seen limited production in Mali. It could be extracted and used at scale within a few short years. H2Au’s view is that, if realised at its full potential, natural hydrogen could address a US$6 trillion/yr energy market, and save over 7 Gt/yr in emissions by 2050. So, what is the holdup? It has been long known that the hydrogen reserves at Mali would not be a one-off. Until recently, however, all of the world’s discoveries of natural hydrogen have been accidental or incidental – often arising during prospecting for other gases or resources. Yet we know, from hundreds of years of fossil fuel and mineral exploration, the type of geologies and territories in which hydrogen is formed and trapped – so what is to stop us actively going looking for them?
Exploring for hydrogen
H2Au’s founders first visited the hydrogen well at Bourakebougou in 2008 – long before many were even thinking about the potential of natural hydrogen. The US Geological Survey began a formal investigation of natural hydrogen resources in 2021. By 2024, active exploration campaigns were ongoing in Australia, Brazil, Colombia, the US, and various countries in Europe and Asia. Businesses at the forefront of this exploration must first identify regions that are known or suspected to contain reserves of natural hydrogen, then secure exploration and production licences. It is one thing to suspect the presence of hydrogen, but identifying commercially viable reserves depends on deep experience and geological expertise. Much of H2Au’s own know-how and model building comes from analysing the well at Mali, and having first-hand knowledge of the geology in that area. As a geoscience-led team, H2Au already has both the internal experience and external partnerships to acquire and interpret the vast data set, such as seismic surveys, required to de-risk exploration. Supply and service chain collaboration is invaluable here in moving dots on a geology map through the exploration phase and towards production. This includes actively partnering with oil and gas drilling experts to leverage and adapt their tried and tested techniques to safely develop hydrogen wells and infrastructure. The key to successfully locating natural hydrogen, and then extracting it at scale, is blending in-house IP in resource discovery, with operational exploration experience across diverse cultures and land-uses. In other words, having both the science to find natural hydrogen, and the ground level experience to execute its commercial extraction. The simplicity of natural hydrogen extraction, and its similarity to established oil and gas industry practices, means that its investment and risk profile depends on a well understood exploration hit rate, rather than whether novel manufacturing technologies will actually work. And once natural hydrogen is found, the OPEX costs are very low: unlike manufactured hydrogen, there is no ongoing need for large amounts of energy, water, and complex plant maintenance. Given the vast amounts waiting to be discovered, natural hydrogen is rapidly emerging as a compelling and exciting prospect. Low in technological risk, and with minimal operating costs, it presents a convincing answer to the world’s energy demands, and in turn holds major promise for global carbon reduction and net zero goals.
Reference 1. https://cen.acs.org/energy/hydrogen-power/Trillions-tons-hydrogenwaiting-under/103/i7
Phil Longhurst, Cranfield University, UK, considers how hydrogen research centres can maintain momentum amidst setbacks and challenges posed by global policies.
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ydrogen energy appears to have been sidelined by big industry players, with Airbus, BP, and Shell all announcing delays to hydrogen research investments and projects. It is the Trump effect: the renewed support for fossil fuels that has had a sudden and immediate influence, in terms of the mindsets and policies of both businesses and governments globally. On the surface at least, that means a serious reversal of progress being made towards replacing black with green technologies in manufacturing, energy, and aviation, removing the confidence and sense of a common, clear direction
that is so essential to turning research concepts into working solutions. But it is at this moment that Cranfield has pushed ahead with closing down its specialist oil and gas research facilities. The multi-phase flow lab, for example, which has been the basis of decades of work on subsea drilling, is being stripped out and sold off. At the same time, space is being created for a full-service hydrogen lab, including an engine test centre focused on hydrogen, not oil. Significantly, the majority of financial backing behind the new CH2i facility on campus (Cranfield Hydrogen Integration Incubator) comes from businesses,
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£46 million from across transport, aerospace, energy and among those industries with targets for decarbonisation, such as steel, food, and ceramics (with the remaining third funded by Research England). Hydrogen-power is high on the agenda for industry internationally, particularly in Europe, the MENA region, and nations such as India, etc. The reality is that US policy on fossil fuels is very short-term. In the context of the evolution of the world’s energy infrastructure, now more than 120 years old, the Trump years are a blip, and will do nothing to change the direction of travel towards new energy sources and solutions. If large energy companies have pulled back from their commitments to hydrogen then it is also because of the short-term opportunity from pushing oil and gas, and also because of temporary market conditions, windfall taxes, instability, reduced profit margins.
Figure 1. Graphene structure for new hydrogen-secure materials.
The momentum behind hydrogen research and the bid to establish viable systems for production, transportation, storage, and different forms of low and zero carbon uses is unaffected. Whatever delays and distractions there might be, in whatever sector, the same need for workable alternatives is not going anywhere. And meanwhile, the UK has taken on a leading role in hydrogen, making it internationally competitive, especially when it comes to the use of feedstocks in hydrogen production, the use of electrolysis and catalysts, biomass and fermentations, and sorbent enhanced methane, as well as in work on finding practical applications for industries of all sizes. Cranfield’s CH2i is due to be fully operational by March 2026, a new technology incubator for accelerating hydrogen research through to operational delivery. Building on 30 years of hydrogen research at the University, there will be a full hydrogen ecosystem on campus, linking projects and facilities in production, storage, materials, and usage. The technology incubator will accelerate hydrogen research through to delivery for use in industry. The Hydrogen Integration Research Centre contains a variety of lab spaces for fundamental research and smaller experiments involving H2 (or related fuels such as ammonia or methane) and H2-related materials and structures, for developing next generation hydrogen production plants, electrolysis, catalysts, and green hydrogen. The Centre includes office space for researchers and R&D partners, meeting rooms and an Innovation Space for events. The key functional areas include a Clean Laboratory, Characterisation Testing Laboratory, Wet Preparation Laboratory, and an Innovation Hub. The Clean Lab is a controlled environment designed to adhere to strict air quality and safety protocols, minimising any form of contamination – critical for precision when conducting sensitive hydrogen research (in new materials and technologies for generation of hydrogen and its derivatives, storage, distribution, fuel-cells, combustion
Figure 2. The HyPER hydrogen production plant on Cranfield’s campus.
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and other applications). For example: catalyst performance under clean conditions; catalyst durability testing under dust-free conditions; adsorption/desorption studies; water/sea-water electrolysis studies; impedance studies; electroplating characterisation; long-term stability testing; methane cracking lab reactors; ammonia combustion studies under clean conditions; and optical characterisation. The Characterisation & Testing Lab is for evaluating the performance, efficiency, and safety of hydrogen-related systems such as electrolysers, fuel-cells, and hydrogen storage. The Lab is also used for the development and optimisation of hydrogen production processes, ensuring they meet quality, safety Figure 3. The planned CH2i facility building. and industry standards for commercial use (ISO 17025 is used for testing most common samples). More specifically: electrocatalyst Other research projects include a focus on safe and effective performance testing (both anodic and cathodic performance handling of hydrogen. National Gas Transmission, the UK’s testing); SE-SMR catalyst durability testing; methane cracking gas network operator, has made a commitment to upgrading catalyst durability testing; methane cracking catalyst regeneration the full network to allow for a switch to hydrogen, and has an studies; gas adsorption/desorption studies; water/sea-water objective of connecting up with continental Europe’s network electrolysis: electrode screening and long-term stability of hydrogen-ready pipelines by the early 2030s. Cranfield has testing; electrochemical impedance studies; and ammonia worked on improving the performance of the most common combustion testing. form of mild steel pipelines to ensure there is no hydrogen The Wet Preparation Lab is a workspace for preparing diffusion or containment failures. While natural gas does not have samples, materials and components before they are moved to moisture issues, it is very important to make sure that hydrogen – the specialised testing or experimentation areas, such as the particularly that coming from electrolysis – is separated from any Clean Lab and Characterisation & Testing Lab; and a flexible moisture as its addition to the pipeline will, again, accelerate the space for prototyping new devices and refining hydrogen internal pipe damage through corrosion, leading to accelerated production techniques. For example: solvent based processes; hydrogen diffusion into the steel lattice and cracking. catalyst synthesis (catalysts for SE-SMR, methane cracking, Cranfield, in partnership with Levidian Nanosystems, has ammonia cracking); sorption materials synthesis; water splitting developed a graphene-based paint – a simple material made electrode preparation (substrate cleaning, multilayer coating, solely from a single layer of carbon atoms, assembled in a pre-conditioning, etc); ammonia cracking electrode preparation hexagonal pattern. The simplicity of the structure means it is easy (substrate cleaning, multilayer coating, pre-conditioning etc); to anticipate how it will behave, as well as being incredibly strong electro-deposition (galvanostatic deposition, potentiostatic (estimated to be 200 times stronger than steel) – which is being deposition and pulse deposition); spin coating, drop casting, and used to secure pipelines for safe hydrogen use. The effectiveness doctor blade coating. of the new paint has been validated in the laboratory The Test Cells and LH2 Test Area involves nine indoor environment following National Gas standards. In aviation, there is the development of liquid hydrogen fuel configurable test cells. Each 60 m2 cell will have a protected tanks. This involves designs for a type VI cryogenic tank founded operators’ control room; and eight are paired with a sliding on a guarantee that even if active cooling or other systems fail, partition to provide up to 120 m2 of test space for larger the materials being used will keep the liquid hydrogen at a safe experiments. The newly-constructed building will allow temperature and pressure environment for long enough for for full HGV access to test cells and includes a yard for the aircraft to land and issues resolved. Brand new materials open air experiments. involved include a self-healing polymer, aerogels (synthetic porous One of the central elements of the campus ecosystem is the ultralight materials), and a graphene layer. The first prototype production of hydrogen. A new generation plant is operating on of type VI cryogenic hydrogen tank is being tested in 2025, with campus for the testing of bulk production of ‘blue’ hydrogen, flight testing expected to start in 2026. involving integrated carbon capture, utilisation and storage. Some of the timescales for transition might look something Working with the US-based Gas Technology Institute (GTI) and for the future, but in the context of both the history of energy British energy company Doosan Babcock, the 1.5 MW/hr pilot technologies and the urgency of net zero targets and climate plant has demonstrated how high purity H2 can be produced at change, hydrogen is imminent. Based on current progress, a 30% lower cost than conventional steam methane reforming Cranfield University would expect to see manufacturing methods. Carbon emissions are cut by 97% compared with industries decarbonising through their use of hydrogen for heat traditional hydrogen production. The consortium plans to processes within the next 10 years (supported by a network of upscale the plant ten times for clean hydrogen production from hydrogen-HGVs for logistics on roads in less than 15 years). natural gas.
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Valentina Di Mauro, Honeywell, UK, discusses why liquid organic hydrogen carriers present a scalable, infrastructure-ready solution for Europe’s hydrogen economy.
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H
ydrogen is commonly positioned as an important enabler in advancing carbon reduction strategies across hard to abate industries – shipping and aviation as examples – and can add a low-carbon option to the energy mix. However, some questions remain on how to best store, transport, and distribute at scale. Liquid organic hydrogen carriers (LOHC) present a currently available solution. LOHC is not a new technology; it is a natural extension of process technologies that have been in deployment for more than 60 years and is currently part of the commercial supply chain. Recent developments include ENEOS’s plan to construct the first commercial scale LOHC project in Japan, which will allow hydrogen to be transported using existing refining infrastructure. Japan’s choice to lead with LOHC illustrates how the technology is already being used in markets that face similar energy security and import challenges to Europe. Far from lacking technical readiness, almost every key aspect of LOHC – from design, catalysts, and operating parameters to maintenance and operational experience – is at technical readiness level between 7 and 9 (TRL 7 - 9). Because of this, it has decades worth of commercial data to utilise and learn from. Instead of regarding LOHC as a potential future solution, it is time to recognise that it is ready and waiting to be deployed.
Dismantling misconceptions
LOHC is commercially ready and can be deployed in existing systems, using the same families of catalysts, reactors and process control systems that already exist globally for refining and petrochemical production. The carriers can be used for hundreds of cycles, lasting up to 20 years, to offer a stable and long-lived asset which can continue delivering results without need for expensive and time-consuming replacements. This means a less than 1% carrier loss in each cycle, and less than 2% hydrogen losses. LOHC is derived from long-established and proven technology which not only
leverages existing infrastructure but can also enable faster timelines to deployment by using pre-existing process units. It is a proven, infrastructure-ready solution with the potential to accelerate hydrogen’s role in meeting global carbon reduction goals.
Unlocking Europe
The EU has set a target of importing 10 million t of renewable hydrogen by 2030.1 However, Europe has yet to capitalise on the opportunity that green and renewable hydrogen present. In contrast to India and the Middle East as notable examples of potential green hydrogen producers, offtake agreements in Europe are still scarce. These agreements are essential because they provide producers with the certainty needed to commit capital, expand capacity, and drive costs down through scale. This scarcity is most likely down to cost considerations, as the pricing of green hydrogen remains much higher than traditional hydrogen. While cost may be a factor, the reality is that Europe will not meet its carbon reduction goals without importing green hydrogen. The key obstacle is not production, but the absence of a value chain which links exporters with European buyers. For example, the Japanese government incentivises adoption of hydrogen as an energy source by providing clear guidelines and standardised methodologies for calculating the carbon intensity of hydrogen. This helps to create market confidence, driving increased uptake and broader awareness while demonstrating how regulatory clarity can unlock private-sector momentum, reducing uncertainty for both producers and consumers. In Europe, Germany has established itself as a leader in hydrogen adoption, led by a comprehensive National Hydrogen Strategy which supports significant investment in the technology needed for domestic green hydrogen production. This approach combines a dedication to technological advancement with a legislative commitment. Both are essential phases of a long-term transition that will allow hydrogen to become a cornerstone of Europe’s clean energy system.
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Infrastructure readiness
Hydrogen producers in regions such as North America, India, and the Middle East are ready to export at scale. However, European buyers have been slow to adopt LOHC technology due to understanding how the process works – how hydrogen is bound to a liquid carrier, shipped, and then released for use. The use of toluene and methylcyclohexane (MCH) as a carrier, both of which are compatible with existing infrastructure including pipelines, tanks, refineries, and processing units, means that customers can reuse the tanks that they already have in place at import terminals and refineries. These catalysts also have a long lifespan – a minimum of 10 years for toluene hydrogenation, and at least six years for MCH dehydrogenation. Such solutions can retrofit existing gasoline production units to release hydrogen from the MCH carrier. Broader uptake of LOHC solutions means these units could be converted into hydrogen handling facilities for a lower cost investment than building brand new installations. This also contributes to employment retention, as existing workers at gasoline production units can easily transfer their skills due to the similar operation and maintenance of hydrogen handling facilities. This is particularly important for regions with strong industrial deployment, as it offers a forward-looking opportunity for communities to adapt and thrive throughout the energy shifts. Importantly, these retrofits can be completed during a planned turnaround in as little as two to three months, vs the years it takes to build a new greenfield site. This speed-to-market advantage makes LOHC one of the fastest and
most practical ways to scale hydrogen infrastructure, turning existing assets into a bridge to Europe’s lower-carbon future.
Speed to market
Hydrogen’s role in Europe’s energy transformation will depend not only on its production cost but also on how quickly it can be scaled. LOHC technology is particularly well-suited to this challenge because it can handle variable energy inputs. This is critical when green hydrogen is produced from intermittent renewable sources such as solar and wind, where production levels fluctuate depending on weather and grid conditions. The ability to store and transport hydrogen efficiently, even under variable input scenarios, ensures that the system can integrate smoothly with renewable generation. Of all available hydrogen carrier options, methylcyclohexane (MCH) offers some of the strongest economics. Its strength lies in the fact that it builds directly on well-established refining and petrochemical technologies, minimising research and development requirements and lowering deployment risks. By leveraging proven industrial processes and equipment, LOHC solutions avoid many of the cost and performance uncertainties that remain with some other alternatives. Another major advantage is speed. Because the infrastructure and operational expertise already exists, projects can move from planning to deployment far more quickly than greenfield alternatives. Retrofitting existing units and reusing current assets reduces both capital expenditure and lead time, ensuring that hydrogen can begin flowing into Europe sooner. For policymakers focused on meeting near-term carbon reduction goals, this speed-to-market benefit could prove decisive. The likely adoption trajectory also underscores LOHC’s relevance. Early adopters will be traditional refineries and petrochemical plants, which already consume hydrogen and need lower-carbon options to support their operations. The next wave will include heavy industries such as steel, cement, and chemicals, which are among the hardest sectors to decarbonise. These industries are beginning to explore low-carbon, and LOHC provides a practical pathway for them to do so without waiting for entirely new infrastructure to be built.
The key to Europe’s hydrogen future Figure 1. Honeywell LOHC technology can leverage under-utilised fossil fuel infrastructure for high-capacity, long-distance hydrogen transport.
Figure 2. Honeywell LOHC provides a lower cost hydrogen transportation solution.
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LOHC is a commercially ready solution that addresses key barriers to hydrogen adoption by providing a carrier with longevity of hundreds of cycles and a lifespan of 15 - 20 years. It is fully compatible with existing infrastructure and assets, can retrofit idle gasoline units, and offers the flexibility to work with variable renewable input. Using advanced technology, it is possible to achieve 99.9 mol% hydrogen purity without purification by pressure swing adsorption (PSA). Most importantly, LOHC delivers fast-track deployment timelines, with retrofits achievable in just two to three months compared to years for greenfield alternatives. Europe cannot delay the development of a hydrogen import value chain. LOHC technology represents a pragmatic, low-risk, and scalable pathway to connect exporters with European demand and turn hydrogen ambition into reality.
Reference 1. https://energy.ec.europa.eu/news/renewable-hydrogen-productionnew-rules-formally-adopted-2023-06-20_en
Jeff Grant, HTEC, Canada, outlines the important considerations involved in building a hydrogen hub for heavy-duty transport, using the Metro Vancouver area as a case study.
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he Vancouver area in British Columbia, Canada, has emerged as one of North America’s leading examples of hydrogen transportation in action. The region’s combination of reliable renewable electricity, ambitious climate policy, and collaborative industry partnerships makes it uniquely suited to develop the infrastructure needed for a hydrogen hub. A hydrogen hub is more than a single project – it is a connected network where hydrogen production, storage, distribution, and end use applications are co-located and coordinated. In the Vancouver area, that vision is taking shape through clean hydrogen production facilities, heavy-duty and passenger vehicle fuelling stations, hydrogen distribution networks, and real-world fleets putting hydrogen to work every day. It is the kind of integrated system that can grow steadily and demonstrate real progress toward decarbonising transportation. On paper, the idea seems simple: build the pieces and connect them. In practice, it is a complex process that aligns technology, supply chains, fuelling networks, and market adoption so that they come online in sync. It also requires strong government support to help projects advance from early-stage development to full scale operation. And once that hub is established and
running, the payoff is clear: a thriving hydrogen ecosystem in action, fuelling innovation, economic growth, and climate progress across the region. This article shares practical lessons from building Vancouver’s hydrogen hub for heavy-duty transport, covering the importance of aligning production and demand, matching infrastructure growth with market readiness, and creating the conditions for the hydrogen ecosystem to expand and thrive.
Clean hydrogen supply: the heart of the hydrogen hub It all starts with hydrogen – producing it cleanly, locally, and sustainably. In HTEC’s Metro Vancouver Hydrogen Hub, the Burnaby Clean Hydrogen Production Facility is already online, producing hydrogen in close proximity to the station network, while other facilities are in development to strengthen supply reliability. At the Burnaby facility, hydrogen is produced through electrolysis powered by BC Hydro’s renewable hydroelectricity, ensuring the process is nearly carbon-free from start to finish. The facility can distribute up to 1.8 tpd of hydrogen, 1 t from electrolysed hydrogen production and 0.8 t via liquid hydrogen
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transfill capabilities. This facility can provide fuel for up to 45 heavy-duty zero-emission trucks or 4000 zero-emission hydrogen fuel-cell passenger cars and is expected to reduce greenhouse gas emissions by as much as 10 000 tpy. Low-carbon hydrogen can also be produced through other pathways. In North Vancouver, for example, approximately 15 tpd of hydrogen is being vented into the atmosphere by a sodium chlorate plant. HTEC is developing a liquefaction facility that will capture, purify, and liquefy this by-product hydrogen, allowing it to be stored, transported, and integrated into the regional supply. Together, these complementary approaches expand supply options, diversify production methods, and create a more resilient hydrogen hub. But building this kind of clean hydrogen supply network takes more than engineering expertise, it requires sustained policy support, clear regulatory frameworks, and significant capital investment. Developing a production or liquefaction facility involves navigating lengthy permitting processes, securing access to renewable electricity, building connections to distribution infrastructure, and ensuring long-term market demand. Government incentives can also make the difference between a clean energy project that stays on the drawing board and one that breaks ground. One of the reasons Metro Vancouver has such strong potential – on top of its clean resources and talented engineers – is the range of support available in British Columbia and Canada. Tools like tax credits for producing clean fuels, accelerated cost recovery for clean infrastructure, revenue opportunities through the Clean Fuel Regulations, and targeted funding from provincial or federal programmes all help lower costs and reduce risk. When these supports work together, projects can move from concept to operation much faster, helping Canada meet its climate targets while laying the groundwork for a thriving hydrogen economy.
Keep production and demand close
A key lesson from hydrogen hub development is that it strengthens the system’s overall resilience. By coordinating production and fuelling under one umbrella, communication becomes faster, accountability is clearer, and schedules or issues can be adjusted more easily as they come up. The Metro Vancouver area offers a good example of this principle in action. An existing network of seven light-duty hydrogen stations (six of them owned and operated by HTEC) already draws on locally produced hydrogen, giving HTEC direct control over the fuel supplied to its stations. This control has
Table 1. HTEC stations uptime report October - 24
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Supply uptime
Hard uptime
Soft uptime
61%
58%
87%
November - 24 68%
56%
91%
December - 24 85%
72%
89%
January - 25
85%
83%
98%
February - 25
70%
67%
97%
March - 25
97%
93%
97%
April - 25
96%
95%
99%
May - 25
90%
89%
99%
June - 25
96%
93%
98%
July - 25
96%
92%
97%
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led to significant improvements in station uptime, reducing the risk of outages and making it easier for fuel cell electric vehicle drivers to plan their trips with confidence. To date, the network has dispensed more than 130 000 kg of hydrogen, abating an estimated 1500 t of CO2 emissions and serving a fleet of almost 300 hydrogen passenger vehicles. The experience has also provided valuable lessons in optimising delivery logistics, maintaining consistent safety and quality standards, and managing infrastructure as a connected system. Case in point: HTEC’s light-duty station supply uptime improved from 64% in October 2024 to 96% by July 2025. This demonstrates how gaining greater control over supply has directly translated into more reliable service for drivers. These insights are now being applied to the roll-out of HTEC’s heavy-duty fuelling infrastructure. New heavy-duty stations are in development, including one in Tsawwassen that sits at the intersection of major freight corridors and port operations. Its location allows it to support two critical initiatives: the BC Hydrogen Truck Pilot, which will deploy six heavy-duty hydrogen-powered trucks with local fleet operators to gather data on vehicle performance, fuelling behaviour, and operational reliability under real-world conditions; and the Ports Project, which will introduce fuel cell electric trucks at Vancouver’s marine terminals, one of the busiest freight hubs in the region. These projects are expected to reduce emissions by as much as 110 000 tpy of CO2, while providing valuable lessons for scaling. Together, these projects will test how proven strategies from the light-duty network can be adapted for the higher fuel volumes, faster turnaround times, and continuous operation demands of heavy-duty transport. The results will help shape how future hydrogen hubs are designed, ensuring that production and demand remain closely linked for maximum efficiency and reliability.
Lowering the first-mover risk
Early adopters of hydrogen transport face a unique challenge: committing to a new fuel before the supporting infrastructure and market demand are fully mature. Expand infrastructure too quickly, and it risks standing idle; wait too long, and potential operators may lose confidence in hydrogen as a viable option. The challenge is finding the right balance and matching the pace of infrastructure growth with the readiness of the market. One way to reduce this uncertainty is by coordinating more of the value chain. HTEC is doing this through its Vehicle Leasing Corp. programme by supplying heavy-duty fuel cell electric vehicles (FCEVs) to fleet operators through a leasing model that will use its refuelling infrastructure. This approach avoids dependence on third-party timelines that could deliver too many – or too few – vehicles for the network’s capacity. It ensures fuelling availability and fleet deployment advance together, reducing bottlenecks and helping the market scale more predictably. For many fleet operators, some of the biggest barriers to adopting hydrogen are not belief in the technology, but economics and operational uncertainty. Fuel costs may still appear higher today, but when factoring in impacts on uptime, payload, and incentives, hydrogen can offer a stronger total cost of ownership than battery alternatives. Leasing programmes that bundle fuelling access, maintenance, and driver training further help de-risk the transition, shifting costs from capital to operating budgets and giving fleets more financial flexibility.
Figure 1. HTEC’s clean hydrogen production facility. Policy signals are also shaping the landscape. The Government of Canada has set a target for 35% of all new medium- and heavy-duty vehicle sales to be zero-emission by 2030, rising to 100% for certain categories by 2040. While these targets are not yet binding, they are prompting companies to explore clean technologies and prepare for a shifting regulatory environment. Early movers who align with these targets will likely benefit from incentives, preferred contracts, and reputational advantages. Since October 2020, a total of 48 XCIENT Fuel Cell Class 8 trucks have been in operation in Switzerland. By June 2024 they successfully completed a driving distance of 10 million km powered by only green hydrogen, saving around 6300 t of carbon dioxide.1 In the US, G.E.T. Freight is operating 30 Hyundai XCIENT Fuel Cell trucks at the Ports of Oakland and Richmond as part of the NorCAL ZERO Project. Since September 2023, the fleet has logged more than 700 000 km in zero-emission freight transport.1 In Georgia, US, Hyundai Motor Group Metaplant America (HMGMA), in partnership with Glovis America, is operating 21 XCIENT fuel cell trucks to support nearly half of the plant’s logistics operations. These trucks are powered by on-site hydrogen production and fuelling infrastructure, demonstrating a practical application of clean hydrogen in industrial logistics.1 These cases underscore a key lesson: when infrastructure, vehicles, and operational readiness are developed in tandem, first-mover risk decreases, market confidence grows, and the path to scaling hydrogen transport becomes much clearer.
Building awareness and strengthening support
Beyond infrastructure, a successful hydrogen hub also depends on raising awareness and building knowledge among key stakeholders. Educating government agencies, regulatory bodies such as Technical Safety BC (TSBC), first responders, and permitting authorities is critical to accelerating adoption and ensuring safety. Stronger, more tailored regulation, developed in partnership with industry experts, help ensure that every hydrogen project meets rigorous design, engineering, and operational standards. At the same time, well-informed first responders, equipped with the right training and resources, can act quickly and confidently in the unlikely event of an incident. This combination of clear regulatory oversight and capable emergency response not only improves safety but also reinforces public confidence in the technology. By communicating openly about how hydrogen infrastructure is designed, built, and maintained according to stringent
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safety processes, stakeholders can dispel misconceptions and highlight the fact that hydrogen, when handled correctly, is as safe as any other widely used fuel. This transparency helps raise awareness of hydrogen’s strong safety record, strengthens trust in its use, and builds a supportive environment for continued investment and adoption – helping the entire hydrogen ecosystem in Metro Vancouver – and other areas – grow stronger, more resilient, and better equipped to scale.
From lessons to next steps
Developing a hydrogen hub is as much about learning in the field as it is about building infrastructure. In the Metro Vancouver area, years of planning, construction, and operation have created not just physical assets, but also a body of expertise that spans the entire value chain, from production and distribution to fuelling and fleet deployment. Along the way, we have seen what works, what needs refining, and where the challenges lie. Some lessons have been clear from the start, such as the value of keeping production and demand close, and the importance of matching infrastructure growth with market readiness. Others are still emerging as HTEC expands into heavy-duty applications, refines its operating models, and adapts to evolving policy and market signals. Each step adds to the collective understanding of how to make hydrogen transport practical, reliable, and scalable. The model taking shape in the Metro Vancouver area – integrated, locally focused, and designed to grow supply and demand together – offers a blueprint that can be adapted to other regions. While no two markets are identical, the principles behind this approach are transferable: align the moving parts of the value chain, work closely with operators and institutions, and ensure that infrastructure and demand evolve in tandem. As Canada and other countries look to accelerate the shift to zero-emission transport, sharing the insights gained here can help shorten the learning curve elsewhere. With collaboration, adaptation, and a willingness to keep learning, the experience built in the Metro Vancouver area can help guide the development of hydrogen hubs that fit the needs of diverse environments contributing to a cleaner, more sustainable transportation future worldwide.
Reference 1. https://www.htec.ca/hydrogen-fuel-cell-trucks-a-promising-path-forheavy-duty-fleets/#_edn3
Mario Esche, Herose, Germany, explains the development process behind designing specialised valves for safe and reliable use in hydrogen systems.
H
ydrogen, as a carbon-free energy carrier, requires safe and reliable solutions for transport, storage, and use. Hydrogen is stored and transported either in liquefied form or compressed at very high pressures in cylinders. High-pressure trailers are primarily used for regional transport over shorter distances. In these trailers, hydrogen is stored in metal or carbon fibre-coated cylinders at pressures of up to 500 bar.
Requirements for valves in hydrogen transport
A central component of the trailers are shut-off valves, which enable the individual storage compartments to be filled and emptied quickly. Their functionality is crucial for the safety and efficiency of the entire system. The requirements for these valves are exceptionally high. They must function reliably in a wide temperature range between -40°C and +65°C, as well as down to -255°C for liquid hydrogen. In addition, they are subjected to daily filling and emptying processes, which leads to a very high number of pressure and temperature cycles over the years. Since hydrogen is highly flammable, tightness is particularly
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important: even small leaks can lead to hydrogen build-up to unsafe levels in a confined space. In addition, due to its low viscosity, leak rates for hydrogen can be significantly higher than for media such as air or helium. At the same time, material compatibility must be ensured, as hydrogen can embrittle metals and penetrate polymers. Without the right choice of materials, there is a risk of cracking, seal failure, or creeping leaks.
Systematic functional analysis as a basis
When developing a hydrogen valve, Herose begins with a comprehensive analysis of the requirements. This is based on the applicable market and standard specifications, as well as on practical experience. In a structured process, the requirements are systematically translated into technical concepts. The focus is not only on pressure and temperature resistance or media compatibility, but also on aspects such as reliability, durability, and user-friendliness.
Material selection: the key to success
Even before prototypes can be manufactured, the right materials must be selected. This is where the particular complexity of hydrogen applications becomes apparent. A material that is generally considered suitable for hydrogen is not necessarily suitable for the specific conditions in the valve. Furthermore, polymers with identical designations can have significantly different properties depending on the manufacturing parameters. Incorrect material decisions could therefore lead to the failure of safety-critical components – a risk that must be avoided at all costs in the hydrogen environment.
Material selection is therefore an important process, with several potential candidates identified and then tested under relevant conditions.
Material testing under relevant conditions
A variety of test methods are available for qualifying materials in the hydrogen environment. The explosive decompression test is particularly relevant for sealing materials. In this test, the material is first loaded with hydrogen under high pressure before being abruptly reduced to ambient pressure. As such, it is possible to test whether the material can withstand extreme stresses or whether damage such as blistering or cracks can be detected. Herose invests a great deal of effort in identifying the right materials – this is the basis for a safe and reliable product. Comparative studies clearly show that materials with similar chemical compositions can deliver very different results. A supposedly suitable candidate may prove to be inadequate in practice, while another material may meet the requirements and be reliable in use. One key insight gained from experience is that tests with substitute media such as helium or nitrogen cannot be readily transferred to hydrogen. Only through direct testing with hydrogen can reliable conclusions be drawn about actual suitability of new products.
From prototypes to long-term testing
Once the suitability of the materials has been demonstrated, prototypes are manufactured. At Herose, these undergo an extensive test programme that verifies both mechanical strength and tightness. The valves undergo cycle tests to simulate stress, wear, and ageing. Before and after the cycles, internal leaks via the valve seat and external leaks are monitored and the tightness is determined. Initial tests are carried out with helium or nitrogen and later tests with hydrogen to ensure functional reliability under real world conditions. These tests are costly, but they form the basis for the necessary confidence in the resilience and durability of the valves.
Approval according to standards Figure 1. Tightness testing of a check valve.
Once the development and validation phase has been successfully completed, the approval of the valves follows. Depending on the application, different standards and test requirements apply, for example for use in stationary systems or in mobile trailers. As part of the approval process, additional tests are carried out, usually with nitrogen or air. These approvals are general and usually not specific to hydrogen.
Summary
Figure 2. Valve after performing a leakage test.
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The development of a product for use in a hydrogen environment illustrates the considerable effort involved in the safe use of this energy source. A key challenge, specifically for use with hydrogen, is the selection of suitable materials and their qualification under real conditions. Only through extensive testing – from explosive decompression to exposure to the load limit with pure hydrogen – can operational capability be reliably demonstrated. The results are products that meet the high requirements of the hydrogen market and ensure the long-term safety and reliability of the systems.
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Bilal Hassan and Nigel Curson, Penspen, UK, analyse the potential of salt caverns in providing long-term, cost-effective hydrogen storage.
G
lobally, underground storage is used to balance energy systems by absorbing seasonal or daily fluctuations in natural gas supply and demand. These systems are vital for energy security, grid
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stability, and market flexibility. Europe, the US, Canada, and China have extensive storage facilities. Underground storage is formed by utilising solution mined salt layers (salt caverns), depleted reservoirs, or aquifers (porous rocks). Of these, salt caverns provide the highest deliverability (withdrawal rate). Underground storage can be used for liquids or gases. There are 681 gas storage sites worldwide.1 Most are used for natural gas, with a few hydrogen and CO2 sites developing given the significant interest in the energy transition. The US Gulf Coast has 569 mapped domes that could support approximately 368 TWh of hydrogen storage. 2 Germany and the UK also have substantial Zechstein salt and other evaporite basins. For instance, Germany’s Etzel salt field is already being used on a pilot scale with 90 t of hydrogen storage capacity.3 The United Arab Emirates (UAE) sits atop significant Hormuz salt deposits or salt domes, most of which are in Abu Dhabi. Research studies have identified at least seven major salt diapirs (e.g. Jebel Al Dhanna, Sir Bu Nair, Dalma) composed of thick evaporites (1 - 4 km of salt) that have pierced through 6 - 7 km of overlying sediment.4 These are particularly large sites, for instance, Jebel Dhanna spans roughly 2.8 x 4.2 km, and the close by Sir Bu Nair is also similarly large. These sites have been mapped already and can host numerous solution mined caverns which can be used for hydrogen storage. While they are far from population (offshore islands and deserts) and overlain by marine or desert terrains, they are close to major industrial cities such as Ruwais as well as oil and gas developments. The first step for utilising such caverns is a geological analysis where high-resolution mapping (gravity, seismic analysis) of the area is used to confirm cavern location and size. Thereafter, pilot shaft-drilling is used to characterise salt purity. Such analysis will always benefit from existing oil and gas wells or surveys to refine models. Thereafter, large caverns are developed inside these domes. The next step to geological possibilities is the viability and readiness of the technology. While salt caverns are a proven technology for natural gas storage, the adaptation of these caverns for hydrogen is an emerging technology with a Technology Readiness Level (TRL) of 5 - 7. However, the prospects are good since salt is impermeable and self-healing, allowing high-pressure gas storage. In practice, caverns are solution-mined by
flushing freshwater for 1 - 3 years to dissolve salt. Typical cavern sizes might be 20 - 30 m high and 30 - 50 m wide, though some proposals envisage ‘giant caverns’ (hundreds of metres in each direction), as expected for potential sites in the UAE. Hydrogen has been stored inside salt caverns for decades. For instance, the UK has stored hydrogen in salt for Teesside chemical plants, and current R&D is mapping UK salt clusters for hydrogen storage. 5 These studies confirm that salt caverns can handle hydrogen similarly to methane. The EU’s HyPSTER project in France achieved the first hydrogen injection into a salt cavern in 2024.6 In addition to below ground preparation of the salt cavern, additional above ground infrastructure such as compressors, pipeline interfaces and gas treatment is needed. Salt caverns require cushion gas (for instance 20 - 30% of volume, often N 2) to maintain pressure. It is important that all balance of system equipment materials resist hydrogen embrittlement, by using dry, high-strength steels. In addition, tightness testing and continuous monitoring (pressure, acoustic sensors) are essential to detect any leaks. Advanced monitoring is recommended to ensure structural integrity and safety. With regards to deployment of hydrogen storage infrastructure, it is foreseen that above ground tanks shall be deployed initially, which would need to be expanded into underground salt caverns. Caverns are the only possibility to provide seasonal storage, required for large electrolyser outputs, sizeable variable renewable energy capacity, and substantial seasonal differences in power demand. In terms of levelised costs (as shown in Table 1), salt caverns offer the only credible scenario for long-term large scale seasonal storage spanning 2 - 4 months. Salt cavern storage has high initial CAPEX but extremely low incremental cost for long-duration storage. As per the latest study carried out by UCDavis, for a typical 500 t salt cavern, costs can be in the range of US$18 million, with 49% of this related to underground works (drilling, leaching), 24% related to surface facilities, and 27% related to brine management.7 The key cost drivers include freshwater for leaching and brine disposal logistics. This step incurs significant costs and time. A large scale cavern could require 5 - 10 years to develop. However, once built, operating expenses are modest, with pumping and monitoring cost being low (US$0.1 - 0.5/kg per cycle) compared to other steps.
Table 1. Cost estimates for various hydrogen storage options
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Storage option
Typical scale
CAPEX per kg H₂
Levelised cost (US$/kg)
Notes/source
Salt cavern
500 - 1000 t
US$30 - 40/kg
US$0.6 - 1.2/kg (for ~2 - 4 months)
(e.g. 500 t requires roughly US$18 million)8
Compressed gas tank
<1 t
US$600/kg
US$0.3 - 0.6/kg (1 - 2 days)
+0.4/kg compression energy7
Cryogenic liquid
5 - 10 t
US$30 - 50/kg
US$0.06 - 0.12/kg (1 - 2 weeks)
+ liquefaction cost (US$1.2/kg)7
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In contrast, above ground options for hydrogen storage have different scales and costs. For instance, compressed gas tanks are small, and capital costs can range around US$600/kg,8 making them practical only for daily cycling. Liquid hydrogen tanks cost US$30 - 50/kg8 and are suitable for up to weeks of storage. However, they suffer from boil-off losses. From an economic perspective, large scale hydrogen storage via salt caverns can offer several macro-economic benefits. Salt caverns can link upstream electricity and water sector and downstream hydrogen industries, optimising the use of curtailed renewable power generation and low marginal cost power for the production and storage of green hydrogen and its subsequent use in the fertilizer and petrochemical industry. By buffering intermittent renewables, caverns improve grid reliability and reduce the need for peaking gas plants. This lowers electricity costs and diversifies the economy from oil dependence. The existing LPG/ammonia export facilities can be repurposed for hydrogen carriers. Overall, this has the potential of producing abundant hydrogen at costs competitive to existing grey hydrogen uses. Hydrogen storage can also enable the use of carbon capture and storage or enhanced oil recovery in oilfields to produce blue hydrogen. The construction and operation of salt caverns and associated facilities will create skilled jobs (engineers, drillers, operators). The UAE government has projected tens of thousands of ‘green jobs’ from the energy transition.9 Many of these will be in renewable hydrogen and related fields. In terms of environmental impact, salt caverns have an overall positive impact, given the possibility to displace fossil fuels, cut CO2 emissions and improve air quality. Underground storage has minimal surface impact and salt’s natural sealing properties virtually eliminate fugitive gas leaks. Caverns also prevent surface spills or boil-off losses that plague above ground tanks. However, the production of salt caverns requires vast volumes of water to leach the salt (in the order of 50 000 - 125 000 m3 for a 500 t cavern). Disposal of the resulting hypersaline brine is a concern. It must be safely diluted or discharged offshore as per environmental regulations, typically using an outfall with dilution demonstrated by dispersion studies. The brine handling can be one-third of the project costs, but proper planning and re-use of brine can reduce the costs. It is important to prevent any ground water contamination which would allow brine or hydrogen to migrate into the soil. Thus, rigorous well integrity standards and continuous monitoring are mandatory. Public acceptance and social impact are crucial for underground storage projects. Globally, lessons from CO 2 storage show that community engagement is vital.10 In terms of salt caverns, usually projects have low visibility (remote sites, no odours), which may ease acceptance. However, it is important that the planning process should include communities and align the
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project with local interests such as hiring locals and sharing economic benefits. The public must be confident in the safety of subsurface storage. This shall require transparent communication about risk and visible monitoring programmes. In terms of policy, many hydrogen strategies explicitly mention geological storage (including salt caverns).11 High level support for storage projects is already there and there has been endorsement for hydrogen storage projects. In the near-term, caverns will likely be permitted under mineral/oil licensing regimes, with additional safety and environmental conditions. However, hydrogen’s unique issues (e.g. embrittlement) have not been attended to in many local codes. Policymakers will need to amend standards (possibly referencing ISO or US DOE guidelines) for hydrogen storage. Globally, very few governments have detailed hydrogen storage regulations. The UAE’s pace is similar; policies set broad direction, and specific regulations come in advance of project development. For example, Germany only recently updated the laws for hydrogen cavern storage (H2Cast). In conclusion, Penspen foresees salt caverns playing a major role in buffering renewable electricity supply from its subsequent conversion to hydrogen and use of the hydrogen in decarbonising hard-to-abate industrial sectors. Most importantly, salt caverns can provide system level flexibility, which is essential for reducing the cost of hydrogen production and increasing its competitiveness.
References
1. Underground Gas Storage: Pillar of Global Energy Security, Highlights from the CEDIGAZ Global Underground Gas Storage 2024 survey. 2. https://www.earthdoc.org/content/papers/10.3997/22144609.202321014#:~:text=569%20salt%20domes%20 located%20in,state%2C%20county%2C%20and%20salt%20 dome 3. https://www.hydrogeninsight.com/innovation/germany-slargest-salt-cavern-hydrogen-storage-demonstration-projectbegins-filling-operation/2-1-1817774 4. https://www.researchgate.net/publication/357250773_ Anatomy_and_uplift_history_of_the_emergent_salt_domes_ of_the_United_Arab_Emirates#:~:text=Hormuz%20salt%20 is%20more%20widespread,and%20East%20Rub%E2%80%99 5. https://es.catapult.org.uk/insight/hydrogen-salt-cavernstorage/#:~:text=Hydrogen%20salt%20cavern%20storage%20 in,technology%20for%20decarbonised%20energy%20systems 6. https://www.thenationalnews.com/news/ uae/2025/04/25/abu-dhabi-salt-lakes-dunes-uae-netzero-2050/#:~:text=The%20use%20of%20salt%20 caverns,injected%20into%20a%20salt%20cavern 7. Hydrogen Storage and Transport: Technologies and Costs, UC Davis Institute of Transportation Studies, 2024. 8. Underground hydrogen storage: The techno-economic perspective, Open Research Europe, 2024 9. https://cms.law/en/int/expert-guides/cms-expert-guide-tohydrogen/united-arab-emirates#:~:text=The%20UAE%20 has%20ambitious%20clean,10%20producers%20globally%20 by%202031 10. https://www.mdpi.com/19961073/18/6/1335#:~:text=emphasise%20that%20social%20 acceptance%20is,of%20natural%20gas%20in%20geological 11. https://cms.law/en/int/expert-guides/cms-expert-guide-tohydrogen/united-arab-emirates#:~:text=decarbonisation%20 plans%20for%20each%20of,significant%20development%20 before%20becoming%20feasible
Adam Schleyhanhn, Fluid Components Intl, a Dwyer Omega Brand, discusses hydrogen gas flow measurement and functional safety on the pathway to net zero.
H
ydrogen energy is gaining rapid popularity for several reasons, with political, environmental, and economic drivers also now leading to its expanded use. To better understand this trend, it is also important to look at the hydrogen value chain and consider the forms of hydrogen production, its applications and flow measurement requirements.
What is net zero?
Net zero emissions as a goal is an important political and environmental driver expected to limit climate change to preserve our planet. According to the experts, we need to limit the global temperature increase to 1.5˚F above pre-industrial levels. Currently, the Earth is about 1.1˚F warmer than it was in the late 1800s, and emissions continue to rise.
Enter hydrogen
McKinsey’s analysis shows that hydrogen could contribute to over a 20% reduction in greenhouse gas (GHG) emissions globally by the year 2050.1 Hydrogen will become a big business, attracting governments and corporate investment (Figure 1).
Understanding the hydrogen spectrum
The colour spectrum is a tool used to classify and identify the different types of hydrogen based on production methods, for example: � Green hydrogen: produced using renewable energy sources like solar or wind power through electrolysis, considered the most environmentally friendly option.
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y Blue hydrogen: derived from natural gas with carbon capture and subterranean storage technology to mitigate emissions. y Black hydrogen: produced from coal without carbon capture, resulting in extremely high GHG emissions.
The hydrogen value chain
The hydrogen value chain covers the process from production to utilisation. First, it is important to talk about how hydrogen is produced. In general, production is classified into two categories – high carbon and low carbon production. High carbon production includes gasification, using coal or organic material to generate hydrogen, and steam reforming (now the most common method of hydrogen production because of the lower cost). Electrolysis is another low-carbon production method that uses electricity to split water into hydrogen and oxygen. When paired with renewable energy sources, electrolysis can be a net zero process – even with its high cost – making it more desirable as an energy source to reach the net zero goal.
Electrolyser application solutions
There are three common types of green electrolysers (Figure 2). The first are PEM electrolysers, which contain a proton exchange membrane (PEM) that uses a solid polymer electrolyte. When current is applied to its cell during the process, water splits into hydrogen and oxygen gases. The hydrogen protons pass through the membrane and form hydrogen on the cathode side. The next type is the alkaline electrolysers (AELs), which contain water and a liquid electrolyte solution, such as sodium hydroxide. When current is applied to the cell,
the hydroxide ions move through the electrolyte solutions from the cathode to the anode. The hydrogen gas is generated at the cathode, and the oxygen gas at the anode. The final type is the solid oxide electrolysers (SOEs). These are solid oxide electrolysis cells, which run in regenerative mode and use the solid oxide as an electrolyte. When current is applied and water is fed into its cathode, the water converts into hydrogen gas and oxide ions. The hydrogen gas is captured for purification, the oxide ions move to the anode and release electrons to become oxygen gas. No matter the type of electrolyser, they all have at least one thing in common. They require accurate air, gas, and liquid flow measurement instrumentation in the production, storage, and transport processes. Thermal flow instruments are uniquely suited to hydrogen production, storage, and transportation systems because of their high accuracy measurement, consistent repeatability, low maintenance, long-life, and low life-cycle costs.
Thermal dispersion flow sensor construction
This basic construction of a thermal flow sensor consists of a sensor tube with two thermowells welded to the end (Figure 3). The first thermowell, referred to as the active sensor, contains a PT1000 temperature sensor plus a heater element inside. The second thermowell, referred to as the reference sensor, contains only a PT1000 temperature sensor. The heater element is supplied with constant power from the electronics and creates a differential temperature between the active and the reference sensors in the process. In addition to supplying power to the heater, the electronics also sense the temperature difference between the active and the reference sensor.
Thermal dispersion technology operating principle
Figure 1. Hydrogen energy forecast to reduce global emissions by 20%.
As the process fluids move through the piping, the molecules of the process cool the active sensor and change the differential temperature between the active and the reference sensors. This change is directly proportional to the gas mass flow of the process. The important point here is that thermal dispersion sensing is a direct mass flow measurement technology: there is no need for additional temperature or pressure, or flow calculators to measure the gas flowing in the pipe. Simply put, the differential temperature measured at the sensor is directly proportional to the actual density of the gas multiplied by the actual velocity of the gas, which is multiplied by the area of the pipe; this provides the mass flow of the gas and can be displayed in a choice of engineering units. As thermal dispersion sensors are a direct mass flow measuring device (not volumetric), changes in temperature and pressure directly affect the density of the gas and are automatically corrected to provide a stable mass flow reading regardless of those fluctuations.
Thermal flow instrument calibration
Figure 2. Green hydrogen process focus.
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Another issue in all types of flow instrument calibrations is the potential use of inferred variables. This occurs when density is assumed without the instrument being tested on a traceable calibration stand. For example, to save costs, an air calibration might be performed with a linear correction factor applied to
turbulent flow. That approach, however, greatly reduces the turndown ratio when trying to measure very small mass flow rates. To resolve this issue, some flow instruments utilise tab-type flow conditioners that create vortices that will eliminate errors associated with transitional.
Process safety concerns
Figure 3. Thermal dispersion technology flow sensing.
There are also key safety considerations that come into play for the handling of hydrogen. This gas has a wide ignition range of 4 - 74% in air. Its flame velocity is 5.6 fps, which is 4.25 times faster than natural gas. Since its combustion is nearly invisible, flames are not noticeable and can lead to accidental burns. hydrogen also has a low ignition energy. Hydrogen is stored at pressures between 5000 and 10 000 psig. As hydrogen has no odour or colour, leak detection and proper ventilation are required when stored in enclosed spaces. Its small molecule size can also cause hydrogen embrittlement of metal pipelines, resulting in the possibility of malformation of the pipe and pinhole leaks.
Hazardous area requirements
Figure 4. Thermal flow/level/temperature switch installed for green hydrogen production. offset the differences in the gas densities. Depending upon the flow sensing technology, these equivalencies do not account for the thermophysical properties of hydrogen and other gases, such as viscosity, or specific heat and thermal conductivity. Per industry standards, ISO 14511:2019 confirms that the best practice for calibrating a flow meter is to utilise the actual gas and mirror the process conditions being measured. Hydrogen gas calibration adds cost, but they are easily outweighed by confidence in accurate and reliable readings.
Hydrogen thermo-physical properties
There are several factors that show why the air-equivalency method for hydrogen flow instrument calibration and measurement is not a good practice. The differences in thermo-physical properties of the two gases are extreme (air vs hydrogen). If using a linear correction factor, the results would be highly questionable, given that the equivalent flow of hydrogen is only 4.56% that of air. Not only does this type of correction impact instrument performance, but it also limits the flow range. Using hydrocarbons such as natural gas for an equivalency media is also not much better. The correction factor is still under 10%.
Reynolds number transition
Most flow measurement technologies have issues when a gas flow transitions between laminar and turbulent flows. For thermal meters, this can most often be seen in smaller line sizes. Since the flow is not laminar or turbulent in this region, there are challenges associated with the randomness of the velocity profile. One way sometimes considered to eliminate transitional errors is to restrict calibrations to either laminar or
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For hydrogen and other process measurement applications in the oil and gas, chemical and refining industries, it is common for instruments to be installed in Class 1, Div 1, and Div 2 hazardous areas. As such, it is important to select an instrument rated for use in this environment. Process and plant engineers want to confirm with their instrument vendors that the product they are offering has the proper third-party certified approvals.
Functional safety concerns
Without failure rate data verified by an authorised third party, it is not possible to perform a suitable analysis of a safety instrumented function (SIF) that accounts for the logic solver, final element and sensor. Systems such as safe failure fractions (SFF) and safety integrity levels (SIL) alone, without knowing other hardware constraints and actual failure rate data, are not enough to be thoroughly safe.
PEM electrolysers Water and air flow monitoring Now consider some hydrogen processes and critical points for gas flow measurement where accuracy, repeatability and safety are essential. At a PEM electrolyser plant connected to a wind farm, excess energy that is not used by the grid will supply power to the PEM and produce green hydrogen for storage and later use. Two key points in the process need to be measured to maintain functional safety. The first point of measurement is verifying the flow of water into the system. Water is crucial because, without water, there is no molecular split and no hydrogen production. Also, the lack of water could result in residual current in the process, causing overheating and degradation of the electrodes. With a reliable thermal flow switch, such as the FCI FLT93 in place, a system shutdown could be initiated to prevent damage or the possibility of a catastrophic failure. The critical second measurement required is air ventilation monitoring of the PEM enclosure. This is critical because we need to ensure that any residual hydrogen that could be
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Alkaline electrolyser (AEL): acid water control
Shifting gears from PEM electrolysers to hydrogen AELs, a critical measurement to maintain the safety of the system is flow monitoring to the anolyte (acid water) and catholyte (alkaline) systems. The optimal performance of an AEL relies on keeping a balanced flow between the two control circuits. Flow switches in these circuits ensure pumps are working efficiently and allow optimisation of the process. They also prevent over-pressure conditions or flooding, which will cause operator safety hazards and possibly system failure. For this application and these reasons, the SIL 2 compliant FLT93S Series Flow Switch could help to assure safe and effective operation of hydrogen AEL production units.
Gas stream analyser monitoring
Figure 5. Thermal flow meter for green hydrogen production. released into the enclosure is dispersed before building up and reaching its flammable limit. As hydrogen has no colour and no odour, strict ventilation standards are in practice to make sure it is quickly diluted into the air to minimise the risk of ignition. In this case, FCI utilises the FS10i Flow Switch/Monitor family of products, with SIL 2 compliance, which gives plant operators the confidence that the system safety requirements are met.
Nitrogen purging Nitrogen purging is employed in hydrogen PEM electrolysers to remove oxygen and other unwanted gases from the system before, during, and after electrolysis. This gas purging step ensures safety and prevents possible hazardous conditions by creating an inert environment. Nitrogen is non-reactive and displaces other gases like hydrogen and oxygen. It also removes other contaminants that could corrode or degrade components in the system. Neutralising and removing hydrogen is especially important during electrolyser start-up, shutdown, or during system maintenance. The amount of nitrogen flowing into the system is measured to ensure the entire system is saturated and ready for safe operation, or in cases of system maintenance, safe for an operator to perform their duties under safe conditions. In this scenario, it could be recommended to use something like the FCI FS10i Flow/Switch Monitor to help improve safety.
Storage ventilation air Once hydrogen is produced, storage is required before transportation to other end users. Just like the air ventilation on the electrolyser enclosure, storage areas also need to have ventilation monitoring for the same reasons. Avoiding the build-up of residual hydrogen in this area and preventing the levels from reaching their flammable limit helps ensure operational safety.
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Measuring the gas hydrogen and oxygen output of the electrolyser with an analyser allows the operator to have a performance and efficiency assessment of the electrolyser. Sample lines pull off process samples for review by the analyser. They provide a detailed analysis of the stream content. This is an important measurement because many signs of process upset will result in unbalanced yields of hydrogen or oxygen, as well as provide early indicators of issues in the overall electrolysers’ operation. Monitoring flow in both the hydrogen and oxygen sample lines ensures companies are reading real-time process data. For instance, without monitoring flow, and if, for some reason, a sample line becomes plugged, then there’s a risk of analysing the same sample repeatedly. This would not provide the data needed by the operator to make critical process adjustments to ensure the electrolyser is operating at its highest efficiency and ensures a high level of functional safety. In this application, FCI would use the FS10A Fow Switch, which is designed for small line analyser applications to ensure that there is a continuous sample flow to the analyser.
Conclusion
As nations and businesses around the globe strive to reach net zero emission goals, hydrogen will continue to grow in importance as an energy resource. As hydrogen demand grows and drives the need for increased production, ensuring the safety of people, equipment, plants, and nearby communities will require adherence to strict functional safety protocols and global standards. Regardless of the type of hydrogen production plant or where hydrogen is used industrially, the accurate, repeatable, and safe measurement of air, gases, and liquids will be essential. Thermal flow instruments offer plant, process and safety engineers and managers a number of important advantages in the accurate and safe measurement of many process fluids. In addition, their rugged designs, low maintenance and long service life make these devices a lowest-installed and lowest life cycle cost choice for the measurement of hydrogen during its production, storage and use.
Reference
1. McKinsey & Company, Oil & Gas, ‘The clean hydrogen opportunity for hydrocarbon-rich countries’, https://www.mckinsey.com/ industries/oil-and-gas/our-insights/the-clean-hydrogenopportunity-for-hydrocarbon-rich-countries
Gregory Shahnovsky, Gadi Briskman, and Gregory Yakhnin, Modcon Systems Ltd, UK, discuss how advanced analysers and AI-driven optimisation can enable safe, efficient, and cost-effective hydrogen production.
H
ydrogen’s value chain has matured to the point where constraints are now less about feasibility and more about safe, efficient, and reliable operability. Hydrogen production through electrolysis is the entry point of the value chain, where water is split into hydrogen and oxygen using renewable electricity. Once produced, hydrogen must be delivered and integrated into existing energy networks. Transportation can involve pipelines, cryogenic liquid carriers, or ammonia/liquid organic hydrogen carriers (LOHC), each with specific challenges: leaks, purity degradation, and material embrittlement. Blending hydrogen with natural gas – often in the 5 - 20% range – offers an immediate decarbonisation pathway but requires precise control of composition to maintain Wobbe index and safety standards.
Production and transport systems must remain inside safe envelopes while consistently meeting purity specifications and adapting to fluctuating demand. Accurate online analysers for oxygen and hydrogen, together with impurity monitoring, provide the critical signals that advanced control systems – including those based on deep reinforcement learning (DRL) – need in order to optimise operations in real time. Standards such as ISO 14687 and SAE J2719 define strict purity specifications, while ASME B31.12 and NFPA 2 govern infrastructure design and safety. The opportunity lies in instrumenting critical interfaces, deploying robust in‑situ analysers and closing the loop with learning control to maximise yield, uptime, and asset life.
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Electrolyser production constraints and crossover monitoring
Gas crossover is one of the most important challenges in electrolyser operation. Small leaks of oxygen into the hydrogen stream, or vice versa, not only compromise fuel purity but also create immediate safety hazards. Even at ppm‑level concentrations, these signals are early indicators of diaphragm or membrane stress, pressure imbalance, or degradation of sealing elements. Continuous monitoring provides operators with the earliest possible warning before dangerous concentrations accumulate. Supervisory control systems use this data directly: if oxygen levels in hydrogen rise, the controller may reduce current density, adjust differential pressure between anode and cathode, or initiate short purge cycles. Conversely, if hydrogen content in oxygen increases, the system can respond by lowering stack pressure or reducing ramp rates. This dynamic control stabilises operation, prevents hotspots from parasitic recombination reactions, reduces Faradaic efficiency losses, and extends the lifetime of catalysts and membranes.
Hydrogen transportation and blending
Hydrogen transport pipelines and blending with natural gas networks must meet strict design and operational standards. ASME B31.12 covers fracture mechanics, materials and re‑qualification, while NFPA 2 sets safety codes. Oxygen ingress must be monitored continuously for emergency shutdowns and inerting. In blending projects, online composition analysers at multiple nodes ensure blend ratios remain stable across the network and allow downstream hydrogen recovery processes to be scheduled efficiently.
Table 1. Key impurity limits and recommended
analyser placement
Fuel‑cell grade hydrogen must meet ISO 14687 and SAE J2719 specifications with a fuel index ≥ 99.97 mol% and strict impurity caps. Oxygen, water, carbon monoxide, carbon dioxide, ammonia, sulfur species, and halogenated compounds are strictly limited. Continuous analysers positioned at production outlets, storage points, and transfer terminals ensure these purity targets are consistently achieved.
The importance of measuring critical process variables for safety and optimisation
In modern hydrogen systems – whether electrolysers, storage networks, or downstream industrial processes – safety and efficiency are inseparable. Maintaining stable operation requires continuous measurement of all critical controlled variables: oxygen, hydrogen, pressure, temperature, humidity, and impurities. Why? Because safety limits and process optimisation goals often overlap. For example: y Oxygen in hydrogen must be monitored at ppm levels to prevent contamination of fuel cells and downstream catalysts. y Hydrogen in oxygen must be measured with high sensitivity, since exceeding ~4% H2 in O2 creates explosive conditions. y Moisture balance (dew point) is vital both for conductivity (too dry → resistance ↑, efficiency ↓) and for safety (too wet → crossover ↑, purity loss ↑). These measurements are not just safeguards – they are the real-time inputs that power digital twins and advanced control strategies (APC, RTO, DRL/AI). With analysers providing ground-truth signals, supervisory control systems can balance load ramping, predict degradation, and optimise hydrogen yield under fluctuating renewable inputs. To illustrate, O2/H2 analysers serve as the ‘nervous system’ of the electrolyser control system, feeding live data that enable predictive control strategy rather than reactive correction. Without accurate in-situ analysers, even the most sophisticated AI models would lack the trusted signals needed to operate safely and efficiently.
Impurity
ISO 14687 limit
Recommended analyser placement
O2
≤ 5 µmol/mol
H₂ header
H2O
≤ 5 µmol/mol
Dryer outlet
CO
≤ 0.2 µmol/mol
Purifer outlet
CO2
≤ 2 µmol/mo
Purifier outlet
Different technologies serve different purposes depending on the required range, accuracy, and response time:
NH3
≤ 2 µmol/mol
Post cracking
Fluorescence-quenching technology
Total hydrocarbons
≤ 2 µmol/mol
Terminal
This technique relies on the principle that oxygen molecules quench the luminescence of certain fluorescent dyes in proportion to their concentration. The technology is well suited for both
Figure 1. Supervisory control stack for an electrolyser train.
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Purity specifications and analyser placement
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Oxygen analysers for hydrogen systems
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This provides highly selective and interference-free measurements. TDLAS analysers excel under harsh operating conditions, including high pressure and high temperature, making them well-suited for combustion control, process optimisation, and emissions monitoring. They are especially effective for path-integrated measurements across ducts, reactors, or flare stacks. Their non-contact nature reduces maintenance, though installation requires proper optical alignment and often purge systems to prevent window fouling.
Figure 2. Hydrogen pipeline and blending schematic.
Hydrogen analysers for hydrogen systems Hydrogen detection is equally diverse:
Thermal conductivity detectors (TCDs) TCDs measure changes in thermal conductivity of a carrier gas when hydrogen is present, as hydrogen has the highest thermal conductivity of all gases. This makes them highly effective in binary or near-binary mixtures, such as hydrogen in nitrogen, hydrogen in natural gas, or hydrogen in oxygen. TCDs are widely deployed for electrolyser monitoring, syngas production, and refinery applications. However, accuracy decreases in complex multi-component gas matrices, since other gases with different thermal conductivities can interfere.
Tunable diode laser (TDL) analysers Figure 3. Conceptual DRL framework integrating analysers and supervisory control. ppm-level and percent-level measurements, offering very fast response times, high robustness against chemical interferences, and excellent stability. It is particularly valuable in safety-critical hydrogen and hydrocarbon environments, where fast and accurate detection of oxygen ingress is required. The main limitation is the lower detection limit (LDL), which typically does not extend into the sub-ppm range. For most industrial applications, this is not restrictive, but ultra-trace measurements may require complementary technologies.
Electrochemical (galvanic) sensors Electrochemical oxygen sensors rely on a gas-permeable membrane that allows oxygen to diffuse into an electrochemical cell, where it undergoes a reduction reaction at the cathode. The resulting current is proportional to the oxygen concentration. These sensors are compact, relatively inexpensive, and suitable for portable devices, medical monitoring, and industrial safety. They are best suited for low-level oxygen monitoring but have finite lifetimes (typically months to a few years) due to reagent depletion and can be sensitive to cross-gas interference or humidity.
Tunable diode laser absorption spectroscopy (TDLAS) TDLAS is based on the Beer–Lambert law, where a tunable diode laser scans across oxygen’s absorption lines in the near-infrared or mid-infrared spectrum. The amount of absorbed light is proportional to the oxygen concentration along the optical path.
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For hydrogen detection, TDL systems use near-infrared or mid-infrared absorption lines. While hydrogen’s direct IR absorption is weak, TDL analysers can detect hydrogen indirectly through collision-induced absorption or by monitoring impurities (such as oxygen, carbon monoxide, or methane) in hydrogen streams. They provide rapid, stable, and highly selective measurements in high-pressure and high-temperature pipelines, making them increasingly relevant for hydrogen economy applications where purity certification and leak detection are required.
MEMS-based hydrogen sensors Micro-electromechanical systems (MEMS) hydrogen sensors represent a new generation of compact, low-power devices. They detect hydrogen either through thermal conductivity miniaturisation, catalytic reactions, or resistive film changes. Their small size allows fast response times (seconds or sub-seconds), portability, and integration into distributed sensor networks. MEMS sensors are increasingly used in fuel-cell applications, safety monitoring in storage facilities, and portable leak detection. Their limitations often include calibration drift and sensitivity to cross-gases, though advances in selective coatings are mitigating these issues.
Hydrogen purity analysers
For gas purity applications, higher analytical resolution is required. For ISO 14687 fuel-cell hydrogen standards, ppm-level precision is required:
Mass spectrometers Mass spectrometers ionise sample gases and separate species based on their mass-to-charge ratios, providing multi-component
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analysis with sub-ppm sensitivity. They are powerful but relatively expensive and require skilled operation and vacuum systems.
Micro-gas chromatography Micro-gas chromatography (micro-GC) miniaturises conventional GC columns, enabling fast cycle times (tens of seconds to minutes) for hydrogen alongside methane, carbon monoxide, carbon dioxide, and other species. Micro-GCs are robust and portable, making them attractive for process gas characterisation, electrolyser diagnostics, and field applications.
Raman spectroscopy Raman spectroscopy analysers use laser excitation to measure vibrational modes of molecules, providing a direct and highly
Table 2. Process variables in alkaline electrolysers, categorised as DVs, CVs, and MVs Category
Variable
Disturbance variables (DVs)
Feed water purity/conductivity
DVs
Ambient temperature
DVs
Electrolyte degradation (KOH drift)
DVs
Membrane ageing/damage*
DVs
Power supply instability
DV
Pressure fluctuations
DV
Air leakage/contaminants
DVs
Electrode fouling/catalyst wear**
Deep reinforcement learning for optimisation
Hydrogen systems require multi‑objective optimisation that balances safety, efficiency, and degradation management under variable renewable inputs. DRL agents excel at such tasks by learning safe operating policies directly from analyser data and digital twin simulations. They adapt in real time, penalise unsafe states and recommend control strategies that extend stack life while improving efficiency. Constraint‑aware DRL ensures limits such as maximum differential pressure or maximum oxygen in hydrogen are never exceeded. The DRL controller benefits from the sensor readings at the system input (power supply and water properties) by leveraging its prognostic control capabilities. It also makes the best use of the sensors deployed on the product streams, effectively dealing with unmeasured disturbances that may cause the process to approach the bounds of safe operation.
Optimising alkaline electrolysers
Stack/cell temperature (60 - 90˚)
Alkaline electrolysers remain cost‑effective and scalable, but are affected by environmental disturbances, electrolyte degradation and membrane wear. Gas crossover leads to hotspots, wasted energy and accelerated catalyst damage. Accurate online analysis of O2 in H2 and H2 in O2 streams provides real‑time signals for immediate correction.
CVs
Electrolyte concentration
Roadmap for progressive deployment
CVs
H2 purity (cathode)
CVs
O2 purity (anode)
CVs
H2/O2 purity
CVs
Δp anode-cathode
CVs
Stack voltage and current density
CVs
Crossover gas concentration
Manipulated variables (MVs)
DC current input
MVs
Electrolyte flow rate
MVs
Cooling water flow
MVs
Stack operating pressure
MVs
Purge gas rate
MVs
Feed water/degrassing
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Controlled variables (CVs)
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selective measurement of hydrogen and its impurities (N2, O2, CO, CO2, CH4, H2O, etc.) in a single spectrum. This makes them uniquely suited for hydrogen purity certification in compliance with ISO 14687 and other standards for fuel-cell grade hydrogen. Raman systems are non-contact, require no consumables, and can operate under high pressure without sample preparation. Limitations include higher capital cost and sensitivity to background fluorescence in some environments, but their capability for real-time, multi-species purity analysis is unmatched.
Deploying analyser‑guided DRL optimisation follows a staged roadmap: y Stage 1 involves a gap assessment against ISO 14687, SAE J2719, ISO 22734, ASME B31.12, and NFPA 2 standards. y Stage 2 defines instrumentation requirements, sampling systems and analyser placement. y Stage 3 builds the historian and data infrastructure to capture high‑frequency analyser signals with health monitoring. y Stage 4 calibrates digital twins with live data, creating a safe environment for testing. y Stage 5 introduces DRL in advisory mode, where it recommends adjustments without closing the loop. y Stage 6 moves to supervisory DRL under PLC guardrails, allowing DRL to adjust setpoints while safety PLCs enforce hard interlocks. y Stage 7 establishes sustainment: analyser maintenance, QA routines and continuous DRL retraining to adapt to changing conditions.
Business case and strategic benefits
Hydrogen is no longer just about feasibility – it is about running plants safely, efficiently, and competitively. This is where advanced analysers and AI-driven optimisation deliver real impact.
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ISO 14687 standards. At the same time, oxygen purity validation enables valorisation of oxygen by-products, which can contribute an additional US$20 - 40/t in revenue streams for industrial or medical markets. Together, these benefits drive improved uptime, lower levelised cost of hydrogen (LCOH) by 5 - 10%, and enhanced operational safety, turning analyser-driven optimisation into a high-return investment rather than a compliance cost.
Bibliography
On Demand Webinars On Demand Webinars Figure 4. Modcon.AI DRL-based closed-loop control for alkaline electrolysers.
1. ISO 14687:2019, ‘Hydrogen fuel quality – Product specification’. 2. SAE J2719:2020, ‘Hydrogen fuel quality for fuel cell vehicles’. 3. ISO 22734:2025, ‘Hydrogen generators using water electrolysis’. 4. ASME B31.12, ‘Hydrogen piping and pipelines. 5. NFPA 2, Hydrogen technologies code.’ 6. Yakhnin, G., Gurina G., Shahnovsky G., ‘Anatomy of the alkaline electrolyser optimization’, (2025) 7. Pasman, H., and Rogers, W., ‘QRA for hydrogen infrastructure. Int. J. Hydrogen Energy’, (2010). 8. GARCÍA, H. et al., ‘Learning‑based optimal operation of power‑to‑hydrogen systems’, (2022 - 2024). 9. DOE/NREL (2024–2025). Hydrogen Shot and electrolysis technology assessments. 10. DOE/NREL (2024–2025). Hydrogen Shot and electrolysis technology assessments. 11. ISO/TR 15916, ‘Basic considerations for the safety of hydrogen systems’.
On Demand Webinars Accurate analysers, when paired with Deep Reinforcement Learning (DRL) optimisation, typically reduce energy consumption by 3 - 5%, directly lowering the electricity cost that accounts for up to 70% of hydrogen production expenses. By preventing hotspots and maintaining optimal current densities, analysers help extend electrolyser stack lifetime by 1 - 2 years, saving up to US$200 000 - 300 000/MW in avoided replacement costs. In large scale installations, this translates to several million dollars in extended asset value and minimised downtime. Continuous hydrogen purity monitoring protects offtake contracts, where penalties for out-of-spec product may exceed US$100 000 per event, while ensuring compliance with
Notes
* Direct, real-time ‘membrane ageing’ sensors do not exist yet. Instead, crossover O2/H2 gas analysers + Electrochemical impedance spectroscopy (EIS) modules are the most practical proxies. ** No single inline ‘fouling sensor’ exists. Instead, increasing overpotential at fixed load and EIS signatures are the accepted proxies. Coupling these with O2/H2 gas analysers for poisons provides better diagnosis.
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Menica Antonelli, Daniela Boni, Salvatore Romagnuolo, and Nicola Tamburriello, KT Tech S.p.A, a NEXTCHEM company (MAIRE group), consider how digitalisation tools can be transformative for hydrogen production in chemical plant operations.
I
n the evolving landscape of the chemical industry, digitalisation is no longer a futuristic concept – it is a present-day imperative. As plants grow in complexity and environmental regulations tighten, the need for intelligent, responsive, and data-driven operations becomes paramount. The integration of
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digital technologies into chemical plant workflows enables a transformative shift from reactive to proactive management, enhancing both operational efficiency and environmental stewardship. Digital process monitors (DPMs) have proved to be an innovative digitalisation tool for hydrogen production units (HPUs). This article presents the architecture, dataflow, and functional capabilities of a Hydrogen Production Unit Digital Process Monitor (HPU DPM) developed by NEXTCHEM, the technology division of the Italian engineering group MAIRE. Designed as an online licensor consultant, it empowers plant operators with real-time insights, predictive analytics, and decision-support tools that are hard to retrieve through traditional distributed control systems (DCS). By creating a digital shadow of the HPU, DPMs continuously validate, reconcile, and analyse
Figure 1. DPM architecture overview.
process data, offering a dynamic interface between field operations and expert knowledge. This article explores how digital tools are redefining the boundaries of what is possible in chemical plant operations. .
DPM architecture overview
DPMs are cloud-based software that bridge real-time plant operations with advanced analytical capabilities to enhance performance and environmental compliance. As illustrated in Figure 1, the HPU DPM interfaces directly with the plant’s DCS via an edge computing device, enabling seamless data acquisition. At the core of the architecture lies the DPM engine, which incorporates a plant model, and sensor data processing. This engine processes incoming data streams to perform both online and offline analyses, supporting immediate operational decisions and deeper diagnostic reviews. The system evaluates key performance indicators (KPIs) such as plant loads and energy consumption, conducts compositional and dew point analyses, and assesses environmental impacts like carbon dioxide (CO 2) emissions and thermal efficiency. Additionally, it monitors equipment conditions – including fouling and catalyst ageing – and duplicates sensor readings to validate data integrity. This framework empowers plant operators and licensors with actionable insights, fostering a proactive approach to process optimisation and sustainability.
The dataflow
Figure 2. DPM dataflow.
Figure 3. Example of sensor duplication.
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The dataflow architecture is designed to ensure high fidelity and actionable insights from plant operations through a structured and secure data management pipeline. As illustrated in Figure 2, the process begins with the acquisition of raw data from the DCS, encompassing a wide array of process variables and instrumentation readings. This data undergoes a rigorous validation phase to exclude outliers and compensate for missing or inconsistent values. The process model, representing a digital shadow of the plant, integrates this data to simulate
specialised equipment, whose performance characteristics and replicate real-time operations with high accuracy. are often opaque to conventional DCSs. By integrating Through data reconciliation, the system harmonises field proprietary process models and reconciled data, it can data to eliminate discrepancies and enhance reliability. detect subtle deviations in behaviour – such as shifts in Once evaluated, the data is stored in a dedicated and reaction efficiency or thermal profiles – that may indicate secured enterprise database. Finally, the processed early signs of degradation or suboptimal operation. information is rendered through a graphical interface, Environmental monitoring and equipment condition offering operators a view of plant performance, including assessment can also be incorporated as core KPIs, environmental metrics, and equipment diagnostics. functionalities of DPMs. Real-time tracking of CO2 This structured dataflow enables robust decision support and continuous performance optimisation. equivalent emissions enables operators to maintain The dashboard is designed to provide operators with a comprehensive and intelligent interface that enhances situational awareness and operational decision-making. One of the core features is the sensors’ duplication module, which ensures data integrity and early anomaly detection. This functionality begins with the duplication and validation of all instrument site data, where each tagged value from the DCS is mirrored within the digital process model. This model acts as a virtual replica of Figure 4. Example of KPI. the plant’s instrumentation, continuously comparing real-time measurements against expected values derived from reconciled data. For instance, if a flow indicator (e.g., FICxx1.pv) deviates significantly from its modelled counterpart (e.g., FICxx1out), the system flags this discrepancy as a potential issue requiring operator attention. This approach enhances the reliability of the data used for process control and enables predictive diagnostics by identifying sensor drift, calibration errors, or emerging equipment faults before they escalate. The dashboard also offers real-time performance indicators that extend beyond the scope of traditional DCSs. It can provide KPIs and soft calculations (derived metrics that are not directly measured but are critical for operational insight). These KPIs include parameters such as unit efficiency, energy consumption, and environmental impact, all of which are continuously updated and visualised through the dashboard. For example, the system can display unit efficiency both with and without steam credit, which are essential for evaluating thermal performance and optimising energy integration strategies. Moreover, the DPM is designed with a high degree of configurability, allowing operators and engineers to tailor the dashboard to specific plant needs or operational goals. This flexibility ensures that the system remains aligned with evolving performance targets and regulatory requirements, making it a dynamic tool for continuous Figure 5. Analysis and equipment status. improvement in plant operations. The dashboard also delivers advanced analytical insights that significantly enhance operational visibility and decision-making. The system is able to perform in-depth analysis of critical process units, Figure 6. Real-time tracking of feedstocks and hydrogen. particularly reactors and
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compliance with environmental regulations while also identifying opportunities for emissions reduction. Simultaneously, it is possible to evaluate the health of key assets, such as heat exchangers, by monitoring indicators like fouling trends and catalyst ageing. These insights are visualised through intuitive dashboards that include metrics such as the ‘reformer steam carbon ratio’ and ‘PSA recovery,’ offering a holistic view of both process efficiency and environmental impact.
Validation
The validation of the HPU DPM was rigorously carried out through its implementation in a medium to large scale industrial facility in Europe, selected for its operational complexity and diversity. This plant processes a wide range of feedstocks – including natural gas, naphtha, LPG and continuous catalyst regeneration (CCR) off-gas – and operates with two distinct steam generation systems. Such a multifaceted environment provided an ideal testbed to assess the adaptability and reliability of the DPM system. The system continuously tracked and analysed performance indicators for each feedstock stream over time, with the HPU DPM values reflecting quasi-dynamic operational conditions. The resulting data trends confirmed the system’s ability to detect and respond to process variations with high fidelity. This real-world deployment, while validating the DPM’s digital modelling and data reconciliation capabilities, also demonstrated its effectiveness in supporting operational
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decision-making across a broad spectrum of chemical processing scenarios.
Conclusion
DPMs represent a significant advancement in the digitalisation of plant operations, offering comprehensive and intelligent platforms for real-time monitoring, diagnostics, and optimisation. By integrating directly with the plant’s DCS, DPMs create a digital shadow of the HPU, enabling continuous validation and reconciliation of sensor data. This ensures high data fidelity and early detection of anomalies through sensor duplication and deviation tracking. Dashboards can extend beyond traditional control systems by providing soft-calculated KPIs and customisable metrics tailored to specific operational goals. Moreover, DPMs can deliver advanced analytics on reactor performance and specialised equipment, offering insights that are difficult to access through standard instrumentation. Environmental monitoring is seamlessly embedded, allowing for real-time tracking of CO 2 emissions and equipment health indicators. These capabilities are visualised through intuitive dashboards that support proactive decision-making and sustainability compliance. HPU DPM exemplifies how digital innovation can transform process industries by enhancing operational transparency, environmental responsibility, and long-term plant performance.
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