Hydrogen leaks and flames can be difficult to detect without the right technology. MSA’s advanced fire and gas detection systems can help mitigate risks and support a safer workplace. Explore Hydrogen Detection Solutions at msasafety.com/hydrogen-detection-solutions
The road ahead for Canada
Arvind Ramakrishnan and Karen Hamberg, Deloitte Canada, explore the future of the heavy duty hydrogen transport industry, considering current market uncertainty and growing momentum across Canada.
08 A cost-effective path to decarbonised (blue) hydrogen
Justin Schaeffer, Shell Catalysts & Technologies, discusses how a new selective carbon monoxide oxidation technology is transforming the Shell Blue Hydrogen Process.
13 Speeding up hydrogen adoption
Adam Kadhim, Topsoe, examines some key technological advances speeding up the adoption of low-carbon hydrogen and facilitating its global transport.
17 The future potential of green hydrogen
Nora Han, ABB, Switzerland, explores how greater efficiency in the production of green hydrogen can enable market expansion.
21 Energy transition challenges
Alberto Litta Modignani, NextChem Tech, Italy, examines how green hydrogen and the electrolysis industry are being reshaped by energy transition challenges.
25 Innovation and collaboration
Chris Gill, Worley, considers how innovation and collaboration within the hydrogen supply chain can help bring down the cost of green hydrogen production, with particular focus on electrolysers and plant infrastructure.
27 The future is electrifying
Tina Andersen, Hystar, discusses how PEM electrolyser technology can enhance safety and efficiency.
30 Efficiency solutions
Larry Emch, Integrated Global Services (IGS), USA, explores technological advancements to increase efficiency and reduce CO2 emissions in steam methane reformers.
37 Advancements in burner technology
Eric Pratchard and Todd Grubb, Zeeco, Inc., USA, alongside Hector Ayala, Aloke Sarkar, and HS Lee, ExxonMobil Technology and Engineering Company, USA, consider the impact that advancements in ultra-low NOX burner technology could have on hydrogen firing and NOX emissions.
43 Digital technology and the future of clean energy
Nico Schmaeling, John Crane, Germany, examines how digitalisation can aid the wider adoption of hydrogen energy, through improved efficiency and profitability.
47 Transforming operational technology
Marcel Kelder, Yokogawa Europe, considers how business models in the operational technology (OT) domain can adapt operations to ensure security and productivity through technological advancements, such as edge machines.
51 The ace up hydrogen’s sleeve
Danny Nicholas, Rotork, UK, examines how electrification, digitalisation, and automation can make clean hydrogen commercially viable.
55 Investing for the future
Chuck Hayes, Swagelok Company, USA, explains how using high-quality valves within hydrogen systems preserves and augments system performance and longevity.
59 Valves for industrial hydrogen
Sanket Walimbe, Trillium Flow Technologies, considers the importance of valves for safety and reliability in industrial hydrogen applications.
63 Fuel cells for heavy duty applications
Dr Michael George and Dr Christian Gebauer, Heraeus Precious Metals, consider the role hydrogen fuel cells could play in the development of heavy duty vehicle materials.
69 Decarbonising shipping
Janna Chernetz, Amogy, explores how ammonia-cracking technology has made ammonia a viable, versatile, safe, and scalable source of power for marine transport.
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The sky’s the limit for hydrogen production. Or perhaps its potential extends well beyond even that. Honda R&D Co. Ltd recently announced plans to test its high-differential pressure water electrolysis system at the International Space Station (ISS). In collaboration with Sierra Space and Tec-Masters, this project forms part of Honda’s vision for a regenerative fuel cell system that could provide advanced energy storage that is capable of supporting human life on the lunar surface.
Honda is using its hydrogen fuel cell technology expertise to develop a circulative renewable energy system that will continuously produce oxygen, hydrogen, and electricity. During the lunar day, the system will use electricity generated by the sun to power the process. Honda’s high-differential pressure water electrolysis system will then produce hydrogen and oxygen from water. During the lunar night, some of the oxygen will be used for astronauts to breathe, while the remaining oxygen, along with the hydrogen produced during the day, will be used to generate electricity. After electricity is generated, the water that is produced as a byproduct will be recycled back into the water electrolysis system to create a closed-loop energy cycle.
Honda is now set to test the core part of its system to verify its efficiency and reliability in the microgravity environment of the ISS.
Back in the ‘normal gravity’ environment of planet Earth, the Global Hydrogen Review team had the pleasure of learning about – and meeting the teams behind –a wide array of other, equally innovative, hydrogen technologies at the recent World Hydrogen Summit & Exhibition in Rotterdam, the Netherlands. It was great to reconnect with some familiar faces and meet a wide range of new companies driving progress in the global hydrogen economy. Next up, we’ll be exhibiting at the Hydrogen Tech Expo North America in Houston, Texas (stand 1070) amidst a more uncertain environment for clean energy in the US. Donald Trump’s flagship tax and spending legislation plans to cut tax credits for the sector, including the termination of the 45V hydrogen production tax credit. If 45V is terminated, Wood Mackenzie estimates that 95% of the 3.4 million tpy of green hydrogen capacity announced in the US would be at risk. Hector Areola, Principal Analyst, Wood Mackenzie, said: “Developers [would] face a critical decision: either accelerate their projects to meet the new deadline or risk losing the tax credit entirely. The ongoing regulatory uncertainty threatens to stagnate the low-carbon hydrogen industry in the US and could potentially alter the landscape for clean hydrogen globally.” ¹
The sheer volume of exhibitors and delegates at trade shows such as the World Hydrogen Summit and Hydrogen Tech Expo North America is testament to the vital role that hydrogen has to play in helping the world to meet its decarbonisation goals. It also serves as clear evidence of strong support for the sector from industry. This needs to be matched by governments the world over to ensure that the sector can fulfil its enormous potential. As Honda is proving, if we shoot for the stars, we might just land on the Moon.
Arvind Ramakrishnan and Karen Hamberg, Deloitte Canada, explore the future of the heavy duty hydrogen transport industry, considering current market uncertainty and growing momentum across Canada.
This article provides a comprehensive overview of the current state and future potential of hydrogen technology in transforming the transportation sector of Canada, and the ambitious policies and strategies adopted to integrate hydrogen as a key component of net zero emissions goals by 2050. The article highlights the progress made, challenges faced, and innovative solutions being implemented, such as large scale pilot programmes and strategic partnerships.
Ambitious policy underpinned by a comprehensive hydrogen strategy
Since the publication of the Hydrogen Strategy for Canada by Natural Resources Canada (NRCan) in 2020,1 progress has been made in advancing a hydrogen economy. The strategy serves as a framework to capitalise on the economic, environmental, energy security, and export opportunities of low-carbon hydrogen.
Complementary provincial strategies have been developed by British Columbia, Alberta, Ontario, Quebec, New Brunswick, Newfoundland and Labrador, and Nova Scotia, each contributing to the national effort. NRCan’s May 2024 Progress Report2 highlights hydrogen hubs and corridor infrastructure as key priorities. With 18 support programmes, Canada is advancing hydrogen technology and establishing a refuelling network, alongside trials for heavy duty truck operability and the broader ecosystem.
Transportation emissions account for approximately 25% of total greenhouse gas (GHG) emissions in Canada,3 underscoring
the importance of decarbonising this sector to meet sustainability goals. Canada’s strategy emphasises leveraging low-carbon hydrogen to meet sustainability targets while fostering economic growth, supported by initiatives like the Clean Hydrogen Investment Tax Credit and Clean Fuel Regulations. Canada could potentially use between 1.7 - 6 million t of hydrogen in the transport sector by 2050,2 accounting for 12 - 35% of the sector’s energy use. This widely reflects the future potential of hydrogen in medium and heavy freight transport, as well as in marine, rail, and possibly aviation fuels, where hydrogen could potentially be used as a feedstock to develop synthetic fuels, as batteries would be too large, heavy, and time-consuming to charge.
Key initiatives transforming heavy duty transport in Canada
� Edmonton Global’s 5000 Hydrogen Vehicle Challenge: aims to drive the adoption of hydrogen across public and private sector fleets. Work is underway to advance the greater use of hydrogen in Western Canada through a consortium approach to a large scale pilot of Class 7 and 8 vehicles across priority corridors.
� Transport Canada’s Zero Emission Truck Testbed (ZETT): led by the Alberta Motor Transport Association and Deloitte Canada, this pilot involves three Class 8 heavy duty fuel cell trucks and one Class 8 heavy duty battery electric vehicle on distinct routes in Alberta and British Columbia.
� HTEC’s H2 Gateway: developing hydrogen supply and demand through a regional, ecosystem-based approach. Supported by a CAN$337 million loan from the Canada Infrastructure Bank, HTEC is building a liquefaction facility in North Vancouver and three hydrogen production facilities in Burnaby, Nanaimo, and Prince George in British Columbia, along with up to 20 refuelling stations.
� Trans-Québec 1 Project: a network of seven hydrogen refuelling stations enabling interregional transport across Quebec, covering nearly 97% of the Quebec population.
One of the most ambitious initiatives is Canada’s HTEC H2 Gateway programme to develop hydrogen production, distribution, fuelling infrastructure, and zero-emission trucking concurrently. This comprehensive approach aims to overcome adoption challenges by integrating all components simultaneously, mitigating the ‘chicken and egg’ problem. The HTEC H2 Gateway programme, with a total cost of CAN$900 million, is funded by the Canada Infrastructure Bank, British Columbia’s Low Carbon Fuel Standard Credits, private-sector contributions, and government grants to deploy 100 hydrogen fuel cell electric trucks and 20 refuelling stations in Metro Vancouver and other connecting regional corridors.
Bumps in the road
Hydrogen technology has the potential to transform transportation, especially for high payloads and extended ranges, but faces adoption challenges. The high costs of hydrogen-powered trucks (approximately three times that of comparable diesel models today), alongside the lack of transparency on the delivered cost of hydrogen depending on production methods and distribution distance, complicate economic feasibility. Sparse refuelling infrastructure and limited original equipment manufacturer (OEM) availability add to deployment challenges and scalability. Production delays in components like electrolysers and lengthy regulatory permitting processes further hinder adoption.
Recent global market uncertainty has also contributed to financial challenges within the industry, impacting both hydrogen and battery electric vehicles. Several companies in the hydrogen fuel cell and electric vehicle sectors, along with various electric vehicle start-ups, have filed for bankruptcy or sought creditor protection. Trucking companies are navigating trade tensions and economic uncertainty by prioritising immediate operational concerns over long-term sustainability goals. In this environment, they are seeking practical applications of technologies that do not disrupt current operations and make economic sense with the ecosystem support.
The potential for pilots at scale
The widespread deployment of hydrogen in heavy duty applications requires substantial investment in vehicles and fuel production, coordinated infrastructure and ecosystem development, and commercially viable operating models. Large pilots have been established in North America, Europe, and Asia to test the introduction and integration of hydrogen into real-world fleet operations. These initiatives rely on strategic partnerships between truck manufacturers, fuel producers, fleet operators, and government agencies to ensure that vehicles, refuelling stations, and supply chains are tested and set up to develop in parallel.
A pilot at scale tests the complexities of heavy duty trucking on priority corridors by deploying hydrogen trucks in significant numbers. This approach aims to drive fleet purchase commitments, accelerate fuelling infrastructure development, and engage the value chain to advance zero-emission vehicle deployment. By fostering momentum and information sharing, such pilots catalyse commitments from partners to establish hydrogen fuelling networks and strengthen the foundation for hydrogen vehicle
commercialisation. They promote cross-functional collaboration and data-sharing on vehicle and system performance.
Path forward
Despite current market uncertainties, the hydrogen mobility sector presents emission reduction opportunities that require a collaborative approach to ensure affordability, reliability, energy security, and sustainability benefits. Current pilots and at scale projects highlight important strategies to maintain momentum:
� Integrated infrastructure development: an integrated approach to infrastructure involves the synchronised development of production, distribution, and refuelling stations alongside vehicle deployment. An emphasis on regional clusters and hub-and-spoke models can optimise station utilisation and ensure that infrastructure scales with demand, mitigating the ‘chicken and egg’ problem.
� Innovative financial models: leasing models and pay-per-kilometre systems can reduce upfront costs for fleet operators, improving the financial viability of hydrogen trucking. These innovative models align costs with operational expenses, reducing financial risks for early adopters.
� Government incentives and regulatory support: stable and sustained government incentives are essential to bridge the economic gap between hydrogen and diesel operations. Financial incentives to de-risk the cost of fuel and/or the cost of the vehicle must be coupled with streamlined regulatory processes to facilitate vehicle approvals and ensure long-term policy stability.
� Operational efficiency: optimising refuelling station design and enhancing vehicle manufacturing capabilities can alleviate supply chain constraints. Encouraging investment in vehicle production is likely to help overcome the current bottleneck in hydrogen truck supply.
� Targeted early-adopter engagement: identifying and engaging fleet operators with strong decarbonisation commitments can drive early adoption. Focusing on operators with return-to-base logistics simplifies refuelling and ensures consistent demand.
� Stakeholder collaboration: continuous collaboration among stakeholders across the value chain is vital. Additionally, stakeholder collaboration should extend beyond fleet operators, vehicle manufacturers, fuel suppliers, and policymakers to include first and second responders, insurance providers, and local government officials with responsibility for permitting.
Both the public and private sectors have a role to play in advancing the transition. By implementing these strategies, regions can develop robust inter-regional corridors and transport hubs, supporting economic growth while transitioning to sustainable, zero-emission long-haul transport.
References
1. ‘Hydrogen Strategy for Canada’, Government of Canada, (December 2020). https://natural-resources.canada.ca/sites/nrcan/ files/environment/hydrogen/NRCan_Hydrogen%20Strategy%20 for%20Canada%20Dec%2015%202200%20clean_low_accessible.pdf
2. ‘Hydrogen Strategy for Canada: Progress Report’, Government of Canada, (May 2024). https://natural-resources.canada.ca/energysources/clean-fuels/hydrogen-strategy/hydrogen-strategy-canadaprogress-report
3. ‘Greenhouse Gas Emissions’, Environment and Climate Change Canada, (March 2025), https://www.canada.ca/content/dam/eccc/ documents/pdf/cesindicators/ghg-emissions/2025/greenhouse-gasemissions-en.pdf
Justin Schaeffer, Shell Catalysts & Technologies, discusses how a new selective carbon monoxide oxidation technology is transforming the Shell Blue Hydrogen Process.
Hydrogen has a vital role to play in the transition to a lower-carbon energy system. While renewable (green) hydrogen is the long-term goal, it will take time for costs to fall and supply to scale. In the meantime, decarbonised (blue) hydrogen offers a lower-carbon alternative to conventional production – one that can be deployed at scale using proven technologies.
The partial oxidation (POx)-based Shell Blue Hydrogen Process (SBHP) offers a scalable, cost-efficient solution for producing decarbonised hydrogen from a variety of gaseous hydrocarbon feedstocks. It can adapt to different applications, ensuring an optimal fit for industries ranging from power generation to ammonia production.
The POx-based technology can deliver low carbon intensity (CI) at minimal cost. Leveraging advanced engineering and operational expertise, it can meet stringent CI targets while enabling further reductions to align with evolving sustainability goals.
It can also be tailored to meet specific hydrogen production needs, including firing-grade hydrogen for power generation and heating, industrial-grade hydrogen for manufacturing processes, and high-purity hydrogen for applications such as
ammonia (NH3) production. Each configuration is optimised for efficiency and cost-effectiveness.
Selective carbon monoxide oxidation (SCO) can also be integrated as a flexible add-on. A single SCO reactor can boost the overall carbon capture rate (CCR) to nearly 99%, helping projects meet regulatory standards and qualify for financial incentives in jurisdictions that reward lower-carbon hydrogen production.
SBHP with SCO offers a cost-effective solution, with 0.5% lower capital expenditure (CAPEX) compared with methanation, a 1.5% reduction in levelised cost of hydrogen (LCOH) vs methanation, and up to 10% LCOH reduction if pressure swing adsorption (PSA) is eliminated, offering a future-proof solution for decarbonised hydrogen production.
The SCO solution is a result of a strategic collaboration between Shell Catalysts & Technologies and BASF, which combines Shell’s process design expertise with BASF’s catalytic innovation and emissions-reduction technologies. Originally developed for the urea industry, BASF’s SCO solution PurivateTM Select has been redesigned for low-carbon hydrogen and ammonia (NH3) production, offering an efficient, high-purity, low-carbon alternative. By integrating BASF’s technology, SBHP users can achieve optimised hydrogen production, qualify for significant
financial incentives, and support ambitious decarbonisation goals without sacrificing operational efficiency.
Scalable technology
The technology provides an end-to-end solution for converting feedstocks into hydrogen (H2) and carbon dioxide (CO2) with a focus on low CI and low cost. Incorporating Shell’s proprietary technologies, including its gas partial oxidation (SGP) and the ADIP1 ULTRA CO2 capture system, it has a proven track record of reliable performance at industrial scales. It can achieve production capacities ranging from 100 tpd to more than 1200 tpd for a single train, or higher for multiple train configurations. This robust, scalable solution is ready for global deployment in decarbonised hydrogen initiatives.
The POx technology can deliver high CCR at a lower cost, resulting in a substantially reduced LCOH. With a track record in large scale projects like the Pearl GTL plant, Shell’s expertise ensures efficient start up and operation, and long-term reliability. The process achieves approximately 99% CO2 capture while maintaining low CI without requiring costly membranes or complex recycles. The non-catalytic oxidation process enhances plant availability by reducing downtime and simplifying operations.
Virtually no direct CO2 emissions are produced by this technology, while its high-pressure hydrogen output reduces energy and compression costs. The ADIP ULTRA system further improves CO2 handling by capturing it at high pressure, minimising compressor size, and regenerating a significant portion of the gas at medium pressure.
Additionally, POx technology maximises energy efficiency through an optimised steam balance, integrating a syngas effluent cooler and a synloop process to recover reaction heat.
Routes to market and value propositions
The technology can produce three distinct grades of hydrogen, each designed to meet specific requirements for various applications (Figure 1). These grades – firing grade, industrial grade, and high-purity hydrogen – cater to diverse industry needs, thereby providing scalable and flexible solutions for decarbonised energy and feedstock supply.
The technology’s flexibility enhances hydrogen production for different grades, to provide industries with a scalable and cost-effective path to decarbonisation. By tailoring configurations, it can reduce CI to meet regulatory and operational needs while supporting global climate goals.
For firing-grade hydrogen, used in low-carbon power generation or industrial heating, the high conversion efficiency of the SGP reactor produces syngas that can be converted into hydrogen that meets purity standards without requiring additional purification. This eliminates hydrogen loss from processes like methanation and PSA, thereby reducing costs and avoiding complex purification equipment.
For industrial-grade hydrogen, methanation is used to achieve more than 98% purity with minimal Scope 1 emissions. The ADIP ULTRA CO2 removal system captures most of the carbon, and methane and CO enhance the hydrogen’s energy content, which makes it a cost-effective, low-carbon solution with high carbon capture, without the need for complex equipment.
For high-purity hydrogen (> 99.9% purity), SBHP with low methane slip enables efficient PSA operations, maximising hydrogen recovery and minimising off-gas production. This approach reduces CI and PSA boiler size, thereby further lowering costs.
Decarbonised (blue) ammonia production
Shell Catalysts & Technologies offers fully integrated solutions for decarbonised ammonia production, and collaborates with third-party NH3-synthesis technologies to facilitate the transition to a low-carbon economy (Figure 2). Several synergies between the POx-based process and NH3 synthesis help reduce costs
and emissions. A high-pressure POx reactor utilises pipeline gas to deliver high-pressure hydrogen, which lowers compression costs for NH3 production, typically above 150 bar. Additionally, the oxygen-based system produces nitrogen as a by-product, which is ideal for NH3 synthesis. The high conversion efficiency of the POx reactor also minimises methane slip, thereby reducing off-gas and lowering the CI in both hydrogen and NH3 production.
Enhance CCR
In response to financial and regulatory incentives, hydrogen producers are continually seeking ways to enhance production efficiency. The SCO technology optimises yields, reduces emissions, and improves performance to meet evolving industry demands. It is a versatile solution that reduces CI across all hydrogen grades: firing grade, industrial grade, and high purity. SCO can be integrated into existing SBHP setups, including methanation or PSA configurations, or used independently to further reduce CI (Figure 3). A single SCO reactor can significantly improve carbon capture, making hydrogen production more efficient and cost-effective.
SCO technology effectively targets CO in hydrogen-rich streams from water-gas shift (WGS) units, and selectively oxidises it. Proven in the urea industry, SCO is now being adapted for emerging sectors such as decarbonised hydrogen and ammonia, with BASF as a key technology partner to optimise hydrogen production and CO conversion.
Figure 1. Tailored H2 grades for diverse applications.
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SCO enhances carbon capture and achieves the highest hydrogen yield of any purification method, thereby significantly improving process efficiency. By increasing hydrogen yield, it reduces natural gas consumption and feedstock-related emissions, which makes it a powerful tool for decarbonising hydrogen production.
Integration benefits
The new SCO line-up brings significant advantages to hydrogen production, offering a highly efficient solution for optimising performance and meeting stringent environmental requirements. By converting CO to CO2 for easier downstream removal, it boosts overall carbon capture to approximately 99% and enhances hydrogen purity without the trade-offs typically seen in traditional methanation or PSA processes.
With its ability to minimise emissions of CO, CO2, and methane, the SCO line-up helps ensure compliance with tightening regulatory standards. Additionally, it supports higher hydrogen yields while reducing operational costs compared with conventional methods. Its adaptable reactor setups allow integration into various projects, to align with specific operational goals and ensure long-term efficiency.
Case study: hydrogen hub network with 98.5% purity requirement
A hydrogen hub is being developed in an industrial cluster, with multiple facilities requiring hydrogen at 98.5% purity. The cluster focuses on decarbonisation and fuel switching to meet strict environmental regulations and reduce emissions. Initially considering SBHP with methanation, the cluster chose a single SCO
reactor instead, as the region offers financial incentives for higher carbon capture and lower CI.
The SCO configuration increased hydrogen purity to 99%, surpassed carbon capture targets with a 99% rate, and boosted hydrogen yield by 1.5% compared with methanation, and 10% over PSA. It reduced CI by 10% and lowered the LCOH by 1.5% vs methanation, and 10% without PSA, which improved both environmental and economic performance.
Compared with methanation and PSA, integrating an SCO reactor improves hydrogen purity, reduces the carbon footprint, and increases yield while delivering long-term cost savings. It enhances CCR and lowers CI, thereby making the process more efficient and sustainable. In high-purity applications, it also reduces costs and offers an efficient, scalable, and environmentally friendly solution for decarbonised hydrogen production.
Conclusion
Integrating SCO technology with the SBHP enhances decarbonised hydrogen projects by boosting carbon capture to nearly 99%, maximising hydrogen yields by minimising consumption, and maintaining high purity without extensive purification. This makes it a cost-effective solution for projects prioritising low CI.
Looking ahead, SCO is well positioned for widespread adoption in hydrogen and NH3 production, driven by increasing regulatory pressures and the growing demand for low-carbon solutions. Its integration with the SBHP, low CAPEX, and high efficiency ensure a sustainable and cost-effective hydrogen production process.
Note
1. ADIP is a Shell trademark.
Figure 3. Configuration with integrated SCO reactor.
Figure 2. Configuration for NH3 production.
Adam Kadhim, Topsoe, examines some key technological advances speeding up the adoption of low-carbon hydrogen and facilitating its global transport.
The hydrogen market is experiencing a transformative phase, driven by advancements in technology, regional demand variations, and the need for efficient transportation methods.
According to the International Energy Agency’s (IEA) ‘Global Hydrogen Review 2024,’ global hydrogen demand surpassed 97 million t in 2023 and is projected to approach 100 million t in 2024.¹ While demand for low-emissions hydrogen increased by nearly 10% in 2023, it remains below
1 million t. Governments have recently stepped up efforts by introducing mandates, incentive programmes, and market development strategies, which could drive demand beyond 6 million tpy by 2030. This expanding market is driven by several countries setting goals for reducing emissions, which they hope to reach partially through the adoption of low-carbon (blue) hydrogen.
When it comes to production, regions like the US and the Middle East have an advantage in producing low-carbon
hydrogen due to their geographic benefits, including affordable natural gas and well-developed carbon capture and underground sequestration (CCUS) infrastructure. On the demand side, regions like Europe and parts of Asia (Japan, South Korea) are expected to become major net importers of low-carbon hydrogen as they focus on enhancing energy resilience.
This growth market creates a significant opportunity for producers looking to scale up low-carbon hydrogen. However, success depends on several key factors: cost efficiency, operational optimisation, achieving the lowest levelised cost of hydrogen (LCOH), and ensuring reliable transportation to target markets. To help the industry navigate this growth phase, a range of solutions are available, including Topsoe’s advanced autothermal reforming (ATR) technology, SynCORTM (Figure 1).
Autothermal reforming (ATR) technology
Hydrogen production at large and mega scale can be made more efficient through the ATR production process, rather than the traditional and currently dominant steam methane reforming (SMR). The SynCOR ATR process, for example, has a lower steam-to-carbon (S/C) ratio of 0.6, which is three to five times less than conventional steam methane reformers (SMR). This reduction in steam demand leads to
smaller equipment sizes and lower costs, which results in a low LCOH.
SynCOR operates within a single reactor where process gas combines with oxygen and additional steam, undergoing a combination of oxygen combustion and steam reforming simultaneously. This process reduces Scope 1 carbon emissions by over 99% with only pre-combustion carbon capture, making the technology highly suitable for low carbon intensity (CI) hydrogen production and deployment in mega scale plants.
The technology has been continuously developed and optimised for 70 years. The first-generation SynCOR, originally known as ATR, was introduced by Topsoe in 1958. A second-generation version of the technology has been deployed in numerous large scale plants for various applications, including gas-to-liquid (GTL), natural gas to gasoline (TIGASTM), and syngas production.
The largest operational SynCOR reactor to date produces 510 kNm3/hr of hydrogen, with a single-train capacity limit of 825 kNm3/hr. Its hydrogen production process requires minimal external fuel due to low firing duty, resulting in high carbon recovery.
Electrified steam methane reforming
One approach to syngas production is via an electrified SMR process. Unlike conventional SMR, which relies on natural gas for both feedstock and heat, electrified SMR works as an integrated system where heating is achieved through direct electrical resistance heating of the catalyst. This eliminates flue gas emissions and reduces overall feedstock consumption, significantly lowering emissions. Topsoe’s eREACTTM (Figure 2) enables a 30 - 40% reduction in natural gas consumption for hydrogen production compared to traditional SMR.
As the steam reforming reactions take place within a catalytic reactor heated by power, preferably from renewable sources, the need for hydrocarbon fuel as a heat source is eliminated, avoiding flue gas emissions from the reformer. The energy density of the process allows for a significantly smaller reactor size compared to traditional SMR units. The process is mostly targeted towards low and moderate low-carbon hydrogen production at sites where adequate renewable power is available.
Almost all of the CO2 formed in an eREACT-based process can be economically recovered using a CO2 removal unit. More than 99% of the CO2 can be captured, making it an excellent choice for low-carbon hydrogen production in scenarios where electricity prices are favourable. This process enables the production of low-carbon hydrogen, green methanol, and high-efficiency sustainable aviation fuel (SAF) from CO2
Carbon capture and storage
Efficient carbon capture is crucial for achieving low-carbon hydrogen production. Intergrating leading carbon capture solutions, such as solvent-based
Figure 1. Autothermal reforming (ATR) section.
Figure 2. Electrified steam methane reforming.
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removal and cryogenic CO 2 capture process, with the production process is crucial. Topsoe offers customers solutions that combine hydrogen production and carbon capture in a single facility under a unified technology licence.
Ammonia cracking
Another tangential but important technology facilitating the growth in hydrogen is ammonia cracking. Transporting hydrogen globally is essential to meet regional demand variations and to supply growing markets. Regions with high energy demand, such as Europe, Japan, and South Korea, may not have sufficient local hydrogen production capabilities, while other regions, like the US and the Middle East, have cheaper or more reliable feedstock. Ammonia cracking offers a solution to this challenge. Ammonia has a higher energy density compared to hydrogen gas, allowing larger amounts of energy to be stored and transported in the form of ammonia. Using hydrogen-derivative ammonia as a carrier enables end-point users to take advantage of cheaper, or more readily available, feedstocks and production processes elsewhere on the globe. Ammonia’s ability to be liquefied allows it to be transported at a lower cost than hydrogen. At the destination, the stored ammonia is converted back to hydrogen through ammonia cracking. Developed back in 1978, Topsoe’s H2RetakeTM ammonia cracking technology is de-risked and ready for scale-up (Figure 3).
Addressing challenges and taking opportunities
The expanding market for CI hydrogen and ammonia presents significant opportunities for those entering or expanding into the space. Companies that invest in these technologies can now position themselves at the forefront of this growth, capturing market share as industries increasingly adopt low-CI alternatives for energy and industrial applications.
Reference
1. ‘Global Hydrogen Review 2024’, International Energy Agency, https://www.iea.org/reports/global-hydrogen-review-2024/ hydrogen-production
Figure 3. Topsoe ammonia cracking facility in Arroyito, Argentina, with a capacity of up to 24 000 tpd.
As the world transitions away from fossil fuels, there is an increasing focus on adopting new methods of power generation that offer long-term solutions to meet the challenges of net zero. Experts, businesses, and governments have all put such hopes, and large sums of money, into hydrogen.
Green hydrogen currently makes up a fraction of the wider clean hydrogen market, with blue hydrogen’s longer history of use making it the more popular form in many markets. While blue hydrogen is the dominant product in various countries, green hydrogen has been the focus of much excitement, having been touted to match or even overtake blue hydrogen. Green hydrogen is now the main focus for the
Nora Han, ABB, Switzerland, explores how greater efficiency in the production of green hydrogen can enable market expansion.
majority of governments exploring new hydrogen-based energy production. However, this hinges on it becoming more cost-efficient.
A new market
Green hydrogen production is distinct from conventional fossil fuel-based hydrogen production in both market dynamics and production methods. The chemical, oil, and gas resources needed for fossil fuel-based hydrogen have specific supply chains, established players, and sit within an organised market structure.
In contrast, the green hydrogen market is unconventional in its structure and behaviour. It is a crowded and diverse landscape with many industries represented, and it depends heavily on government subsidies. These subsidies are mostly focused on investing in greenfield projects and emerging technology. The limited market development means there is plenty of room for growth.
The green hydrogen market has vast potential but is currently constrained by high production costs and technological limitations. While some hydrogen technologies have reached industrial maturity, the capacity of electrolysers remains insufficient to meet the growing demand of the green hydrogen market. For instance, alkaline and proton exchange membrane (PEM) electrolysis technologies, though commercially available, have not been installed beyond the 20 - 200 MW range. As a result, larger scale applications have been left unexplored. Such limited development provides significant opportunities for innovation, as well as challenges for the scaling up of production. The industry lacks an established pathway for maximising efficiency in establishing a green hydrogen production process at scale, and so addressing these issues is crucial before significant market expansion can occur.
Efficiency: more than a money saver
The financial benefits of energy efficiency in the production of green hydrogen are undeniable. In the lifecycle of a hydrogen plant, up to 80% of the final cost is attributed to its electricity consumption, influencing not
only production and operating costs, but also the ultimate cost of hydrogen for the end user. Improving efficiency by just 1 - 2% can save hundreds of millions, demonstrating a clear financial incentive to accelerate efficiency gains.
Increased efficiency gains across the whole lifecycle of a green hydrogen rectifier can reduce the high costs of production associated with green hydrogen, while also greatly reducing the associated carbon emissions. In the midst of the current climate discussions, sustainable energy provision is a significant imperative and the longevity of the components used in industry technologies is a key part of this.
ABB calculations have shown that if the world were to save just 2% of its current energy output in electricity production every year, by 2030 enough energy would have been saved to have powered the entire US for the whole of 2022.
It is clear that improving energy efficiency must be moved higher up the agenda in the conversations on global decarbonisation as it offers a significant impact.
What is it going to take?
ABB Motion has been developing the use of collaborative techniques and integration of multiple technologies to reduce energy costs. Thyristors can be used as one of the primary instruments in green hydrogen production. These instruments can also be used in conjunction with other systems, such as insulated-gate bipolar transistors (IGBTs), which actively compensate for the reactive power costs.
Optimising the design of the electrical power supply for green hydrogen production starts by defining key performance indicators (KPIs) such as footprint, power quality, energy efficiency, and product cost. These KPIs allow the use of benchmarking technologies suitable for the power stage, such as IGBTs, thyristor, and diodes.
It is rare that one solution fits all. An optimal approach requires the dissection of the (V, I) plane in multiple power segments and seeks the most suitable power semiconductor technology, power converter topology, and even cooling method for each segment separately. This will enable designs that maximise performance for the selected KPIs.
In the next stage, the complete power supply package is shaped, from the MVAC grid down to the electrolyser. This package typically includes the MV-to-LV transformer that provides AC power to the rectifier, a switchgear to protect the LV equipment, and the power rectifier itself. The electrical components are arranged on a skid, a type of mechanical support substrate, while cabling and power connectors are also part of the package.
The power supply package is the building block of the electrical system that powers the network of the hydrogen plant’s electrolysers. The number of power supplies and electrolysers depends on the total power input to the plant, which can range anywhere from a few MW up to hundreds of MW. A plant consisting of many electrolysers gives
Figure 1. ABB Motion’s power supply selection is guided by a comprehensive analysis of voltage, current, and operational variables.
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The cost of producing green hydrogen is high. Stakeholders are still not yet fully committed to its development despite its promise; however, its role in the global energy transition is undeniable. Green hydrogen is not just another alternative energy source, it can enable deep decarbonisation with applications that extend far beyond the power sector. From heavy industry to long-haul transportation, green hydrogen has the potential to transform entire economies – replacing fossil fuels in sectors where electrification alone is simply not a viable solution. If scaled effectively, it could provide a clean, long-term energy source that complements wind, solar, and other renewable technologies, creating a more resilient and diversified energy system.
higher degrees of freedom to optimise the overall power quality and efficiency.
Optimising for power quality can be done on a unit level at each power supply separately, at the point of common coupling, or at a combination of these options. The objective here is to minimise harmonics on the power grid side and compensate for reactive power.
Maximising the performance of the hydrogen plant can be achieved through the smart control of the power semiconductor switches of each rectifier. The objective is to minimise losses by optimising the behaviour of the electrolyser down to the millisecond. Efficiency can be further optimised by adjusting the operating profile of the electrolyser to voltage and current requirements related to the beginning and end of the product’s lifetime. The result is a thorough use of the electrolyser’s hydrogen-producing capabilities throughout its lifetime.
A further degree of freedom is the automation of the complete system. The loading profile of each electrolyser can be adjusted separately such that the overall efficiency of the plant is optimal. Further objectives can be pursued, such as the lifetime maximisation of each electrolyser, by sharing the thermal stress in real time.
ABB has collaborated with Hystar, a green hydrogen producer in Norway, to use its PEM electrolysers in a demonstration plant to deepen the understanding of efficiency. This partnership highlights the value of collaboration and underscores how the future growth of the green hydrogen economy is contingent on a collective effort from industry partners.
To realise green hydrogen’s potential, decisive action across three fronts is required: governments need to implement supportive policies, industries must forge cross-sector partnerships, and companies must invest heavily in expanding the energy infrastructure. By simultaneously addressing these key areas, costs can be reduced while accelerating the widespread adoption of green hydrogen technology, paving the way for a cleaner and more sustainable future.
Yet, realising this potential requires overcoming significant financial and technological hurdles. While the high cost of production remains a major barrier, history has shown that emerging clean energy technologies can become cost-competitive with time, investment, and economies of scale. Solar and wind power faced similar challenges, and they are now among the cheapest sources of electricity worldwide. The same trajectory is possible for green hydrogen, but this hinges on a unified approach where researchers, companies, and governments come together to strive for progress and accelerate cost reductions. Advances in electrolyser technology, power supply optimisation, and efficiency improvements will be instrumental in closing the cost gap between green and fossil-based hydrogen, ensuring that green hydrogen can compete on a level playing field.
Policymakers play a crucial role in driving this transition. Supportive policies, such as subsidies, carbon pricing, long-term investment incentives, and sustainability mandates for companies, are needed to create a market environment where green hydrogen can thrive. Instead of competing in isolation, integration and collaboration are the key to uniting a diverse array of expertise, resources, and ideas to accelerate green hydrogen’s development and reap its rewards. A coordinated global approach – one that includes shared infrastructure development, cross-border hydrogen trade, and standardised regulations – will be essential in building a hydrogen economy that is both economically viable and widely adopted.
Looking ahead, the long-term vision for green hydrogen is both ambitious and exciting. By embracing standardised solutions and optimising production efficiency, green hydrogen could be the cornerstone of the future energy mix, fundamentally reshaping how the world is powered.
Ultimately, the commitment to sustainability demands collective effort, and investing in green hydrogen is an investment in a healthier planet for future generations. The faster the industry can standardise and scale up production, the sooner costs will fall and green hydrogen’s potential will be fully acutalised.
The stars of the energy-related trade show at the Hannover Messe 2025 were artificial intelligence (AI) and machine learning (ML), as companies demonstrated how these two powerful tools are becoming drivers of tomorrow’s energy and manufacturing sectors. Walking around the halls of the exhibition and viewing the AI and ML technologies alongside interactive demos on display, as well as the usual technologies and trends, visitors could really experience the
Alberto Litta Modignani, NextChem Tech, Italy, examines how green hydrogen and the electrolysis industry are being reshaped by energy transition challenges.
excitement and feel part of something that is transforming and setting new standards in the industry.
The same excitement has infused the nascent green hydrogen industry over the last seven years, when investors, industrialists, developers, and governments – spurred by the growing concerns about climate change – have led the race away from carbon-intensive fuels towards a new decarbonised energy world based on renewable power and green hydrogen.
Despite the hall at the Hannover Messe being dedicated to energy and hydrogen, with plenty of technologies on display, it was clear that the green hydrogen industry is currently facing a difficult situation.
It is now apparent that the energy transition is not just about energy; it is also about reshaping the global economy and energy geopolitics. As such, it is not happening at the pace and scale that was hoped. The global energy system has made it clear that the switch from oil, gas, and coal to wind, solar, hydrogen, and biofuels is much more difficult, expensive, and complicated than was initially expected. Furthermore, there is a general sense of frustration because every new MW of renewables coming online globally is an ‘energy addition’ rather than a ‘fuel switch’ or a substitution of fossil sources.
Greenhouse gas (GHG) emissions would need to decrease from about 34 billion t in 2020 to about 22 billion t in 2030 to meet 2050 climate targets, according to the International Energy Agency (IEA); however, emissions kept rising, up to 41.6 billion t in 2024.1 And a steep decline in only seven years is extremely unlikely to happen.
Green hydrogen project developments continue to expand but at a much slower pace than originally anticipated. The mortality rate of projects remains high. Green hydrogen costs, lack of sufficient long-term demand, and an uncertain regulatory environment have led to the cancellation of some promising projects even after final investment decision (FID).
Looking at the electrolyser market, numerous suppliers have probably invested too early, counting on the take-off of large scale projects worldwide. They have, as a result, saddled themselves with manufacturing facilities operating at a very low load factor that may soon become liabilities rather than assets. In such a situation it has been challenging for many electrolyser manufacturers to secure a lasting competitive advantage. Many companies in the EU and the US have been facing financial losses so severe that some of them have been forced to shut their businesses down, while many others are struggling to survive. However, despite this challenging environment, some positive developments have emerged:
y The water electrolysis market still shows very high potential for bankable technologies like alkaline and PEM, with market size expected to reach over US$5 billion by 2030 to serve large scale green chemical projects.
y The electrolysis suppliers’ arena remains crowded and challenging, but has produced important lessons to learn from the last 10 years of the green hydrogen and water electrolysis industry.
Investment in a proprietary giga-scale manufacturing capacity should be made very cautiously as the mortality rate of green hydrogen projects remains quite high. Instead, technology companies in water electrolysis should remain asset light, while focusing on innovation, engineering, testing, total cost of ownership minimisation, and flexible supply chains. Partnering with established manufacturers from other sectors to leverage best-in-class industrial production process knowledge should be considered as a strategic option.
The supply chain for electrolysers is made of a long list of components, with actual and potential criticalities on costs, performance, production capacity, delivery time, and market compliancy among others. Industry debate is ongoing about which business model and partnership an electrolyser manufacturer should establish with critical components suppliers to anticipate bottlenecks, de-risk performances, and avoid price volatility. Lack of familiarity and weak integration between OEMs and EPCs has affected green hydrogen projects quite heavily so far. Electrolyser manufacturers should also leverage more EPC competences to provide a cost effective constructable turnkey product.
Finally, meeting in-country value requirements is also of the essence, by collaborating with local partners to integrate locally produced components, which have been qualified and tested upfront to meet the required standards and supporting the performance guarantees.
So, which competing forces will drive and shape the future of electrolysers manufacturing to serve the expanding green hydrogen market during the next five years and beyond?
y Political stability and international cooperation vs political tension and trade tariffs.
y Industry 4.0 and AI adoption vs costs and labour constraints in emerging markets.
y Stable legal frameworks vs complex and varied legal requirements across different jurisdictions.
y Vertical integration of performance components to generate side revenues across the value chain vs flexible supply chains to de-risk the procurement activities.
The scale and variety of the challenges associated with green hydrogen adoption mean that it will not proceed as many expect or in a linear way. It will be multidimensional, proceeding at different rates with a different mix of technologies and different priorities in different regions, reflecting the complexities of the energy system that underpins today’s global economy.
It also makes clear that the process will unfold over a long period and that a linear transition is not possible; instead, the deployment of green hydrogen at scale will involve significant trade-offs due to the intrinsic features of a global hydrogen economy. Some examples include:
y Renewables can be installed almost everywhere and so electrolysers can be directly connected to them, thus making countries with an abundance of low-cost, renewable power ideal producers of green hydrogen, as well as hubs for the exchange of energy and hydrogen. As such it looks like a global
Figure 1. NextChem’s electrolysis cell FHYVE presented at the Hannover Messe in April 2025.
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business, but considering that hydrogen transportation is technically complex and costly, green hydrogen trade and new industrial relations are being shaped at a regional level instead.
y Renewable hydrogen will not generate revenues and profits comparable with the traditional oil and gas system. At the same time, upstream investments are lower and technical complexity is smaller, thus opening the market to new and diverse players, making hydrogen a more competitive business.
y Together with global suppliers of electrolysis stacks, regional industrial ecosystems will also enable developers and operators to leverage local supply chains for the deployment of balance of stacks and balance of plant at lower cost.
In conclusion, the challenges faced by the water electrolysis industry creates healthy competition on the one hand, and a significant degree of uncertainty on the other. Therefore, companies aiming to play a leading role in the global green hydrogen market must allow for flexibility when they organise their operations and make strategic decisions, in order to adapt to new and unplanned situations. The importance of also addressing economic growth, energy security, and energy access underscores the need to pursue a pragmatic path.
Combining hydrogen production and storage technologies with digital modelling tools can help to promote low-carbon and green hydrogen in the short and long-term. Proprietary technologies also help to decarbonise industrial processes, such as through producing ammonia and methanol. As a global EPC contractor, MAIRE integrates EPC expertise into the
design phase of new technologies, reducing risks, optimising constructability, and lowering total cost of ownership.
Strategic approach to navigating green hydrogen industry challenges
MAIRE’s green chemicals business unit NextChem is addressing the complexities facing the green hydrogen industry through the FHYVE technology developed by HYDEP (a NextChem subsidiary), that is scheduled for scale-up to industrial size in 2026.
In response to the challenges posed by political instability and trade tariffs, NextChem leverages its presence in key markets such as India and Latin America, utilising its EPC contractor footprint to cultivate resilient international partnerships and robust global supply chains.
To leverage industry 4.0 and AI integration, the company employs advanced AI-driven cell monitoring systems capable of predictive diagnostics and real-time performance optimisation, enhancing electrolyser efficiency and reliability. This strategic approach also involves a balanced hybrid strategy to the supply chain and manufacturing, combining selective vertical integration of high-performance components with diversified supply chains.
This model effectively mitigates procurement risks while unlocking additional revenue streams along the value chain.
Collectively, these technological advancements and strategic initiatives reinforce commitment to scalable, sustainable, and economically viable green hydrogen solutions.
Reference
1. ‘Fossil fuel CO2 emissions increase again in 2024’, Global Carbon Budget, (13 November 2024). https://globalcarbonbudget.org/fossilfuel-co2-emissions-increase-again-in-2024/
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Chris Gill, Worley, considers how innovation and collaboration within the hydrogen supply chain can help bring down the cost of green hydrogen production, with particular focus on electrolysers and plant infrastructure.
There are numerous barriers to scaling up green hydrogen production. This ranges from cost, to securing land and energy supply, as well as ensuring community engagement and support for planned projects.
One area that has not been explored in depth is technological innovation across the supply chain. Given that the green hydrogen industry is still in its early stages, this presents both challenges and opportunities for producers.
These challenges and opportunities fall into two core areas. The first is the electrolyser, the most critical component for converting electricity into hydrogen through electrolysis. The second is the balance of plant (BoP), which includes the surrounding infrastructure and systems that support the electrolyser’s operation. This encompasses everything from cooling to compression, offering opportunities for simplification and standardisation that can drive major efficiencies for producers.
Addressing these challenges calls for strategic partnerships and innovative approaches. Collaboration with original equipment manufacturers (OEMs) has the potential to bring about breakthroughs in both core areas.
Innovative electrolyser solutions
An electrolyser is currently responsible for 30 - 40% of production costs. Although electrolyser technologies are now fairly well established, there is still potential for improvement and innovation. Advancements in cell design, simplification of the balance of stack design, or improvements in membrane technology have the potential to increase efficiency and drive significant performance gains over the long-term.
Beyond enhancing electrolyser performance, increasing attention is being given to the materials used in their manufacturing. Efforts are underway to reduce reliance on scarce and expensive critical raw materials, such as iridium and platinum, which would result in lower costs to produce and reduced reliance on critical materials supply chain. This challenge is particularly pressing for PEM electrolysers, which depend on hard-to-source iridium.
To address this, researchers and manufacturers are working to identify alternative metals that can maintain or improve performance while reducing supply risks. These efforts are gaining urgency as EU legislation, such as the Critical Raw Materials Act, aims to reduce dependence on single third countries for key materials. By 2030, the act mandates that no more than 65% of the EU’s annual consumption of any critical raw material can come from a single third country, making access to rare earths and other critical elements from abroad more challenging. This is accelerating the search for substitute materials and innovative electrolyser designs that minimise reliance on constrained resources.
BoP
BoP refers to all the supporting components and infrastructure required for a hydrogen production system to function, beyond the core generating unit. In a hydrogen production facility, for example, the electrolyser is the centrepiece, but it cannot operate without an integrated BoP. This includes critical systems such as power conversion,
cooling, gas handling, water purification, compressors, storage, and control systems.
To drive down costs and accelerate deployment, the BoP must adopt a supply chain-led approach. This means that it is not just about selecting the best available equipment but also aligning standard supply chain offerings with specific project requirements and challenging specifications that add unnecessary complexity and cost.
For instance, compressors, a critical part of the BoP, can be among the most expensive pieces of equipment, potentially costing tens of millions of dollars depending on the asset’s size. Instead of following traditional design philosophies and opting for an industry-standard compressor, a supply chain-led strategy ensures that the OEM is fully engaged. By working strategically with both the engineering, procurement, and construction (EPC) contractor and the customer, the team can achieve breakthrough outcomes, adopting a minimum viable product approach to meet the customer’s business case needs.
This approach contrasts sharply with the way most process industry projects are developed today. It provides a solid foundation for significantly improving project viability and aligning costs with the real needs of the customer’s business objectives.
When the BoP is standardised, modular, and efficient, manufacturers can create a clear path to faster, more cost-effective hydrogen deployment – helping to turn ambition into reality.
Automation and digital solutions optimise BoP performance, reduce emissions, and future-proof hydrogen production. Advanced automation, digital twins, and AI-driven monitoring enhance efficiency, minimise energy losses, and improve system reliability. These technologies lower costs, reduce downtime, and support a scalable hydrogen economy.
Asset optimisation centres (AOC) use real-time analytics and remote monitoring to optimise assets. By integrating automation and digital solutions, this can help create more resilient and cost-effective green hydrogen production.
Collaboration: unlocking the opportunity to scale green hydrogen
The relationship between asset developers (an engineering partner who designs and builds the asset) and key equipment OEMs is an important one because it will not be possible to increase efficiencies in electrolyser technologies or standardise hydrogen production, more broadly, to the degree needed without a supply chain-led approach. Greater collaboration between these stakeholders to encourage technological innovation and standardisation will maximise the cost efficiencies that can be achieved and increase the likelihood of a green hydrogen project ambition becoming a reality.
The future of green hydrogen is not just about ambition, it is about execution. And execution demands collaboration.
Figure 1. Hydrogen tanks.
Tina Andersen, Hystar, discusses how PEM electrolyser technology can enhance safety and efficiency.
After a somewhat slower than expected green hydrogen scene in Europe during 2024, the hydrogen industry is experiencing a resurgence with more medium and large scale projects moving ahead.
Hystar, the Norwegian PEM electrolyser OEM, is seeing a very positive market trend, with more solid hydrogen projects being developed than ever before, and the short to medium-term outlook looking strong. While general support for decarbonisation of industry could be stronger, both on a national and regional level, great projects are nonetheless paving the way and reaching final investment decision (FID).
The recent months have been hectic and exciting. Hystar opened one of its containerised electrolyser projects (1.5 MW) in the Kårstø gas processing plant in Norway and delivered another 5 MW unit in Poland.
Hystar ended 2024 with being awarded a €26 million grant from the EU Innovation Fund, one of the world’s largest funding programmes for innovative low-carbon technologies. The grant will be used for the installation and operation of an automated GW production line for PEM electrolyser stacks in Høvik, Norway. The company’s headquarters and current stack assembly line are also located on the same campus. To keep up with the current market, PEM stacks must be truly cutting-edge, and must be cost-efficient for producing green hydrogen at scale. The EU Innovation Fund is useful for enabling companies to expand rapidly. More recently the market has seen the closure of new sales contracts for the supply of PEM electrolyser stacks to South Korea, and with the near-completion of FEED studies for more projects both in Europe and other continents, 2025 looks to be a busy year.
Norway has a long history of green hydrogen production at an industrial scale dating back to the 1920s. Abundant hydropower resources were used to make green hydrogen and green ammonia for fertilizer production, becoming an important industry in Norway and fostering a strong tradition within electrochemistry.
Green hydrogen has an undisputed role when it comes to the decarbonisation of hard-to-abate sectors such as heavy-duty transportation, aviation, green steel, glass, cement production, and the maritime sector.
Norwegians are perhaps not known for boasting, but supporting industries in reducing their CO2 emissions is a source of pride. Cutting energy consumption by 10 - 15% compared with standard PEM electrolyser stacks has led to significant cost savings. The uniqueness of modern stack technology should be centred around the operating principle, which should significantly enhance both system safety and performance. What can make this possible is changing the water feed from the anode to the cathode side, and adding a ventilating flow on the anode side, which makes it possible to utilise thinner membranes.
The hydrogen and oxygen evolution reaction still takes place in the same manner as in traditional PEM stacks, with protons being transported through the membrane. By having the air ventilation on the anode side, system safety is enhanced by effectively reducing the concentration of hydrogen in the oxygen on the anode side. It is simple but extremely effective. Using a significantly thinner membrane, which drastically reduces the ohmic resistance in the system, the stack energy consumption is substantially lower than traditional PEM stacks. This innovation can translate to large electricity cost savings, contributing positively towards reducing the levelised cost of hydrogen production.
Enhancing safety features and the ventilation system at the anode side also increase the reliability of the system, ensuring the electrolyser runs as close to 100% of the time without any undue downtime. This is crucial for maximising hydrogen production and minimising the complexity of owning and operating an electrolyser. In this scenario the focus should be to make all parts of owning and operating an electrolyser as affordable and simple as possible.
Hystar has been actively working on several projects over the last few years across Europe and most recently in South Korea. The company offers both containerised electrolyser systems and stacks for system integrators and EPCs globally. The containerised systems provide a turnkey solution that can be installed on-site, with Hystar participating in the commissioning of the equipment. The stacks are mass produced at facilities in Norway and shipped to customers, including recent contracts with South Korean customers.
Companies should be willing to show their commitment to driving the green transition through collaboration with customers. These strong customer relationships should be fuelled by a shared motivation to reduce greenhouse gas emissions and enable smart, profitable value chains that accelerate the green transition.
Supporting customers through the transition to sustainable energy should always remain a key focus. Companies need to be ambitious in setting goals and be committed to driving down costs and maintaining efficiency advantage.
With innovative technologies and strategic market movements, a clever business will be poised to make significant contributions to the hydrogen production industry, paving the way for a more sustainable and efficient future. Companies need to be ready to collaborate and provide solutions that fit the needs of the hydrogen industry.
Figure 1. Preparation of a customer order at Hystar’s Innovation Centre in Høvik, Norway.
Figure 2. Hystar’s patented technology.
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Larry Emch, Integrated Global Services (IGS), USA, explores technological advancements to increase efficiency and reduce CO2 emissions in steam methane reformers.
Developing cleaner and more efficient hydrogen production methods has become an ever-increasing priority for facilities worldwide. Global hydrogen production reached 97 million t in 2023, yet less than 1% qualified as low-emission hydrogen.1 Steam methane reformers (SMRs), the dominant technology in global hydrogen production, achieve 65 - 75% efficiency rates but continue to face significant operational challenges.2 This article explores technological advancements addressing efficiency limitations, heat transfer issues, and emission reduction strategies in hydrogen production facilities.
Key findings discussed in this article include:
� High-emissivity ceramic coatings applied to refractory surfaces can increase radiant efficiency by 2 - 5%, reduce bridgewall temperatures by up to 50°C (122°F), and cut fuel consumption and CO2 emissions by 2 - 5%.
� Advanced robotic cleaning technologies for convection sections can restore near-design efficiency levels, reduce flue gas temperatures by up to 58°C (136°F), and improve overall thermal efficiency by approximately 3%.
� Combined implementation of these technologies delivers immediate and significant returns on investment, with annual
savings of €210 000 - 630 000 in European markets and US$255 000 - 895 000 in US markets, while reducing CO2 emissions by 3000 - 7000 tpy.
SMRs
Despite the emergence of alternative technologies such as partial oxidation, autothermal reforming, biomass gasification, and alkaline electrolysing, SMR remains the dominant method for hydrogen production globally. SMR-based hydrogen plants typically range from 5000 nm3/h to more than 300 000 nm3/h in capacity, with hydrogen purity reaching up to 99.99%.3
As shown in Figure 1, in a typical SMR-based hydrogen facility, hydrocarbon feedstocks (natural gas, LPG, naphtha, or refinery off-gases) first undergo desulfurisation. Process steam is then added, and the mixture enters a pre-reformer. Further reforming occurs in the radiant wall SMR, followed by a medium-temperature CO shift reactor. Finally, the gas is purified through pressure swing absorption (PSA) to achieve product-grade hydrogen.
Efficiency challenges in hydrogen production
The radiant wall SMR consumes substantial energy and requires advanced technologies in combustion management, radiant coil design, metallurgy, control, and refractory systems. As process gas progresses through reforming tubes, the equilibrium position constantly shifts due to changing gas composition and temperature.
Maintaining optimal SMR performance faces several challenges:
y Uneven heat distribution in radiant sections.
y Bridgewall temperature limitations.
y Convection section fouling.
y Tube metal temperature constraints.
y Emissions compliance requirements.
These challenges directly impact production capacity, operational costs, and the environmental performance of hydrogen plants.
Radiant heat transfer efficiency in reformers
Radiant heat transfer is essential in the efficiency of hydrogen production systems, particularly in reformer furnaces, where it accounts for up to 95% of total heat transfer.4 The effectiveness of this process depends on the emissivity of internal surfaces (their ability to emit thermal radiation). Traditional fibre refractory materials possess relatively low emissivity values (0.3 - 0.5), creating an opportunity for improving the energy transfer pathways where significant heat escapes through flue gases rather than reaching process tubes.
Ceramic high-emissivity coatings transform this dynamic by increasing surface emissivity to values above 0.9, directing more radiant energy toward the process tubes. These proprietary coatings have many benefits. They reduce bridgewall temperatures, increase production capacity, lower fuel consumption, and decrease carbon emissions. Additionally, they protect refractory surfaces from high temperature degradation by encapsulating ceramic fibre materials to prevent particulate release and loss of insulation value. Unlike ridigiser type materials, ceramic coatings are specifically designed for numerous years of service life in these elevated temperatures. This technology represents a safe and proven approach to overcoming common operational limitations in hydrogen reformers.
Case study 1: enhancing radiant section efficiency
A twin-cell side-fired primary reformer in southern Europe experienced production limitations due to high bridgewall temperatures. When production reached approximately 110 000 nm3/h, bridgewall temperatures would trigger an alarm set at 1100°C (2012°F). This restriction severely limited the reformer’s efficiency and throughput capacity.
The implementation of high emissivity refractory coatings on all radiant surfaces (burner tiles, insulating brick, and ceramic fibre) resulted in significant improvements:
y Increase in emissivity from 0.45 to 0.92.
y Radiant efficiency enhancement from 40.3% to 42.3%.
y Bridgewall temperature reduction of more than 50°C (Figure 2).
y Hydrogen production rate increase from 108 000 nm3/h to 116 000 nm3/h.
y 4.9% overall radiant efficiency gain.
y CO2 emission reduction equivalent to 18 400 tpy.
y Payback period of less than three months.
Maintaining stable bridgewall temperatures (well below thresholds) over a six-year operational period demonstrated the durability and reliability of the coating system. When reapplied
Figure 1. The SMR process.
Figure 2. Bridgewall temperature readings vs time.
during a 2023 turnaround, the coatings continued delivering consistent performance benefits. An overview of these benefits is shown in Table 1.
Convection section optimisation
Convection sections in SMRs often experience efficiency losses due to fouling accumulation on heat transfer surfaces. This fouling, consisting of airborne particulates, combustion byproducts, and occasionally migrated process materials, creates thermal barriers that significantly reduce heat exchange effectiveness.
Convection section fouling typically manifests through increased fuel consumption, elevated flue gas and stack temperatures, and reduced throughput capacity. Advanced robotic cleaning technologies offer a solution by accessing tube arrangements to remove deposits that conventional methods cannot reach, much less remove, restoring near-design efficiency levels while extending equipment lifespan.
Case study 2: SMR efficiency optimisation
The Tüpras İzmir refinery in Turkey demonstrates the relationship between radiant and convection section optimisation technologies. Following a turnaround where adsorbents from a Pressure Swing Absorption Unit migrated into the SMR convection bank, the facility experienced reduced efficiency, higher fuel consumption, and elevated flue gas temperatures.
Radiant section solution
In 2014, applying high-emissivity ceramic coatings to the refractory surfaces increased the radiant section’s
heat transfer efficiency by 2.9%, decreased bridgewall temperature by 26°C (79°F), and reduced energy consumption by 6.8 - 8.3%.
Convection section solution
Three years later, TubeTech TM robotic cleaning addressed the severe convection section fouling that had never been cleaned since the unit’s commissioning. This complementary intervention decreased flue gas temperatures from 278°C (532°F) to 220°C (428°F), improved overall thermal efficiency by approximately 3%, and increased steam production by 20% while raising steam temperatures by 10 - 15°C (18 - 27°F).
Results and ROI
Together, these technologies reduced hydrogen production costs by US$24.6/t, delivering a return on investment (ROI) in under 60 days. This combined approach, enhancing radiant section emissivity while restoring convection section cleanliness, represents a comprehensive strategy for maximising SMR efficiency beyond what either technology could achieve independently.
Emissions reduction strategies
SMRs significantly contribute to site emissions at hydrogen production facilities and refineries. As regulatory pressures and corporate sustainability commitments intensify globally, addressing these emissions delivers both environmental and economic benefits.
High-emissivity ceramic coatings applied to refractory surfaces reduce emissions substantially alongside their efficiency improvements. A typical installation delivers 2 - 5% fuel savings, translating to 2000 - 4000 tpy of CO2 reduction.5
European market benefits
y Natural gas savings: with European natural gas prices, these efficiency gains represent approximately €160 000 - 480 000 in annual fuel savings, depending on plant size and regional pricing.6
y Carbon credit value: under the EU Emissions Trading System, where carbon credits trade at approximately €50/t of CO2, these reductions carry an additional value of €100 000 - 200 000 annually.
US market benefits
y Natural gas savings: with natural gas prices forecasted at around US$4.20/million Btu for 2025, these efficiency gains represent approximately US$170 000 - 510 000 in annual fuel savings for US facilities, depending on plant size and local gas pricing structures.7
Table 1. Final steam methane reforming efficiency analysis
y Carbon credit value: in states with active carbon pricing mechanisms, where carbon credits trade at approximately US$13.85/t of CO2, these reductions carry an additional value of US$27 700 - 55 400 annually.
Complementary convection section optimisation through robotic cleaning technology provides additional environmental and financial benefits. These advanced systems typically deliver a further 1 - 3% reduction in fuel consumption and CO2 emissions, preventing approximately 1000 - 3000 tpy of CO2 emissions.
European additional benefits
y Natural gas savings: €50 000 - 150 000 per year.
y Carbon credit value: €50 000 - 150 000 annually.
US additional benefits
y Natural gas savings: US$85 000 - 385 000 per year.
y Carbon credit value (where applicable): US$13 85041 550 annually.
When implemented as a comprehensive optimisation strategy, the combined technologies deliver convincing economic returns in both markets, even before considering potential future carbon pricing mechanisms. This makes these optimisation technologies increasingly attractive for hydrogen producers focused on operational efficiency and environmental performance.
International market considerations Beyond the US and European markets, facilities worldwide can benefit significantly from these optimisation technologies. The precise ROI calculations depend on local factors including:
y Regional fuel costs and availability.
y Local regulatory frameworks and emissions pricing mechanisms.
y Facility-specific operational parameters and production demands.
Individual ROI calculations for other countries should incorporate these region-specific factors to determine the precise economic value of implementation. However, given the relatively short payback periods observed across diverse operational environments, these technologies consistently deliver strong financial returns regardless of geographic location.
Conclusion
The optimisation of hydrogen production facilities presents an opportunity at the intersection of operational efficiency, economic performance, and environmental sustainability. These case studies highlight that combining high-emissivity ceramic coatings in radiant sections and advanced robotic cleaning technologies in convection sections can transform SMR performance.
These technologies safely address fundamental heat transfer limitations, a common challenge for hydrogen producers. They offer proven pathways to overcome production bottlenecks without major capital investment. With implementation timeframes typically measured in days rather than months, rapid returns on investment make these solutions financially attractive across diverse market conditions globally.
References
1. ‘Global Hydrogen Review 2023’, International Energy Agency, (2023), https://www.iea.org/reports/global-hydrogenreview-2023/executive-summary
2. ‘Hydrogen Insights 2024’, Hydrogen Council and McKinsey & Company, (September 2024), https://hydrogencouncil.com/wpcontent/uploads/2024/09/Hydrogen-Insights-2024.pdf
3. ‘Low carbon hydrogen production through methane reforming’, Scottish Enterprise, https://www.scottish-enterprise.com/media/ mgrdyoir/hydrogen-factsheet-low-carbon-hydrogen-productionthrough-methane-reforming.pdf
4. SUNDMACHER, K., and LIESCHE, G., ‘Optimal Tube Bundle Arrangements in Side-Fired Methane Steam Reforming Furnaces’, Frontiers in Energy Research, (30 October 2020), https://www.frontiersin.org/journals/energy-research/ articles/10.3389/fenrg.2020.583346/full
5. AKTAŞ, Y., et al., ‘Ceramic coating application in a refinery stream methane reformer furnace’, Digital Refining, (June 2022), https:// www.digitalrefining.com/article/1002773/ceramic-coatingapplication-in-a-refinery-steam-methane-reformer-furnace
6. ‘Europe’s New Emissions Trading System Expected to Have World’s Highest Carbon Price in 2030 at €149, BloombergNEF Forecast Reveals’, BloombergNEF, (6 March 2025), https:// about.bnef.com/blog/europes-new-emissions-trading-systemexpected-to-have-worlds-highest-carbon-price-in-2030-at-e149bloombergnef-forecast-reveals/#:~:text=BloombergNEF%20 predicts%20that%20the%20EU,revenue%20from%202027%20 to%202035
7. ‘Short-Term Energy Outlook’, US Energy Information Administration, (10 April 2025), https://www.eia.gov/outlooks/ steo/#:~:text=We%20now%20expect%20that%20global,in%20 last%20month’s%20STEO%2C%20respectively
Figure 3. Before convection de-fouling.
Figure 4. After convection de-fouling.
Eric Pratchard and Todd Grubb, Zeeco, Inc., USA, alongside Hector Ayala, Aloke Sarkar, and HS Lee, ExxonMobil Technology and Engineering Company, USA, consider the impact that advancements in ultra-low NOX burner technology could have on hydrogen firing and NOX emissions.
Meeting worldwide net zero commitments requires significant decarbonisation of the oil and gas and other heavy industries. One way to achieve decarbonisation goals is using hydrogen as a process burner fuel at concentrations close to 100% by volume instead of hydrocarbon-based fuels. Current ultra-low NOX burners (ULNBs) and new burner designs can struggle with high hydrogen concentrations due to increased flashback risk and elevated costs for NOX emissions management, as hydrogen’s higher flame temperature leads to more adiabatic NOX production. As demand grows for better solutions with lower carbon and NOX emissions, the industry needs a ULNB suitable for 100% hydrogen firing while
maintaining much lower NOX emissions – and one that is easy to retrofit into existing fired heaters to minimise the capital outlay required to decarbonise key refinery processes.
To meet that demand, Zeeco and ExxonMobil worked together to design, develop, test, and implement a new next-generation ULNB design that can fire 100% hydrogen in addition to a wide range of fuel gas compositions, while producing significantly lower NOX emissions without complicated or expensive additional control systems or emissions solutions. The new burner does not use external flue gas recirculation or lean-pre-mix technology and meets targets in both natural and forced draft systems with ambient or preheated combustion air.
The companies jointly conducted burner testing for both single and multi-burner configurations for a wide range of process conditions. Those test results showed good flame stability, performance, and emissions reduction, with flame dimensions similar to current-design ULNBs. ExxonMobil installed the new burners, named FREE JET® Gen 3TM, in a process heater at its facility in Baytown, Texas, US. Early operational results were consistent with burner performance testing, and the burners are delivering emissions reduction and operational flexibility as expected.
Current emerging technologies and selective catalytic reduction (SCR) systems, considered possible alternatives to this new burner design, can be complex, expensive, and require additional protective systems or operational requirements.
Burning hydrocarbon-based fuel containing as much as 80% hydrogen cuts CO2 emissions in half. To achieve greater reductions in carbon, a higher concentration of hydrogen, likely close to 95%, is needed to achieve net zero emissions targets. Thus, to meet industry goals for decarbonisation, a process burner design must be commercially available that can safely and cost-effectively combust close to 100% hydrogen.
Most fired heaters and process furnaces today were designed for firing natural gas or refinery fuel gases that contain a high proportion of hydrocarbons plus hydrogen, inert gases, and traces of other compounds. Hydrogen content for typical refinery fuel gas may vary between 20 - 40%. When converting burners to fire high hydrogen, concentrations of 90 - 100% are needed and that changes the operating parameters of the burner, requiring adaptations to the design to ensure optimal burner and heater operation.
The flame speed of hydrogen is significantly higher than that of typical hydrocarbon fuels, resulting in faster combustion and increased heat release per unit volume. The flame speed of hydrogen combustion is approximately 1.7 m/s (5.6 ft/s), while the flame speed of natural gas is significantly slower at only 0.4 m/s (1.3 ft/s). Additionally, the stoichiometric adiabatic flame temperature of hydrogen (2182°C or 3960°F) is higher than natural gas (1937°C or 3520°F). Hydrogen’s high flame speed causes combustion to occur more rapidly than when firing natural gas. This rapid combustion process releases the combustion energy in a smaller volume, leading to localised elevated near-flame temperatures, which compound the effect of the inherently high adiabatic peak flame temperatures on NOX emission rates. Any region with elevated temperatures above 760°C (1370°F) is conducive to creating small amounts of NOX formation and at temperatures above 1100°C (2000°F), NOX increases exponentially.1
Current ULNBs will often produce 50% more NOX emission when switching fuels from low to high hydrogen. Local regulatory requirements for NOX emission limits are expected to continue increasing, regardless of hydrogen firing. Thus, the next-generation ULNB designs that are suitable for firing 100% hydrogen must also reduce NOX emission further than the current generation of ULNBs.
Current ULNB technologies
Process burner designs have improved over the decades, and various technologies have been deployed to lower NOX emissions with a primary focus on manipulating localised areas of the air/fuel mixture to create either fuel-rich or fuel-lean
combustion zones to lower the peak flame temperature and reduce NOX formation. Air staging, fuel staging, internal flue gas recirculation (IFGR), and lean pre-mix have been the primary techniques for reducing NOX with currently available ULNBs. However, these techniques cannot meet the demands of high hydrogen firing while keeping NOX emissions within limits.
Emerging technologies have attempted to use combinations of these methods, and concepts such as ‘flameless combustion’ have shown some promise. However, these burner designs require complicated hardware, sophisticated controls, and protective systems to be added to the existing equipment. Additionally, these burners are typically limited to forced draft installations, making them unsuitable for most retrofits without significant investment because most fired heaters are natural draft. Some of these designs also use lean-pre-mix technologies, which can have potential flashback limitations when firing high hydrogen fuels, especially at the lower end of the burner heat release (i.e. at higher burner turndowns).
Installation of an SCR unit is an alternative means of addressing higher NOX emissions due to high hydrogen firing. An SCR is a post-combustion system installed in the flue gas duct downstream of the convection section. SCRs can reduce NOX emission by up to 95%, but installing one is a significant capital expenditure with long-term operational challenges. Furthermore, the additional space requirement of an SCR can be challenging, especially when retrofitting existing equipment. Lastly, SCRs must be operated within the specified flue gas temperature and ammonia/urea injection rates to avoid deterioration of the catalyst bed and/or ammonia slippage to the atmosphere.
Advanced ULNB technology
Addressing these industry challenges requires a 100% hydrogen capable process burner without complicated controls, extra systems, or unique space and shape requirements. ExxonMobil and Zeeco collaborated on a new burner design capable of meeting the above requirements and transitioning from a variety of fuel blends to 100% hydrogen and vice versa.
The resulting burner is a patent-pending design incorporating a new square burner tile configuration and an adaptation of proven ULNB technology to reduce NOX emissions significantly. The two companies worked together to design, performance test, and field test the design to verify it would safely and cost-effectively achieve performance and emission objectives.
Previous generations of the process burners using free-jet theory had individual burner staged fuel tips with a single fuel port. This optimised the benefit of IFGR to lean the fuel mixture and, when combined with the round tile shape, produced a nearly universal lean fuel mixture composition along the burner firing ledge. Primary firing tips located along the inner diameter of the burner throat ensured burner stability, and the uniform flame temperature resulting from the fuel mixture has generated positive NOX performance for more than two decades.
The new square-tile burner design builds upon the well-established free-jet concepts but also introduces a new way of staging fuel and air to reduce thermal NOX generation further. The new burner reduces the number of staged fuel tips but adds multiple ports to each tip that deliver fuel mixture along the tile surface. Fewer points of fuel introduction and the new square tile shape create non-uniform areas of rich and lean fuel mixtures. These non-uniform areas mean the primary tips that generate
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higher levels of thermal NOX can be located in a lean fuel region to lower the combined flame temperature produced by the primary and staged fuel. The zone located between the primary tips has a more fuel-rich mixture that remains stable without the assistance of the primary tip.
The new square tile design results in single-digit NOX performance when firing typical refinery fuels, and maintains a strong performance even while firing 100% hydrogen. Stable, reliable, and practical performance across a wide variety of fuels means operators have the capability to fire 100% hydrogen, a wide variety of refinery/petrochemical fuel gas compositions, 100% natural gas, and large volumes of low BTU gas (LBG), and to switch back and forth among various fuels more easily. The burner is capable of a 5:1 turndown in heat release. Burner tile sizes are comparable to existing burners of similar heat release, and it utilises a single primary fuel gas connection to the burner to limit fuel gas piping modifications. This design does not require additional fuel, air controls, or protective systems. Figure 1 shows the new burner design installed in an operating unit that has operated for nearly a year.
This design does not use traditional lean-pre-mix methodology, eliminating burner flashback concerns. No external flue gas recirculation is required. Additionally, the burner can operate in either forced or natural draft modes and with ambient or preheated combustion air.
Figure 2 illustrates the NOX emission performance vs modern ULNBs. This new burner design provides about a 50% reduction in NOX emissions while delivering the capability to fire up to 100% hydrogen without sacrificing flame stability.
Performance test results
The new burner design was rigorously tested in various operating conditions to verify its performance and evolve its design. The companies’ extensive development programme included single burner testing, multi-burner testing, ambient and preheated air, forced draft and natural draft applications; and firing
Corrected to 3%
Figure 2. Burner test results of FREE JET GEN 3 NOX performance across a range of hydrogen fuel blends vs measured NOX of various current-generation ULNBs.
Figure 1. New burners installed in an operating unit.
Table 1. Performance test of the new burner design (natural draft, single burner, ambient air)
of natural gas, typical blends of refinery/petrochemical fuel gas, 100% hydrogen, and LBG waste gases. Testing of the final design showed good performance and flame stability over a wide range of fuel gas compositions. Tables 1 - 4 summarise the burner test results for various conditions.
Figure 3 shows single burner testing at a range of hydrogen concentrations in the fuel blends. As can be seen from the images, the burner tested included a nozzle for LBG fuel firing (the large circular nozzle in the centre of the burner), but LBG was not in service when the photographs were taken.
Test results show the burner is fully capable of firing 100% hydrogen and provides about a 50% reduction in NOX emission, with single-digit NOX emission performance on natural gas firing. Even at 100% hydrogen firing, NOX emission was close to single digits at approximately 10 ppm(v) in natural draft application and 9 ppm(v) in forced draft application, values corrected to 3% O2 dry. It was observed that NOX emission increases as hydrogen content increases in fuel gas, but peaks at about 80% hydrogen and then drops beyond that until 100% hydrogen firing, as evident in the Fuel C data in Figure 3. CO probing and O2 profiling verified that the flame
length and width are comparable to current-generation ULNBs. CO tests verified the stability of the burners irrespective of fuel composition.
Multi-burner tests were performed to examine potential adverse effects of any flame-to-flame interactions on NOX emission and the impacts were found to be negligible. Since many older existing fired heaters have burners spaced tighter than API 560 recommendations, additional burner tests were conducted at burner spacing tighter than API 560 recommendations. NOX emission increase was less than 20% when burner spacing was reduced to 75% of the API 560 recommended spacing over a wide range of fuel firing, including 100% hydrogen.
Field test results
ExxonMobil installed 12 of Zeeco’s FREE JET Gen 3 burners in one of the vertical cylindrical heaters at its Baytown facility for field application in early 2024. The burners are forced draft, preheated air, suitable for natural draft ambient air operation as well, and have a design heat release of 9.8 million Btu/hr (LHV basis) each. The CO emission remained compliant even during commissioning without the need to adopt additional mitigation measures.
3. Performance test of the new burner design (forced draft, single burner, ambient air)
Table 4. Performance test of the new burner design (forced draft, single burner, 400°F preheated air)
Table 2. Performance test of the new burner design (natural draft, multiple burner, ambient air)
Table
The CO emission stayed below a 50 ppm hourly rolling average even during startup operations. Field reports confirmed that all burners remained stable even at low firing rates and with excess oxygen as high as 10 vol% (wet). Preliminary emission testing was done with the burners firing between 60 - 75% of designed heat release, with a hydrogen concentration in the fuel gas ranging between 45 - 60%, and with combustion air temperature between 135 - 230°F. Measured NOX emissions when corrected to 3% O2 (dry) and 1600°F bridgewall temperature remained at or below 12 ppm. This matched the performance testing results.
Conclusion
In the coming years there will be demand for next-generation ULNBs fit for 100% hydrogen firing yet with much lower NOX emission. These burners need to be easy to retrofit into existing fired heaters, easy to install on new fired heaters, and need to have
minimal hardware/control requirements. This newly-developed next-generation ULNB meets industry’s demands and can make a facility hydrogen-ready today for the coming fuel changeover. The burner is suitable for both natural draft and forced draft applications, for both ambient air and preheated air, and can handle a wide range of fuel gas compositions, including 100% hydrogen –and has been proven in field installation. The burner maintains the performance and flame dimensions of current-generation ULNBs while significantly reducing NOX emission.
Notes
• All references to % hydrogen content is in volume%.
• ExxonMobil Technology and Engineering Company has numerous affiliates, many with names that include ExxonMobil, Exxon, Mobil, Esso, and XTO. For convenience and simplicity, those terms and terms such as “Corporation,” “company,” “our,” “we,” and “its” are sometimes used as abbreviated references to one or more specific affiliates or affiliate groups. Abbreviated references describing global or regional operational organisations, and global or regional business lines are also sometimes used for convenience and simplicity. Nothing contained herein is intended to override the corporate separateness of affiliated companies.
Reference
1. ‘Technical Bulletin: Nitrogen Oxides (NOx), why and how they are controlled', US Environmental Protection Agency, (November 1999), https://www3.epa.gov/ttn/catc/dir1/fnoxdoc.pdf
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Figure 3. Single burner testing showing various levels of hydrogen in natural gas.
Nico Schmaeling, John Crane, Germany, examines how digitalisation can aid the wider adoption of hydrogen energy, through improved efficiency and profitability.
For hydrogen to achieve the scale and affordability needed to meet net zero ambitions, the sector must embrace digitalisation. The hydrogen industry is at a pivotal moment, with years of policy support and investment momentum driving significant growth. While there are some economic challenges, the overall outlook remains positive, with continued advancements and strong support from global initiatives. Digital technologies play a significant role in overcoming some of the barriers that the industry faces, driving efficiencies, reigniting investment, and enabling hydrogen to fulfil its potential.
The current economic headwinds are concerning. However, the net hydrogen project pipeline continues to grow at a strong pace. Hydrogen is currently bouncing back after a short slowdown, driven by EU-funded infrastructure and demand stimulation, as well as
increased momentum in India and China. In the US, there are no clear signals that the country is moving away from hydrogen, particularly blue hydrogen and carbon capture utilisation and storage (CCUS). The sector does face pressure from rising costs of materials, labour, and water, alongside increasing grid and transportation costs. Add to that the geopolitical uncertainty and ongoing concerns over potential trade troubles, and it is clear hydrogen has a number of challenges to navigate.
Digital technologies are key to accelerate the scale up, as they can improve efficiency and profitability. Digital marketplaces, for example, are beginning to facilitate the buying, selling, and coordination of green hydrogen, making transactions accessible for budding consumers – an important step. Soon, digitalisation will make the decarbonisation of hard-to-abate sectors increasingly viable.
What could a digital hydrogen future look like? It would mean a global hydrogen supply chain, tracked by blockchain, moving green fuel from Australia to the US, and everywhere in between. Artificial intelligence (AI) optimises production, storage, and distribution, onsite and in transit. Smart contracts ensure seamless trading, while industries and transport systems integrate hydrogen into its energy mix. As costs fall and adoption rises, hydrogen could supply 20% of the world’s energy by 2050, which is the Hydrogen Council’s current target.1
The future may be bright for hydrogen. This article will explore how digital technologies are bolstering the hydrogen market and the potential to achieve a digital hydrogen future.
Understanding the hydrogen market
Before diving into digitalisation, this article will consider the hydrogen market in more detail.
Despite some stalling out of projects, the consensus is that this is a short-term trend, partly because of economic headwinds and an interim period between adoption and greater digitalisation. In fact, while some areas are experiencing setbacks, others are showing forward momentum.
For example, according to the International Energy Agency (IEA)’s ‘2024 Global Hydrogen Review,’ governments are beginning to transition from policy development to implementation, announcing approximately US$100 billion in new funding for 2025 and beyond.2 In 2024, 19 new national hydrogen strategies were introduced, bringing the total to 60 – covering 84% of the world’s carbon-emitting countries. At COP28, 37 governments committed to standardising
national certification, laying the groundwork for a globally recognised framework for hydrogen products.
This shift from policy to implementation will be backed by digital technologies, showing up in four critical areas. First, production optimisation, where Internet of Things (IoT) systems enhance electrolyser efficiency and streamline operations. Second, AI-powered predictive maintenance, which minimises unplanned outages, reduces costs, and improves overall reliability. Third, digital marketplaces, which are bridging the long-standing gap between producers and consumers. And finally, advanced modelling – particularly through digital twins – which are unlocking new efficiencies.
Finding efficiencies
If there is one thing digitalisation is bringing to hydrogen, it is visibility. The industry is increasingly leveraging real-time insights to fine-tune production, cut costs, and scale up efficiently. AI and IoT sensors now track every detail, from plant operations and electrolyser performance to grid fluctuations and even weather conditions.
One of the recent developments comes from the development of capillary technology, which is improving electrolyser efficiency. It is hitting 98% system efficiency by eliminating gas bubbles on electrodes and optimising water flow.3 This kind of development is primarily due to the design of the cell, rather than the digitisation of sensors controlling operating parameters. Efficiency gains are rolling in thick and fast across the sector. The Hydrogen Council reports that AI and machine learning are already boosting green hydrogen production efficiency by 10 - 15%, largely through AI-driven optimisation of electrical input and heat levels in electrolysers.4 Beyond production, digitalisation is also cutting downtime. Predictive maintenance is nothing new in industrial settings, but its impact on hydrogen is profound. Deloitte estimates that hydrogen producers are seeing a 25% boost in productivity while reducing maintenance costs by the same amount.5 The European Hydrogen Association is even more bullish, reporting that AI-driven predictive maintenance can cut unplanned outages by 30 - 40%, slashing both workforce and spare parts costs.6 While results vary, the bigger picture is clear: hydrogen production is moving from reactive problem-solving to proactive optimisation.
A green hydrogen trial at the European Marine Energy Centre (EMEC) is an example of this, where AI algorithms monitored real-time grid and weather data to automate production and storage – even adjusting operations to capitalise on lower electricity prices.
Digitalisation is also tackling one of hydrogen’s biggest barriers: market inefficiency. Producers are currently hesitant to commit to large scale projects without guaranteed demand, while consumers are reluctant to invest without reliable supply and infrastructure. What is missing? A clearer, more dynamic marketplace.
Early solutions are emerging. Lhyfe Heroes, launched in April 2024, is one of the first green hydrogen marketplaces, allowing buyers and sellers to trade hydrogen in just a few clicks. In June 2023, the European Energy Exchange (EEX) launched HYDRIX, a platform for hydrogen sales auctions and trading instruments. A year later, Hyfinder emerged as a dedicated B2B marketplace designed specifically for the hydrogen sector.
Figure 1. Hydrogen plant.
These platforms allow for greater transparency and accessibility. They are shaping pricing and commercial models for the entire industry, connecting producers, consumers, and investors, giving buyers the ability to compare supply points, verify hydrogen sources, and make more informed purchasing decisions.
HYDRIX is particularly interesting. As the first green hydrogen index of its kind, it is setting the foundation for regulated exchange trading – a crucial step in creating a mature, liquid market. It is already making waves, forming partnerships with the Indian Gas Exchange (IGX) and Gesellschaft für Internationale Zusammenarbeit (GIZ) to help establish a hydrogen trading market in India.
While these digital marketplaces aim to improve supply and demand forecasting to enhance visibility, and are a good first step, they are something of an exception to the rule. Data-sharing limitations remain as many market participants fear losing their competitive edge by sharing their data. But without that reliable data, investors and hydrogen players struggle to make informed decisions, leading to short-term thinking that hinders long-term market growth.
Progress is being made in this area. The HyTrust project, run by Fraunhofer IEE in Kassel, Germany, and Fraunhofer IMW in Leipzig, Germany, has implemented a data trust system to facilitate secure data exchange in the hope that a neutral intermediary may encourage participants to engage more appropriately.
Lastly, digitalisation is also transforming how hydrogen projects get off the ground. Digital twins, which are virtual models of physical systems powered by real-time sensor data, are quickly becoming a must-have tool for hydrogen projects. Why? Because they are helping producers trial and test different scenarios to produce the best results – the same technology that allowed Hysata’s electrolyser result.
Digital twins also help de-risk projects by allowing developers to simulate how hydrogen plants will perform before they are built and can be optimised to new locales all without laying a single brick. Not only are these models helping companies optimise efficiency, cut costs, and make smarter investment decisions, McKinsey estimates that digital twin technology could reduce hydrogen production costs (LCOx) by 5 - 15%.7
One example is the Zero Carbon Humber cluster in the UK, where Microsoft, Accenture, and the University of Sheffield’s AMRC used digital twin technology to model hydrogen-based decarbonisation strategies. This initiative explored how hydrogen could benefit more than 300 UK businesses in the area, offering a real-world glimpse into hydrogen’s potential at scale.
With digitalisation accelerating production, maintenance, trading, and project planning, hydrogen is finally gaining the tools it needs to scale at speed. The challenge is now to help these technologies reach maturity.
Hydrogen of the future
With the global green hydrogen market on track to reach 150 GW of production capacity by 2030, fuelled by technological advancements and unprecedented investment, the pace of progress will only accelerate.
One key area to watch is microgrids – small, localised electrical systems that can generate and distribute electricity,
which will become more important as hydrogen producers seek to integrate renewables into their operations. Microgrids help hydrogen producers optimise energy production, storage, and grid interaction using IoT and big data, which will aid efficiency. The Yuri Green Hydrogen Project in Western Australia offers a glimpse of this future, aiming for 500 MW of electrolysis capacity by 2030. It is already leveraging an 8 MWh energy storage system and 18 MW of solar power to support a 10 MW electrolyser – a clear demonstration of how smart energy management is reshaping hydrogen production.
Yet the greatest developments may still surprise the industry. Take the recent development from the Ulsan National Institute of Science and Technology (UNIST) –a photoelectrode module that uses sunlight to split water into hydrogen and oxygen. If scaled, this could redefine solar-powered hydrogen production and may sit alongside more traditional models.
For now, blue hydrogen remains the dominant form of hydrogen production, acting as a bridge to fully green production. According to the Hydrogen Council, an eightfold increase in investment is needed to meet global policy targets, and to fast-track this transition.8
The next steps? Producers can prioritise digital infrastructure alongside physical assets while advancing data-sharing protocols – because without clear, reliable data, the entire industry slows down. Investors should back projects with strong digital components and support market-enabling digital infrastructure wherever possible. Consumers, too, can actively engage with digital marketplaces to signal demand, stabilise the market, and drive commercial adoption.
Hydrogen sits at the heart of the ‘twin transition’ –the simultaneous shift towards a low-carbon and digital future. Any initiative aligned with these twin forces will not just accelerate hydrogen’s viability but will help fast-track towards a sustainable future. And despite a temporary market slowdown, this transition is already well underway.
References
1. ‘Hydrogen for Net-Zero: A critical cost-competitive energy vector’, Hydrogen Council and McKinsey & Company, (November 2021), https://hydrogencouncil.com/wp-content/uploads/2021/11/ Hydrogen-for-Net-Zero.pdf
2. ‘Global Hydrogen Review 2024’, International Energy Agency, (October 2024), https://www.iea.org/reports/global-hydrogenreview-2024/investment-finance-and-innovation
4. ‘Hydrogen in Decarbonized Energy Systems’, Hydrogen Council and Baringa, (October 2023), https://hydrogencouncil.com/wp-content/ uploads/2023/10/Hydrogen-in-decarbonized-energy-systems.pdf
6. SAXENA, A., ‘AI-Driven Optimization for Green Hydrogen Production Efficiency’, Journal of Scientific and Engineering Research, Vol. 11, No. 6 (2024), pp. 145 – 155. https://jsaer.com/download/vol-11iss-6-2024/JSAER2024-11-6-145-155.pdf
7. ANDRIOPOULOS, N., DON, D., UBOGUI J., and WAARDENBURG M., ‘Digital twins: Capturing value from renewable hydrogen megaprojects’, McKinsey & Company, (1 May 2024), https://www. mckinsey.com/industries/electric-power-and-natural-gas/ourinsights/digital-twins-capturing-value-from-renewable-hydrogenmegaprojects
8. ‘Hydrogen Insights 2024’, Hydrogen Council and McKinsey & Company, (September 2024), https://hydrogencouncil.com/wpcontent/uploads/2024/09/Hydrogen-Insights-2024.pdf
Marcel Kelder, Yokogawa Europe, considers how business models in the operational technology (OT) domain can adapt operations to ensure security and productivity through technological advancements, such as edge machines.
The business model for numerous industries is undergoing significant changes and will continue to be driven by market conditions and the emergence of disruptive technologies, such as robots and artificial intelligence (AI). Companies that adhere to outdated business models risk losing their competitive edge and may even face the possibility of going out of business. Initially, the transformation of business models occurred within the enterprise environment through digital transformation. Over time, this transformation has also reached production sites. These sites, known as the operational technology (OT) domain, tend to be conservative and generally resist significant changes, which is understandable due to safety and security concerns.
Renewable industries, including the green hydrogen sector, encounter similar challenges but with an additional hurdle: an uncertain business model. Unlike the established and predictable business model for grey hydrogen, the business model for green hydrogen is new and likely to be volatile. This uncertainty puts pressure on operational expenditure (OPEX) from the plant’s operational readiness. As a result, the need for digitalisation to reduce OPEX becomes increasingly important.
Despite the urgency to transform business models in the OT domain for operations, supply chain, asset management,
and production, introducing disruptive technologies to support the transformation faces significant challenges. Disruptive technologies in the OT domain, such as the Industrial Internet of Things (IIoT), tablets, smart CCTV, robots, drones, digital twins, and AI, hold the potential to drive significant improvements. However, a sustainable plan is essential for successful deployment.
Existing company policies on safety and security often create barriers to implementing new technologies. These policies, combined with the lack of a data management and integration strategy, hamper the deployment and data exchange between domains, including the cloud. The consequence is siloed data, lacking structure and context, leading to limited integration and efficiency. This is particularly concerning because of the urgency to digitalise. As data volumes continue to grow, digitalisation will play a crucial role in the effective use of AI, which is one of the key pillars for transforming the OT domain.
To effectively use AI, a substantial amount of data is necessary for the algorithm to identify patterns and provide usable feedback to users or machines. This concerns not only structured data, such as organised and real-time data from a control system, but also unstructured data such as text, images, videos, and audio, produced by sources like smart CCTV, smart sensors,
robots, drones, and external systems, as seen in Figure 1. Unlike structured data, which is easier to manage, unstructured data demands more sophisticated tools for processing and analysis.
Domain segregation
To address the potential security and safety constraints of the OT domain when using structured and unstructured data from new smart sources, companies may consider separating the production site into an OT domain and a distinct IIoT domain, as shown in Figure 2. In traditional OT environments, security remains a primary concern, particularly for automation and safety systems, leading to strict cybersecurity policies. As a result, implementing changes in the OT domain can be challenging. Most new technologies, such as IIoT and robots, are primarily used for monitoring and analysis with no direct impact on control and safety. By implementing these technologies in a distinct domain, the associated policies and rules could be more relaxed, including a different IEC-62443 security level. Alternatively, it is possible to accommodate all separate zones under one OT firewall, assuming the integration and cybersecurity policies allow the exchange of data between the OT domain and the enterprise, including the cloud. Regardless of the architecture chosen, separating critical systems into distinct domains and zones remains essential to limit the impact of a potential security breach.
Data management
Cloud storage and computing, combined with AI, is transforming various business processes in the OT domain. Asset management is a prime candidate for transformation through data analytics. Currently, most assets are maintained under a labour-intensive and costly preventive maintenance regime. Transitioning from preventive to predictive maintenance requires, among others, additional sensors, integration, and advanced analytics.
IIoT sensors offer a cost-effective option and are typically adequate for monitoring less critical assets, which often make up more than 60% of all assets in a facility. However, sensors connected to the asset alone do not provide the full picture. For a comprehensive deep analysis of asset reliability, additional data such as process information, historical asset data, inspection log files, and engineering details are necessary. This data is located and stored in different storage repositories in the OT and IT domains.
Data from diverse OT sources must be structured and contextualised to become useful for users like process or reliability engineers. Traditionally, this processing occurs on-site using data historians or specialised tools like simulation software. Yet, with growing data volumes and the need for more computing power and collaboration, these applications are increasingly shifting from deployment on-premise to the cloud. As this shift occurs, the demand for a data management strategy to integrate the OT and IT domains will grow.
For numerous companies, data management for the OT domain is not a strategy but a reactive, ad-hoc solution tailored to the user’s needs. Traditionally, real-time data is considered critical and managed by the data historian, while transactional data, such as work orders generated by the ERP system, is frequently transferred using eXtensible markup language (XML) or simple object access protocol (SOAP) as a common solution, as seen in Figure 2. However, a data management strategy would go beyond these tools by defining why and how this data is collected, who can access it, how it is secured, and how it integrates with other systems to support broader goals.
Historically, the data historian has served as the primary data manager within the OT domain. These systems typically feature OT-interfaces such as OPC DA, and are designed to make data easily accessible for various uses. The data stored in the data historian consists of structured process data, arranged and formatted consistently. The data historian, however, encounters two major constraints that undermine its potential as the future’s data manager: it is limited to managing only structured data, and its software licensing costs scale with the number of data points. As smart algorithms drive an increase in both structured and unstructured data, these limitations become even more pronounced.
Figure 2. Typical operational technology (OT) architecture with separate domains.
Figure 1. Data types.
Edge machine
As digital solutions, OT data, and cloud usage grow, the number of connectors bridging the IT and OT domains also rises. For real-time data, the data historian can be the interface; for transaction data, SOAP can be the interface; for images and video from CCTV or robots, secure file transfer protocol (SFTP) can be the interface; and for interfacing with the cloud, message queuing telemetry transport (MQTT) can be the interface. However, without a strategy, the increasing number of interfaces between IT and OT could impact the long-term sustainability of the architecture, particularly in terms of data management and cybersecurity.
The data historian will continue to be vital for storing critical data in many facilities, but edge machines are increasingly taking over the role of the data manager between the IT and OT domains. Edge machines are a new concept for the OT domain and play a key role in bringing the IT and OT worlds together, also known as IT/OT convergence.
The edge machine is a software solution running on a physical machine or within a virtual environment. Its primary function is connectivity in conjunction with managing and processing OT structured and unstructured data. Typically, the edge machine is in the demilitarised zone (DMZ), as shown in Figure 2, which serves as a firewall to separate the IT and OT domains. The edge machine is a solution for the OT domain, acting as the data manager across various domains, including the cloud. However, many companies remain unaware of its potential and continue to rely on the data historian as their primary data management tool.
As the number of interfaces between systems and applications grows, so does the number of connections. Traditionally, the OT domain relies on point-to-point connections, meaning each link between applications and systems operates as an independent, standalone connection. As the number of interfaces between domains, applications, and systems increases, middleware offers a more efficient solution for managing these connections and data models, as seen in Figure 3.
Middleware is a software component within the edge machine solution that acts as an intermediary layer, enabling efficient data exchange and collaboration across systems, applications, and domains. It streamlines integration by managing data transfers, translating between different protocols, and offering essential services like security and scalability. Middleware typically supports various protocols such as OPC Unified Architecture (OPC UA), SOAP, and MQTT, to connect applications and systems to the middleware virtual service bus. The data on this service bus is managed through configured workflows. For instance, a workflow might involve exchanging data between two applications under specific conditions or making data available for analytics, as illustrated in Figure 4.
Like any solution, the cloud has its drawbacks, including the latency of data transfer. When real-time analysis with fast sample times is required, the computing needs to be executed on-premises instead of the cloud. The data historian is initially the most suitable option when all necessary data is available, and the task involves a first-principle calculation. However, for machine learning (ML) or AI algorithms that rely on data from multiple IT and OT sources, the data historian is probably not the best option. Edge machines with connectors to various data sources for managing data create an ideal environment for on-premises analytics. These machines can integrate with either external analytical tools through plugins or incorporate built-in analytics, including ML and AI.
When analytics are performed on-premises, users can take advantage of the local edge machine’s dashboarding and reporting features. The strength of these modern solutions lies in its low-code engineering environment. Whether configuring workflows or creating dashboards, minimal coding is needed for customisation, making deployment user-friendly.
Conclusion
In summary, many companies are on the brink of transforming the OT domain to increase their productivity and competitiveness. Digitalisation plays a pivotal role in this transformation, leveraging technologies like IIoT, robotics, and AI. These technologies not only generate data but also rely on data from the available IT and OT sources to use them effectively. Thus, sustainable data management between IT and OT domains becomes crucial for transformation.
Figure 4. Block diagram of Yokogawa’s IM Hub Edge Machine.
Figure 3. Interface types.
Danny Nicholas, Rotork, UK, examines how electrification, digitalisation, and automation can make clean hydrogen commercially viable.
Clean hydrogen can play an important role in the energy transition, but the cost of production has left its use a long way behind earlier predictions. If the industry is to thrive, there must be a greater focus on commercial viability through electrification, digitalisation, and automation.
Hydrogen that is produced using renewable or nuclear energy, or fossil fuels with carbon capture, can clean up hard-to-abate industries such as shipping, aviation, chemicals, and steel. But while demand for hydrogen keeps growing, low emissions hydrogen accounted for less than 1% of overall production and use in 2023. 1 To achieve targets set by the
International Energy Agency (IEA), it would have to make the enormous leap to a third of global hydrogen demand by 2030. 1
But while clean hydrogen is more expensive than many alternatives, such as biogas, wind, and solar energy, the hydrogen industry may have an ace up its sleeve. Many producers are developing plants and facilities from scratch, and can also create infrastructure that will prioritise on safety while keeping costs down through automating processes, monitoring equipment, and collecting valuable data.
This is essential for first movers in the sector because although there are growing opportunities, there are also headwinds and rising costs caused by the global energy crisis, high inflation, and supply chain disruptions.
According to the IEA’s ‘Global Hydrogen Review 2023’, some projects have increased their initial cost estimates by up to 50%. 2 However, these rising costs can be mitigated through the use of smart technology.
Improving efficiency
Hydrogen is found in a number of natural resources but while supply is plentiful, it still needs to be separated from the element it is joined to (for example, water is comprised of hydrogen and oxygen). In the electrolysis process, an electric current is applied to water, splitting it
into hydrogen and oxygen, and both the liquid and gases must be efficiently managed with smart electric actuators.
And because clean hydrogen solves the problem of carbon emissions which can result from traditional hydrogen production, there is increasing momentum and growing opportunities for early movers in the industry. Hydrogen is capable of being stored under high pressure or as a liquid and then transported in tanks, or through pipelines and used where it is needed, but at every stage the flow of liquids and gases must be precisely controlled for both safety and cost efficiency.
Highly engineered components can reduce unplanned maintenance and plant shutdowns. Smart equipment designed for the rigours of hazardous environments can ensure valves move quickly and precisely to minimise waste and energy consumption. Such equipment can also institute emergency shutdowns when necessary to protect both people and equipment. And systems can be built to ensure they are repeatable so that each new hydrogen plant is of the same high standard.
Investing in technology
Investment in this technology presents a significant opportunity as governments and international institutions turn their attention to breathing life into the clean hydrogen sector. From production to storage and transportation of clean hydrogen, the industry is gaining momentum. More than 40 countries have now established national hydrogen strategies and the IEA is encouraging faster action to stimulate demand for low-emission hydrogen and generate investment in the sector. 2
North America and Europe have taken the lead in implementing initiatives to encourage low-emissions hydrogen production. Government funding has been made available through schemes such as the US Hydrogen Production Tax Credit, the EU Important Project of Common European Interest, and the UK Low Carbon Hydrogen Business Model. 2 China, which accounted for less than 10% of global electrolyser capacity for dedicated hydrogen production in 2020, is now thought to have reached 50%. 2
As a result, transport and storage infrastructure for hydrogen and hydrogen-based fuels must scale up.
Hydrogen is mostly produced and consumed in the same location but with demand growing there is a need to develop infrastructure that will connect production with centres of demand. Pipelines are the most efficient and least costly way to transport hydrogen distances of up to 3000 km. 1
Approximately 2600 km of hydrogen pipelines are already in operation in the US and 2000 km in Europe, with several countries developing new hydrogen infrastructure. 1 The European Hydrogen Backbone initiative aims to establish a pan European hydrogen infrastructure while the Dutch government has announced a plan to invest €750 million in a 1400 km national hydrogen transmission network. 1
For transporting hydrogen over longer distances, shipping hydrogen in carriers is more cost-effective.
Figure 1. CVL on an electrolysis skid.
In February 2022 the Hydrogen Energy Supply Chain project demonstrated the first shipment of liquefied hydrogen from Australia to Japan.
Infrastructure for storing hydrogen will also be needed. While salt caverns are already being used in the US and UK, the potential of hydrogen for balancing the power grid and the possible development of an international trade in the gas will require much greater storage capacity.
Several research projects are underway for the demonstration of fast cycling in large scale hydrogen storage, such as HyCAVmobil in Germany and HyPSTER in France. Other projects in the Netherlands, Germany, and France are looking at the potential for repurposing natural gas salt caverns, as in 2022 a demonstration facility to store hydrogen in lined hard rock caverns started operations in Sweden.
Eliminating pollution
All this means that the role of smart technologies to control the flow of gases and liquids will be key to ensuring safety and commercial viability. The energy requirement of compressed hydrogen storage, for example, needs accurate and reliable valve control for temperature and pressure management which can be achieved with smart electric actuators.
And because of the cost of production, it is essential that every step of the value chain, from production to storage and transport, is as smooth and efficient as possible. The automation of the flow of water, hydrogen, and any associated hydrocarbons via actuators and related instruments can ensure efficiency and peak performance. They leave no room for human error and levels of accuracy and precision can be increased.
Valve actuators can be used, for example, across renewable energy applications such as solar tracking systems and offshore wind farm transformer platforms. Electrolysis plants need highly accurate modulating valve operation to control water levels and flow rates, while fail-safe flow control solutions are specified on safety critical systems such as hydrogen storage tanks, transport, and distribution networks. Distribution stations also demand the highest level of safety from actuators and flow control equipment.
In addition to improving efficiency, smart control systems can also eliminate pollution by identifying rogue emissions and stopping leaks while using a fraction of the
power of many existing systems. This is essential because zero emissions targets for the industry are rapidly approaching – in the EU, 2050, and China, 2060.
Using electric actuators
Selecting electric actuators rather than more traditional pneumatic control can offer benefits when it comes to safety, efficiency, and commercial viability, and various hydrogen equipment manufacturers have already chosen electric actuators to play a critical role within their hydrogen generators.
Rotork actuators were also selected to control the flow of hydrogen at a power plant. More than 90 CVL linear electric actuators and 184 ExMax quarter turn electric actuators were used by US company Doosan fuel cell’s project in Daesan, South Korea. 3
The number of projects for low-emission hydrogen production that have been announced is rapidly expanding, although many are at an early stage of development. Production could reach 38 million tpy in 2030 if all the projects that have been announced come online.
Some early examples of clean hydrogen production are already in operation. Bloom Energy has begun producing hydrogen from the world’s largest solid oxide electrolyser at NASA’s AMES Research Centre in California, US, and the world’s first hydrogen storage facility in an underground porous reservoir began operations in April 2023 in Austria.
Low-emissions hydrogen offers huge opportunities for those who can manage costs through the efficient use of technology. In the IEA’s Stated Policies Scenario, the market size of the low-emissions hydrogen sector is expected to rise from US$1.4 billion currently to US$12 billion by 2030, which is equivalent to the spending on offshore wind in Europe in 2022. 2 And it could further increase to US$112 billion, roughly the size of the rooftop solar PV installations in the Asia Pacific region in 2022.
Ultimately, early movers in the clean hydrogen market have huge opportunities if they can drive down the cost of production, storage, and transport, while maintaining the highest levels of safety. The clean hydrogen sector is comparatively young, however, and as it accelerates, equipment manufacturers may not have the supply chains they need in place to achieve these goals. They will need to form partnerships with established suppliers that have global footprints and offer a broad range of technologies and multiple solutions that can help them achieve greater cost reductions.
References
1. ‘Hydrogen’, International Energy Agency, (2025), https://www. iea.org/energy-system/low-emission-fuels/hydrogen
2. ‘Global Hydrogen Review 2023’, International Energy Agency, (2023), https://www.iea.org/reports/global-hydrogenreview-2023/executive-summary
3. ‘Hundreds of electric actuators supplied to fuel cell power plant’, Rotork, (8 August 2019), https://www.rotork.com/en/ news/hundreds-of-electric-actuators-supplied-to-fuel-cellpower-plant
Figure 2. Clean hydrogen can play an important role in the energy transition.
Chuck Hayes, Swagelok Company, USA, explains how using high-quality valves within hydrogen systems preserves and augments system performance and longevity.
Hydrogen is one of the most versatile gases in the world. Industries ranging from food processing to steel production to transportation all rely upon it, either as a key component of a larger process or as an end product itself. Its utility makes it a strong contender to replace other energy sources as a greener, more sustainable option.
Figure 1. Tiny hydrogen molecules can infiltrate the surrounding stainless steel of the system’s components and cause hydrogen embrittlement, leading to a weakening of the components.
Despite its many benefits, hydrogen is not always an easy substance to work with. To process it effectively, industrial hydrogen and heavy-duty transportation systems require high-quality, specialised components. Due to hydrogen’s volatility, handling systems must deliver leak-tight performance to ensure safety for technicians as well as end users. In addition, to remain a viable option, these systems must last for years or even decades, so designing with the proper components is crucial to ensuring system longevity.
Valves are especially instrumental in controlling the flow of hydrogen from one location to another. Specifying the right type of valves within the system’s design can mean the difference between safe, efficient, and effective hydrogen delivery vs operations that could put technicians and end users at risk.
How hydrogen differs from other industrial gases
Hydrogen is the simplest element, having only one proton and one electron. In addition, it also comprises the smallest molecules in the universe. Keeping them contained presents a difficult challenge, particularly because any leak during transport can endanger users. This is especially true in vehicle fuel applications,
where end users are typically not accustomed to working with hydrogen and may not understand the related risks.
Hydrogen’s small molecules also pose a threat to system components themselves. Using lower-quality stainless steel components can encourage a process called hydrogen embrittlement, where the molecules embed into the surrounding metal. Over time, this infusion can lead to fissures that significantly weaken the component, potentially resulting in system failure. To avoid these problems, system designers should take measures to ensure that components are made from only high-quality stainless steel.
Hydrogen exposure can also have negative effects on elastomers, particularly in hydrogen-rich environments such as fuel cells, hydrogen storage systems, or industrial processes. Elastomers are more permeable to hydrogen than metals, meaning hydrogen can diffuse through them relatively easily. Over time, this can lead to swelling or blistering, especially under cyclic pressure conditions.
Why high performance matters in hydrogen valves
Ensuring the quality level of a hydrogen delivery system’s components prevents persistent problems from occurring, which ultimately contributes to the system’s overall success. Designers may consider several factors when specifying hydrogen valves:
� Pressures: hydrogen must be stored at 350 - 1000 bar to achieve the desired density.
� Safety: no matter what industry the hydrogen delivery system is intended for, it must be designed with the safety of workers in mind.
� Maintenance: valves should be easily accessible for replacement during maintenance, and the system should allow for easy configuration of a leak-tight seal.
The specified valves must meet these overall performance standards to ensure the system works properly. Additionally, valves should demonstrate leak-tight performance at the connection point and at the shutoff or regulation point. Operating conditions for hydrogen valves are often challenging, so the selected valves should be manufacturer tested and verified to ensure they are adequate for the task.
Types of hydrogen valves
In most hydrogen applications, two or more of the following valve types are combined to make a complete system.
Ball valves
Ball valves stop and start the flow of hydrogen from one direction to the next. Higher-quality ball valves feature stem seal designs that do not break down with repeated use. When ball valves are used, it may make sense to use a trunnion-style valve with a direct-load design. Such designs can provide confidence that the valves
Figure 2. Ensuring components meet the highest possible standards will protect technicians from potentially hazardous hydrogen leaks.
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will not leak, even when they are activated and shut off multiple times during each cycle. Alternatively, system designers may consider valves with bottom-loaded stems, which reduce the possibility of a blowout and provide a greater degree of safety.
Reputable partners can offer suggestions on which ball valves will work most effectively in the system as designed. For example, ball valves may offer two or three-way functionality, different mounting options, and a range of flow coefficients, which are highly system-specific, and a knowledgeable partner should be able to discuss the benefits of each. Selecting ball valves that are designed to be used in hydrogen applications and that are compatible with the system’s fittings is critical, so designers should consult an expert for advice when needed.
Needle valves
Needle valves are helpful for making fine adjustments in how much hydrogen is moving through the system at any given time. When deciding which hydrogen needle valves to use, designers may consider several factors. These valves are typically made of metal, which means the force needed to seal them could deform the needle and seat over time. Deformed needles can lead to dangerous leaks that result in significant costs to fix. Additionally, because of the required sealing force, large air actuators are often necessary to open and close the valves. These electric actuators can take up to two minutes to fully deploy. With these factors in mind, designers should look for needle valves made with high-quality 316 stainless steel that can resist deformation during repeated use. Also, because not all needle valves are properly pressure rated for common hydrogen applications (350 - 1000 bar), designers should choose a needle valve that is qualified for elevated working pressures. And, like with ball valves, compatibility with other hydrogen-qualified components is a must.
Check valves
Check valves prevent excess backflow, which protects technicians and, in the case of transportation applications, end users. Unlike check valves in other industrial fluid systems, there are several hydrogen-specific stressors to incorporate into any check valve selection process. Springs are a vital component of most check valves and are made with strain-hardened materials. Unfortunately, this makes it more susceptible to hydrogen embrittlement. To prevent this, check valves and their springs should be made of high-quality 316 stainless steel that prevents deterioration from occurring. In transportation applications, check valves often endure rapid temperature and pressure changes, which can stress the elastomer seals more than usual. In those instances, it may make more sense to use ball check valves on hydrogen compressors. Material integrity and compatibility with other hydrogen components are important here, too.
The bottom line
Hydrogen is an increasingly integral part of operations across many industries. Engineers who are designing
Best practices for hydrogen system design
Hydrogen’s utility as an industrial fluid is unmatched, but due to its properties, it requires specific design practices to maximise its potential. The fluid systems that move hydrogen gas from one place to another must be able to handle its molecules safely, efficiently, and effectively.
Because many hydrogen system designers are limited to an oil and gas background, their understanding of hydrogen’s challenges may be somewhat lacking. With this in mind, designers may want to consider these common steps as they create new hydrogen fluid systems:
� Reducing leak points in hydrogen infrastructure means keeping the number of connections to a minimum. Additionally, designers should pay attention to employing proper tube-bending techniques in strategic locations rather than adding another potential leak point to the system.
� Generally, a well-designed hydrogen system should be made from high-quality 316 stainless steel tubing materials, which have demonstrated good performance over lengthy service life. Specifically, stainless steel containing elevated levels of nickel can deliver optimal performance in hydrogen systems. The American Society for Testing and Materials (ASTM) requires a minimum of 10% nickel in 316 stainless steel formulations, but 316 stainless steel with a minimum of 12% nickel is better suited for the unique challenges posed by hydrogen. Nickel content helps stabilise the microstructure of stainless steel, enabling it to be more resistant to hydrogen embrittlement.
� While cone and thread fittings are often used in oil and gas fluid systems, they will not work as effectively in hydrogen system settings. The history of these fittings is storied, but deploying them in hydrogen systems will lead to leaks and potentially increase risks for technicians and consumers. Fortunately, modern higher-performing options like compression fittings are available. Two-ferrule mechanical grip fittings are commonly specified in hydrogen applications because they maintain ideal pressure ratings of up to 1050 bar. They provide more security than older technologies and are available in high-quality stainless steel material options.
advanced hydrogen handling systems should take extra care to specify that the proper valves fit each application to ensure the appropriate containment of hydrogen’s volatile and tiny molecules. Working with a knowledgeable partner with experience in the hydrogen sector can provide valuable insight into choosing the right components for the job. As the use of hydrogen continues to grow in the industrial landscape, taking all these factors into consideration helps to ensure safety, reliability, and durability for the long-term.
Sanket Walimbe,
Trillium Flow Technologies,
considers the importance of valves for safety and reliability in industrial hydrogen applications.
Hydrogen has long been essential in industries like chemical processing and refining, but its role as an energy carrier has remained limited due to costly, fossil fuel-dependent production. However, hydrogen is a viable solution for sectors where direct electrification is impractical, such as heavy industry and transportation.
The hydrogen market
Hydrogen production and energy are emerging as major growth markets for green innovation. The estimated global market is around 90 million t and is forecast to reach 130 million over the next 10 years, or approximately US$17.4 billion to US$29.7 billion over the same period.
This significant growth is driven by technological advancements, which are driving down costs for industries racing towards energy transition, bringing in investment for R&D. As technology drives down the costs of hydrogen
energy production, it becomes more viable than other renewable solutions like solar and wind power for large scale energy production due to its superior efficiency as an energy source. As governments and businesses invest heavily in hydrogen infrastructure, this surge creates fertile ground for job creation, with new roles emerging in engineering, manufacturing, and R&D.
Europe and China have already begun their investment in the hydrogen market, while the US is just beginning this journey. This only cements the potential for growth still to come when the US realises the full potential the hydrogen market could offer.
Hydrogen as a cleaner power source
A major part of hydrogen power’s attractiveness is its alignment with the United Nations Environmental, Social, and Governance (ESG) goals. By supporting hydrogen initiatives, companies can demonstrate commitment to the energy transition and environmental stewardship. This enhances their corporate reputation and attracts socially conscious investors who are increasingly prioritising ESG criteria in their investment decisions.
In the rapidly evolving landscape of energy transition, it is essential to utilise advanced and reliable solutions for process applications when handling hydrogen – whether in its production, transportation, or storage. Although valves may seem like minor components, they play a crucial role
in emission control and process optimisation. They assist industries in transitioning to cleaner energy solutions, support carbon capture and storage (CCS) initiatives, and maintain operational integrity. All of these factors are vital steps toward a net zero future. Therefore, valves must be reliable and secure enough to manage the unique challenges posed by hydrogen and CCS applications.
Trillium Flow Technologies has achieved TÜV SÜD certification for its Blakeborough® control valves designed for industrial hydrogen applications. This newly certified valve, specialised for use in the hydrogen production process, comes in addition to another recent development, the Sarasin-RSBD H2Star Valve, designed for hydrogen fuelling and distribution. Both valves can aid in emission control and process optimisation.
Ensuring safety
Hydrogen safety requires stringent measures due to its low ignition energy, making even minor leaks hazardous. Effective leak prevention relies on advanced detection systems such as infrared sensors and flame detectors. Material compatibility is also critical, with rigorous testing to ensure resistance to embrittlement and explosive decompression. Since hydrogen is odourless, specialised sensors or odorants are essential for reliable leak detection.
Hydrogen’s role in the energy transition
Industrial applications
Hydrogen enables decarbonisation in steelmaking, ammonia production, and refining. It can replace coke in steel production, reducing CO2 emissions, and serve as a cleaner feedstock for ammonia and synthetic fuels, aiding the transition to sustainable industrial processes.
Energy storage
Hydrogen can store excess renewable energy, addressing intermittency issues and stabilising the grid. Large scale hydrogen storage facilities can act as buffers, ensuring a steady power supply.
Heavy-duty transportation
Hydrogen’s high energy density makes it ideal for aviation, maritime transport, and long-haul trucking, where battery weight and charging times are limiting factors. Companies like Nikola, Hyundai, and Daimler are investing in hydrogen-powered trucks to enable zero emission freight transport.
Technical challenges in hydrogen handling
Despite its advantages, hydrogen presents significant technical challenges due to its unique properties, largely relating to material degradation.
Hydrogen embrittlement
Hydrogen tends to diffuse into material attacking its fundamental properties, such as ductility and toughness, making the material brittle. This is called ‘hydrogen embrittlement’ and the embrittlement occurs at a molecular level. This depends on variable factors such as temperature, pressure,
Figure 1. Trillium facilities at Elland, UK, on TÜV SÜD certification day.
Figure 2. Control valves at Trillium’s UK valve facilities.
purity, exposure time, and partial pressure of hydrogen. Also, high-strength materials, components with sharp discontinuities, and those with surface defects are especially susceptible to this issue. If unsuitable metallic materials or welds are employed, the valves may experience brittle fractures, resulting in valve failure or loss of containment.
Polymer blistering
The selection of polymers for sealing applications presents significant challenges, primarily due to hydrogen blistering, which is the most common issue encountered. This phenomenon occurs when diffused hydrogen accumulates within the polymer, creating internal pressure that eventually forms blisters. Over time and repeated cycles, the formation of additional blisters leads to increased permeability, ultimately resulting in leakage. To mitigate these risks, additional testing is recommended, including rapid gas decompression (RGD) testing of elastomers with 100% hydrogen. For thermoplastics, optional RGD testing is advisable, especially for applications at elevated temperatures near the material’s limits. Furthermore, compatibility and ageing assessments of elastomers and thermoplastics should be conducted with 100% hydrogen gas phase.
Welding and cladding
Nickel-based alloys are not recommended for pressure-containing welds due to their susceptibility to hydrogen embrittlement and potential degradation in high-pressure hydrogen environments. The hardness of the
weld metal and heat-affected zone (HAZ) must conform to NACE MR0175 requirements to mitigate the risk of hydrogen-induced cracking and ensure long-term material integrity. While cladding can be acceptable, it should not be used as a primary measure to prevent hydrogen degradation of the base material or as a barrier against hydrogen exposure, as the underlying substrate must be inherently resistant to hydrogen-related failure mechanisms.
Cryogenic hydrogen service
Trillium’s Blakeborough control valves for hydrogen services have recently been certified by TÜV SÜD. This certification validates the control valves’ compliance with stringent international standards, including ISO 15848-1, BS EN IEC 60534-4, and ISO 19880-3. These standards emphasise durability, precision, and safety under demanding conditions. Rigorous testing with 99.9% pure hydrogen at both cryogenic and ambient temperatures confirmed the valves’ performance, meeting endurance Class A CO1 and CC1 stem leakage requirements and ensuring compliance with stringent fugitive emission standards.
The qualification programme is followed by a factory audit, designed to confirm that the facilities’ quality management system is fully equipped to address the requirements of emerging technologies. This audit evaluates the factory’s adherence to essential standards in critical areas such as production control and monitoring, supply chain and material management, product verification and testing, and documentation practices. The factory’s ability to design,
manufacture, and test valves for hydrogen service in industrial applications is thoroughly validated through this process.
The valve design is classified under ISO 15848-1, meeting the Class A stem leakage requirement for CO1 and CC1 endurance, ensuring durability and longevity in demanding hydrogen applications. The testing was conducted with 99.9% pure hydrogen at cryogenic and ambient temperatures, proving the suitability of the design and material of construction for demanding hydrogen applications. Both valve function and internal/external leakage are rigorously tested in accordance with BS6364, ANSI FCI 70-2, BS EN IEC 60534-4 Class VI, and ISO19880-3 standards. This ensures optimal performance and safety under various operating conditions.
Applications
Hydrogen is central to achieving net zero carbon goals, serving as a versatile energy carrier for applications ranging from industrial processes to long-distance transportation. Blakeborough control valves offer reliability in these critical applications, due to the material compatibility, as the metallic, elastomeric, and thermoplastic components have been tested to withstand extreme temperatures and hydrogen exposure.
The valves bolster operational efficiency and reduce emissions across different areas of the hydrogen value chain. In production and storage, these components support hydrogen purification, pressurisation, and liquefaction processes. Also, in transportation and distribution, the valves ensure safety and reliability for hydrogen transfer and storage systems.
The future of hydrogen in energy transition
The hydrogen economy is expected to expand significantly in the coming decades. Governments and industries worldwide are investing in hydrogen infrastructure, including production plants, storage facilities, and transportation networks. Emerging technologies, such as solid-state hydrogen storage and advanced electrolysers, will play a crucial role in making hydrogen more accessible and cost-effective.
Additionally, international collaboration is essential for developing a global hydrogen supply chain. Countries such as Japan, Germany, and Australia are leading the efforts to establish hydrogen trade routes, enabling large scale hydrogen distribution.
Conclusion
Hydrogen is a cornerstone of the global energy transition, providing a sustainable alternative for hard-to-decarbonise sectors with high energy demands. Innovations in material science, safety protocols, and flow control technology have driven the emerging industry forward, making it safer and more viable to investors. As the industry evolves, advancements in valves and infrastructure will continue to play a major role in supporting a cleaner, more sustainable energy landscape. As other markets begin to realise the full potential in the hydrogen production and energy industries, the industry is likely to witness greater investment and a more urgent need for innovative new flow control products.
A podcast series for professionals in the downstream refining, petrochemical, and gas processing industries
EPISODE 3
Peter Davidson, CEO of the Tank Storage Association (TSA), discusses the essential role that the tank storage sector has to play in ensuring supply security and resilience, as well as in facilitating the energy transition.
EPISODE 4
Rasmus Rubycz, Market Manager for New Energy at Atlas Copco Gas and Process, considers how heat pumps as an industrial technology are gaining greater attention as a result of the increased drive for sustainability, and the challenges and opportunities of electrification of process heat.
EPISODE 5
Mike Logue, Owens Corning Business Director –Specialty Insulation, delves into factors that can support the performance, safety, and longevity of insulating systems installed in hydrocarbon processing environments, including cryogenic facilities.
EPISODE 6
Leakhena Swett, President of the International Liquid Terminals Association (ILTA), and Jay Cruz, Senior Director of Government Affairs and Communications, consider the key role of industry associations.
EPISODE 7
Susan Bell, Senior Vice President within Commodity Markets – Oil, Rystad Energy, discusses the impact of trade wars on global oil demand and oil prices.
Dr Michael George and Dr Christian Gebauer, Heraeus Precious Metals, consider the role hydrogen fuel cells could play in the development of heavy duty vehicle materials.
Global transport consumes 28% of the total energy demand, leading to 10.3 billion tpy of CO2 by 2040. These numbers illustrate that this sector is one of the most important industries, but also one of the most challenging ones, to drive decarbonisation to net zero. Within the transport sector, light and heavy duty vehicles (those less than 3.5 t) like buses, trucks, off-road, and construction vehicles are responsible for over 26% of the total traffic CO2 emissions.1 Decarbonisation of this sector would therefore have a tremendous impact on the global CO2 footprint.
Battery electric vehicles (BEVs) are likely to play an important role in this decarbonisation process. However, in applications where high-power densities, fast refuelling times, and long travel distances are required (such as heavy duty, aviation, or maritime transport), BEVs are technically limited. The polymer electrolyte membrane fuel cell (PEMFC) technology is one of the key technologies to allow for the decarbonisation of the heavy duty, aviation, and maritime sectors. Refuelling times are similar to diesel engines and driving distances up to 1000 km with high power densities make PEMFCs a strong solution, especially for heavy duty applications.
The advantages of hydrogen fuel cells for combustion engines are well known, however, the technological switch has not yet taken place. Only approximately 200 heavy duty fuel cell trucks are currently deployed on European roads.2 However, this number is expected to increase to 110 000 fuel cell trucks by 2030, making clear that the switch will take time, but is likely to come.3
The cause for challenge
Although fuel cell stack systems for heavy duty applications with up to 150 kW per unit exist already, the slowdown of a broad commercialisation is partly based on high technical requirements. The US Department of Energy regularly sets targets indicating what future systems should be able to deliver. The targets for 2030 aim for a lifespan of 25 000 hrs, an efficiency of 68%, and a cost target of US$80/kW. 4 The ultimate target for 2050 requires a further cost drop to US$60/kW and 30 000 operating hrs, which shall lead to a total driving distance of 1 million miles. For comparison, the average durability target for fuel cell passenger cars is only 150 000 miles.
To meet these challenging durability targets, operation strategies and material optimisation need to be addressed. However, translating these overall targets into specific material design criteria for all single components of a membrane electrode assembly (MEA) requires strong collaboration between developers, manufacturers, and OEMs.
EU funded projects like PEMTASTIC use synergies of different partners along the full value chain of a fuel cell
Figure 1. The catalyst coated membrane (CCM) or membrane electrode assembly (MEA) is the heart of the fuel cell. It is where the energy stored in the hydrogen is converted back into electricity. Efficiency and durability of the stack is highly dependent on it.
stack, hereby combining a model-based electrode design approach with the development of materials. By analysing heavy duty truck mission profiles, mandatory realistic test protocols can be defined which allow a rational design of materials specifically developed for heavy duty application.
At the heart of the cell
The ‘heart’ of a fuel cell – the membrane electrode assembly (MEA) – consists of the membrane, ionomer, and the catalyst (Figure 1). The latter is a high-tech material, typically platinum nanoparticles, supported on a conductive carbon material. All these components have their own requirements based on the harsh operating conditions that are seen at heavy duty. Especially elevated operation temperatures (> 95 °C) and a wide range of humidities (relative humidity < 80 %) are drastic conditions that severely foster the degradation of these materials. Therefore, stability is the top priority in material choice. Besides that, to achieve the aforementioned cost targets, a drastic reduction of catalyst costs is required. According to Beyer, the platinum containing catalyst alone accounts for 26% of the total fuel cell stack costs. 5
Such high expectations can only be met by developments specifically tailored for heavy duty vehicle applications. Catalysts need to integrate high intrinsic activity, exceptional stability, and the capability to accommodate high platinum loadings (≥ 50% platinum weight) at the same time. This can only be achieved with an understanding of the interactions between platinum nanoparticles, carbon support, and ionomer within the catalyst structure, as well as its degradation behaviour under different stressors. Whereas the latter is a more fundamental understanding, and a lot of insights are already known from the literature, 6 the effective development of these materials is highly dependent on testing under conditions that closely simulate real-world heavy duty vehicle applications.
Strategies for heavy duty vehicle catalysts
Various strategies have been devised to synthesise platinum on carbon (Pt/C) and platinum alloy on carbon (Pt-alloy/C) catalysts that exhibit remarkable initial activities. Although these approaches seem to be promising, these materials often fail to sustain high performance in long-term durability tests. Additionally, many are based on complex, small scale laboratory synthesis methods that do not transfer to industry-level and cost-competitive production. Therefore, the major deployment of heavy duty vehicle catalysts relies so far on single metal Pt/C materials as they offer the lowest dissolution rates and highest possible stability.
Activity: finetuning the Pt/C nanoparticles
The truth is that the activity increase of pure Pt/C material is limited due to the fact that no additional electronic effects can be established without a second metal. However, the developers in the Heraeus Precious Metals hydrogen labs tuned the activity of Pt/C by creating a design of the nanoparticle size (typically 2 - 4 nm),
its position and distribution on the support material, as well as decreasing any poisoning effects (Figure 2).
However, it must be maintained that these measures have a direct impact – positive or negative – on the platinum particle stability and thus the fuel cell application durability.
Stability: maintaining the balance
Typical degradation mechanisms for Pt/C materials can be summarised as platinum dissolution and Ostwald ripening, agglomeration of platinum particles or even the corrosion of the carbon support, and detachment of full platinum particles. All these degradation mechanisms are significantly accelerated when the average operating temperature of a fuel cell is increased, like in heavy duty fuel cells.
There are already ways to increase the stability of Pt/C with facile and scalable strategies. Unfortunately, measures to increase the stability usually jeopardise the activity. Thus, the
challenge was how to minimise the activity loss while gaining stability (and vice versa).
The Heraeus Precious Metals team are tackling these challenges by combining catalyst design knowledge with the expertise of carbon suppliers, and established feedback loops with testing partners and customers. Despite all the challenges, this combination led to different generations of stabilised Pt/C materials that are able to fulfil the ambitious application requirements.
To compare the stability of various Pt/C materials, the US Department of Energy has set testing conditions and targets which makes it very easy to compare the stability improvement of new generations of materials. The actual target defined by the US Department of Energy is described as the number of cycles which are reached until the initial activity drops by 30 mV (at 0.8 V).4
Standard Pt/C materials usually show a number of cycles below 20 k (see Figure 3). It makes clear that a stabilisation of these materials is needed. After two generations of material development, the team were able to overcome this target level of 30 k cycles set by the US Department of Energy (DOE) with only a negligible loss in activity. However it was evident that, based on the harsh conditions of heavy duty applications, even higher stabilities are needed. The next generation of material which combines different material approaches was able to reach up to 80 k cycles, still with the initial catalyst activity of a high activity Pt/C catalyst. The most recent generation is developed within the previously mentioned EU-funded project PEMTASTIC, where the team designed a completely new type of material. Although it is not yet a commercial product, the team has reported that they were able to reach the 100 k cycle barrier, while even slightly increasing the activity of this material.
What broke the spell?
Those material generations were designed utilising the insights and the team’s experience for Pt/C catalysts to systematically experiment with the available strategies. Step by step, the trade-off between activity and stability was narrowed down with every new generation of catalyst, eventually coming to zero, which resulted in a swing towards improvement in both activity and stability. Pivotal factors influencing this were the model-based design of the materials as well as the synergies gained by being part of the project PEMTASTIC.
Among others, the following strategies were being used in the material development path:
y The smallest platinum particles are always most prone to dissolution and agglomeration. The project team diligently took care of a uniform particle size and increased the initial particles size. At the same time, the nanoparticles were distributed homogeneously on the carbon support. The result was a reduction of the platinum dissolution rate and migration effects.
y Anchoring the nanoparticles on the carbon support structures of high surface area carbons helped against migration and agglomeration of the particles, through limiting the nanoparticles mobility and optimising nanoparticle distance.
y Choosing the right carbon material as the catalyst support has a tremendous effect on the overall catalyst performance. Carbon properties like surface area, porosity, crystallinity, or surface groups directly affect the platinum particle deposition
Figure 3. With every generation of catalyst, the number of cycles increases while the activity rate stays at good levels.
Figure 2. A small scale reactor in the hydrogen lab.
and the reactions within the electrode layer. Several different carbon supports have therefore been tested and new carbon supports have been developed by partners based on the expert’s feedback to find the best combination of carbon and platinum.
Conclusion
The market for heavy duty fuel cells is growing and promising, but also very challenging. Designing heavy duty vehicle materials requires an understanding of the real application requirements
Figure 4. Fuel cell test stations in the hydrogen lab. Testing under realistic conditions is key for development progress.
and synergistic collaborations between material developers, testing partners, and OEMs. It is however possible to fulfil the harsh heavy duty requirements and even outperform the US Department of Energy’s targets by utilising different tools, strategies, and approaches. Nevertheless, even the most promising last generations have to be tested under real-life conditions to validate these findings (Figure 4). Strong requirements can lead to new approaches and solutions which foster the fuel cell market development, especially in the heavy duty automotive segment but also in other mobility applications, such as the maritime and aviation sectors.
References
1. KÖLLNER, C., ‘H2 engine and fuel cell drive in system comparison’, SpringerProfessional, (8 September 2021), https://observatory. clean-hydrogen.europa.eu/index.php/hydrogen-landscape/end-use/ hydrogen-fuel-cell-electric-vehicles
2. ‘Hydrogen Fuel Cell Electric Vehicles’, European Hydrogen Observatory, (2023), https://observatory.clean-hydrogen.europa.eu/index.php/ hydrogen-landscape/end-use/hydrogen-fuel-cell-electric-vehicles
3. RUF, Y., et al., ‘Fuel Cells Hydrogen Trucks’, Ronald Berger, (December 2020), https://horizoneuropencpportal.eu/sites/default/files/2023-09/ chju-study-on-fuel-cells-hydrogen-trucks-2020.pdf
4. MARCINKOSKI, J., VIJAYAGOPAL, R., ADAMS, J., JAMES, B., KOPASZ, J., and AHLUWALIA, R., ‘DOE Advanced Truck Technologies, Program Record #19006’, US Department of Energy, (31 October 2019). https://www.hydrogen.energy.gov/docs/hydrogenprogramlibraries/ pdfs/19006_hydrogen_class8_long_haul_truck_targets. pdf?Status=Master
5. BEYER, U., PORSTMANN, S., BAUM, C., and MÜLLER, C., ‘Production of PEM systems, upscaling, rollout concept’, SpringerProfessional, (2022). https://www.springerprofessional.de/de/produktion-der-pem-systemehochskalierung-rollout-konzept/20310514
6. BÜCHI, F.N., INABA, M., and SCHMIDT, T.J., (eds), Polymer Electrolyte Fuel Cell Durability (2009).
Lightweight composite impellers for centrifugal hydrogen compression
As the European Hydrogen Backbone and other major energy projects within Europe and the whole world develop and promote the use of this alternative energy medium, the requirement to compress large volumes of hydrogen to ensure its distribution and storage become apparent.
In this webinar, Greene Tweed will expand upon the significant challenges of centrifugal hydrogen compression, and introduce the company’s innovative thermoplastic composite impeller, with the goal to use the higher strength-to-weight ratio of this class of materials to increase the rotational speeds of centrifugal impellers to achieve tip speeds of at least 600 m/s, which would enable the (re)compression of pure hydrogen.
24 September 2025 | Live Webinar
Janna Chernetz, Amogy, explores how ammonia-cracking technology has made ammonia a viable, versatile, safe, and scalable source of power for marine transport.
The maritime sector accounts for about 4% of US transportation emissions, according to recent data from the International Maritime Organization (IMO). The sector’s unique operational profile –massive energy demand, long asset life cycles, and global interconnectedness – makes it one of the hardest yet most essential sectors to decarbonise. Fortunately, progress has been made to mitigate greenhouse gas (GHG) emissions in the industry, a recent example being the Maritime Energy and Emissions Innovation Action Plan – a roadmap from the US Department of Energy (DOE) designed to align US ports, vessels, fuels, and workforce with a net zero emissions future by 2050.1 The plan includes guidance about shippers swapping to low-GHG fuels as a strategy to decarbonise.
Among alternative fuels for shipping, one molecule stands out for ocean-going vessels (OGVs): ammonia. Ammonia, with
its high hydrogen density, zero carbon footprint at the point of use, and existing industrial infrastructure, is emerging as a leading hydrogen carrier and a viable marine fuel. Unlike hydrogen in its elemental form, which requires ultra-cold cryogenic storage or high-pressure containment, ammonia can be stored and handled with existing technologies, such as those already in use in the fertilizer and chemical industries.
Cracking ammonia to produce hydrogen fuel
While hydrogen power often takes centre stage, popularised by innovations like Toyota’s 90 kW Mirai car, ammonia’s volumetric energy density makes it a critical component of hydrogen’s potential in the maritime industry. Hydrogen, when used alone as a maritime fuel, is cost-prohibitive due to the need for ultra-low temperatures and high pressures for storage,
Case study: tugboat demonstrates the viability of ammonia power
To showcase the potential of ammonia as a marine fuel, Amogy retrofitted a 1957 tugboat with its ammonia-to-electric power system and sailed the vessel in September 2024, fuelled entirely by ammonia.
The demonstration is the world’s first use of an ammonia-to-power system to power both propulsion and auxiliary systems. This demonstration validated the safety and performance of ammonia cracking technology and underscored its scalability, reinforcing ammonia’s potential as a carbon-free fuel for maritime applications.
Equally important, the project represented a significant stride in regulatory and policy advancement, as Amogy collaborated closely with the US Coast Guard’s Sector New York to secure limited approval for both bunkering operations and the vessel’s demonstration voyage. A regulatory breakthrough for the maritime shipping industry came when Amogy’s NH₃ Kraken marked the first truck-to-ship ammonia bunkering in the US.
Insights gained from the tugboat project will serve as valuable benchmarks for future maritime initiatives.
With the completion of the tugboat demonstration, Amogy is poised to advance towards commercialisation. The company will leverage the knowledge gained to fulfill contracts for building new vessels and retrofitting existing ones in collaboration with some of the world’s leading shipyards and shipping companies.
coupled with significant safety challenges. Research from the University of Pennsylvania’s Kleinman Center for Energy Policy highlights hydrogen’s unique risks, noting that it can “escape even air-tight vessels,” which necessitates an extensive overhaul of maritime infrastructure to ensure safe containment and storage of the universe’s smallest atom.2
Ammonia offers a practical solution as a hydrogen carrier. The ability to crack ammonia into its base elements, nitrogen and hydrogen, offers key benefits. After cracking, the nitrogen can be safely released into the atmosphere, while the extracted hydrogen can then be directed into a hydrogen-to-power conversion system, such as a fuel cell or an engine, to generate electricity.
Ammonia also outperforms hydrogen in energy density and in storage and transportation feasibility. Liquefied ammonia has an energy density of 3.83 MWh/m3, compared to 2.64 MWh/m3 for liquid hydrogen.2 For shipping journeys that can be weeks long, ammonia can better support extensive fuel demands due to its higher energy output. These ships also cannot rely on batteries due to their energy density limits. When the risks associated with hydrogen transport and bunkering are factored into the equation, ammonia as a carrier becomes a more viable alternative to hydrogen alone.
Taking regulatory aim at zero emissions
Ammonia, with its high energy density and role as a hydrogen carrier, offers a promising pathway for decarbonising the shipping industry without compromising its substantial power demands. As a zero carbon fuel, ammonia could play a pivotal role in steering global maritime transport toward
net zero emissions. Current projections from the Ammonia Energy Association note that blue and green ammonia will comprise between 20 - 60% of the shipping fuel mix by 2050.3
In addition to the US’s Maritime Energy and Emissions Innovation Action Plan, the IMO has already initiated critical first steps to remove regulatory barriers to the use of ammonia as a marine fuel, which is an essential move to unlock its potential for shipping decarbonisation. In December 2024, the IMO released international interim guidelines establishing safety standards for ships using ammonia as fuel. This will be followed by a pivotal regulatory change in July 2026, when the IMO plans to delete the current prohibition in the IGC Code that prevents the use of toxic cargo, such as ammonia, as fuel. Further advancing this effort, the IMO is expected to adopt specific guidelines on the use of ammonia cargo as fuel during the 11th session of the Sub-Committee on Carriage of Cargoes and Containers (CCC 11) in spring 2026 with even further revisions expected during CCC 12 in 2027. Together, these actions signal a strong commitment by the IMO to enable the safe and scalable adoption of ammonia fuel in international shipping.
Most recently, on 11 April 2025, the IMO reached a landmark agreement to implement a global carbon tax on shipping emissions, marking a historic first for any international sector to face binding emissions targets. Penalties will range from US$100/t for ships moderately above the standard, and up to US$380/t for those continuing to rely on existing high-emission fuels. The resulting revenues will be allocated to a net zero fund intended to reward low-emission ships, support clean energy R&D, advance the IMO’s climate goals, and assist climate-vulnerable states.
Ammonia power on the water today
While regulation evolves, ammonia-powered systems are fit to meet the needs of shippers and shipyards now, at any stage of the decarbonisation journey. The low-GHG fuel can complement existing combustion engines, which eases the transition to new technologies without requiring a complete overhaul of current infrastructure. These hybrid approaches reduce carbon emissions while familiarising the industry with ammonia’s potential as a primary fuel. For example, ammonia could provide auxiliary power for port operations or onboard electricity generation or even serve as pilot fuel in dual-fuel ammonia engines. This flexibility is critical for shipping companies looking to achieve net zero targets while maximising the value and lifespan of their fleets.
Another positive sign of ammonia’s momentum: there are already vessels built to run on the fuel. According to the Ammonia Energy Association (AEA), 129 ammonia-fuelled vessels and 193 ammonia-ready vessels (which can be converted to NH3 in the future) are in progress. And the number of ammonia power vessels continues to grow as regulatory pressure ramps up.
To support the retrofitting and building of OGVs, global organisations and leaders are taking significant steps to build a robust regulatory framework for ammonia as a fuel. Authorities such as the Norwegian Maritime Authority, Singapore’s Maritime and Port Authority (MPA), and Japan’s Ministry of Land, Infrastructure, Transport, and Tourism (MLIT) are actively developing ammonia bunkering guidelines. Ammonia-cracking technology has proven its potential to deliver a viable, scalable,
Figure 1. The NH3 Kraken is a carbon-free, ammonia-powered maritime vessel which has demonstrated the viability of ammonia as an energy-secure fuel for the shipping sector. The vessel sailed on a tributary of the Hudson River, upstream from New York City, US, in September 2024.
and cost-effective pathway for decarbonising maritime transport, and with progress already being made on fleets of greener OGVs, the chemical is in position to propel the industry toward a cleaner future.
Conclusion
The shipping industry is accelerating its drive to decarbonise, with the IMO setting ambitious targets to achieve net zero emissions by 2050 and codifying measures like carbon fees to hold shippers accountable for their emissions. As the industry
evaluates alternative fuels, ammonia – and specifically its role as a hydrogen carrier – must be a part of the solution.
A key requirement in the energy transition is that industry leaders stop viewing decarbonisation challenges as insurmountable obstacles, but rather as necessary steps to achieve durability of both technology and policy, and the industry needs both for commercial viability. Success in decarbonisation and energy resilience is measured by progress, and progress is well underway.
Ultimately, ammonia stands out as a compelling option for shipowners seeking sustainable solutions. Its abundance, versatility, and scalability make it a practical and cost-effective fuel, offering several realistic pathways to adoption in the maritime industry’s journey toward a greener future.
References
1. ‘An action plan for maritime energy and emissions innovation’, US Department of Energy, (December 2024), https://www. transportation.gov/sites/dot.gov/files/2024-12/Maritime%20Plan. pdf
2. SERPELL, O., HSAIN, Z., CHU, A., and JOHNSEN, W., ‘Ammonia’s Role in a Net-Zero Hydrogen Economy’, Kleinman Center for Energy Policy, (March 2023), https://kleinmanenergy.upenn.edu/wpcontent/uploads/2023/03/KCEP-Digest53-Ammonias-Role-Net-ZeroHydrogen-Economy.pdf
3. ATCHISON, J., ‘IEA: ammonia key to decarbonising shipping by 2050’, Ammonia Energy Association, (3 October 2023), https:// ammoniaenergy.org/articles/iea-ammonia-key-to-decarbonisingshipping-by-2050/#:~:text=Together%2C%20%E2%80%9Cblue%20 and%20e%2D,figure%20to%20the%20IEA%20report)
