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Autumn 2026 Volume 5 Number 3 ISSN 2977-1927 23 Liquid hydrogen: from plant to port

03 Comment

Daniel Patrick, Atlas Copco Gas and Process, explores the compressor and expander technologies that can support the liquid hydrogen value chain.

04 Building confidence in Europe’s

hydrogen economy

Magnus Killingland, DNV, examines the growth of the European market and the new challenges producers and governments face.

27 The challenge of cryogenic hydrogen

Katsuyuki Takano, Ebara Elliott Energy, analyses how return gas blowers can be designed to safely manage liquid hydrogen during storage and transfer.

Magnus Killingland, DNV, examines the growth of the European market and the new challenges producers and governments face.

31 A source of energy and hope

he global hydrogen market is one that has the potential to scale significantly from where it stands today, even with lower earlier forecast predictions. As an energy carrier, hydrogen will not compete on cost with electrification where electricity is feasible, but it still remains one of the few viable solutions for decarbonising hard to electrify sectors such as steel, chemicals, shipping, and aviation. DNV’s ‘Energy Transition Outlook 2026: Hydrogen to 2060’ report, predicts that overall hydrogen volumes will grow by 170% and see cumulative investments of US$3.2 trillion through to 2060. This is despite a significant downward revision in the demand and uptake of hydrogen from the previous research conducted in 2022. Analysis points to China leading that expansion, and accounting for 35% of new hydrogen production and use over the forecast period. Looking to Europe, a sizeable growth in demand is also anticipated, with demand from European countries for hydrogen trebling by 2060, reaching 35 million t. Despite being poised for growth, the hydrogen market is still in a fragile position. The current and future clean hydrogen capacity will largely be driven by policies and implementation of legislation, meaning projects are proceeding only where credible, policy-backed demand exists.

Tobias Moss, Dräger, Germany, describes how safety enables profitable hydrogen scale-up.

35 Managing oxygen risks in high pressure

hydrogen systems

Ariel Kigel and Galina Gurina, Modcon Systems, explain the risks posed by oxygen ingress in high pressure hydrogen systems, discussing how measurement integrity can mitigate this.

04 4

41 Improving thermal efficiency in steam

methane reformers

10 The emerging hydrogen backbone

Anton Korobeynikov, Integrated Global Services (IGS), Czech Republic, presents case studies outlining strategies for the improvement of existing steam methane reformer assets.

Jens Conrad, Everfuel A/S, Denmark, discusses large scale green hydrogen production in Denmark and pipeline export to Germany.

15 Shifting the focus from hydrogen ambition

45 Reliability you can depend on

Romeu Kleinubing, Emerson, USA, details how hydrogen producers must plan predictive maintenance and safety strategies early to successfully compete projects at scale.

to infrastructure reality

Erwan Bruneau, Air Products, investigates how refuelling stations can be designed to scale hydrogen deployment across Europe’s transport and industrial sectors.

19 Unlocking global hydrogen trade at scale Priyan Mistry, Honeywell Technologies, details how ammonia is the key to unlocking hydrogen transportation to support the global hydrogen economy.

49 The pipeline to the future

Garry Hanmer, Atmos International, UK, explains how advanced AI algorithms are transforming hydrogen pipeline monitoring and safety.

53 Switching on net zero at sea

Danny Nicholas, Rotork, UK, provides insight into how electrification and digitalisation support maritime decarbonisation with hydrogen and other alternative fuels.

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s the summer months come to an end in the northern hemisphere, so too does the season of music festivals. In the absence of the UK’s largest festival, Glastonbury, this year – 2026 is a planned fallow year to let the farmland rest and regenerate (not that the repeated heat waves helped much with that) – attention turned to some of the country’s smaller festivals. And one in particular made the headlines for its boundary-pushing approach to sustainability (as well as music). Boomtown in Hampshire – just 25 miles or so from where our offices are based – introduced a new main stage at this year’s event, powered entirely by green hydrogen. The HydroXL stage, which was headlined by Four Tet and Skrillex (no? me neither), was one of the festival’s three main stages, with an audience capacity of 20 000. The festival’s hydrogen journey started back in 2022, when Hydrologiq deployed a hydrogen-powered generator to power the public transport hub for the week preceding the festival and all four days of its runtime. Last year’s smaller ‘Hydro’ stage was powered by hydrogen fuel cell generators, and the installation was managed once again by Hydrologiq (now known as Logiq Systems). For the ‘XL’ version of the Hydro stage launched this summer, Boomtown partnered with Geopura, which delivered its HPU2 high-capacity hydrogen power unit to the site. The system uses Ballard hydrogen fuel cells to convert green hydrogen back into clean electricity, with water as the only by-product at the point of use. Speaking prior to this year’s event, Boomtown’s Co-Founder and CVO, Luke Mitchell, was clearly impressed with the success of 2025’s Hydro stage: “Personally, I spent a lot of time behind the stage as it was fascinating to see. Where you would normally hear diesel generators, there was just silence, with nothing but water vapour as the by-product, and the water was so pure you could drink it. It inspired us to take the leap and develop the idea into one of our main stages this year.” The concept of ‘taking the leap’ is pertinent to the wider hydrogen sector, which is itself moving from demonstrations and smaller scale projects towards larger, industrial scale deployment. And Mitchell’s explanation of the festival’s ambitions have relevance far beyond the entertainment industry: “It’s a significant investment to pull this off and a real journey this year to prove it works on this scale. GeoPura’s ability to produce truly green hydrogen using renewable energy is another important factor, not just for Boomtown, but for the wider events industry who we hope to see adopting this technology too. It’s crucial that others with resources in our industry invest in this new green technology, so we reach a point where it’s achievable for all to use.” The call for increased investment could be applied to the wider hydrogen economy. The industry needs to keep taking the next step – scaling production, developing infrastructure, building demand, and bringing costs down – if hydrogen is to move from early commercial deployments towards widespread adoption. Boomtown took its Hydro stage and made it XL. Our industry must follow suit.

Magnus Killingland, DNV, examines the growth of the European market and the new challenges producers and governments face.

And it is exactly this lack of implementation of legislation from ambitious policies which has led to DNV’s downwards adjustment of the sector’s future. If legislation and a lack of incentive stand in the way of ambitions, it will be increasingly difficult to scale investment in new projects.

A European outlook

Forecasting shows that despite the challenges the industry faces, there are signs of progress becoming clearly visible, as pilot projects show promising results, the first implementation of legislation moves forward in leading countries, and investment decisions are made. Albeit these decisions are at a smaller scale than what had originally been planned, they represent important steps towards building a more resilient and secure energy system. Beyond its role in decarbonising hard-to-abate sectors, hydrogen is increasingly viewed as a strategic energy security asset, offering a pathway to reduce dependence on imported fossil fuels, diversify energy supply chains, and strengthen the competitiveness of energy-intensive industries. DNV’s own research has found that, as of December 2025, around 0.5 GW of hydrogen capacity is now operational in Europe and a further 4.5 GW is post-financial investment decision (FID), with refining accounting for around half the total offtake.

Figure 1. European hydrogen demand by sector.

Analysis has discovered that European hydrogen demand will more than triple by 2060 (Figure 1), and all of Europe’s 35 million t of hydrogen consumption will be decarbonised, mostly through domestic renewable hydrogen. However, there will still be important roles for imports from regions with low-cost abundant renewable resources. This diversified supply approach will be critical for reducing reliance on individual suppliers while enabling Europe to benefit from competitive renewable energy resources globally. Europe will also benefit from low-carbon blue hydrogen production with carbon capture. Exemplifying this are low-carbon hydrogen projects such as H2BE, a blue hydrogen project in Belgium co-developed by Engie and Equinor, and Yara International’s flagship blue hydrogen-based ammonia plant in the Netherlands. Looking at green hydrogen, cost premiums compared to fossil hydrogen will be closed faster in Europe than other regions thanks to a rising carbon price. However, mandates and additional support such as Contracts for Difference (CfD) and investment support will be needed until 2040 to bridge the gap. The implementation of policies to support the wider scaling of hydrogen adoption, while limited, is making a difference. European blending mandates for transport fuels have done much to support the refinery businesses cases and important projects are being backed by European Hydrogen Bank and national government production subsidies, but it is important to note that they are not being enforced for industry, or adopted by all member countries. Interestingly, funding is being organised on a transnational basis now. For example, financing for hydrogen production projects in Denmark is supporting the planned hydrogen pipeline to Germany. Looking at the UK hydrogen market, the country’s strategy has been delayed and is now expected to be expanded upon by the end of 2026. However, the government has progressed low-carbon hydrogen through its Hydrogen Allocation Rounds and Low Carbon Hydrogen Agreements, moving towards an ambition of having up to 10 GW by the end of the decade. The government has also been developing transport and storage business models and has conducted consultations on hydrogen blending.

The new risk landscape

Figure 2. At DNV’s Spadeadam testing and research facility in the UK, experts examine large scale pipeline rupture testing, venting and flaring, ignition consequence, and gas accumulation to better understand the risks involved with hydrogen.

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Autumn 2026

As global hydrogen projects move from pilot sites to becoming industrial scale assets, many would think that a simple expansion of the pilot is all that is required, but this is not the case. With this growth comes new failure modes that emerge from shared systems, dynamic grid operation, and complex interfaces between suppliers, constructors, regulators, lenders, and operators. The industry has learned a great deal from the early deployment of smaller pilots, largely in 1 - 10 MW projects, about equipment behaviour, safety margins, performance, and degradation. But as the sector advances towards 100 and 500 MW facilities, and even the first GW scale hubs, the knowledge gained from these smaller projects is proving insufficient as design logics fail to transfer over, proving that it is not a copy-and-paste

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exercise to move from pilot to scale. This is why the learning rates are lower compared to solar and batteries, and that development takes time. The increased costs associated with ‘balance-of-plant’ technologies when plants scale, can become a source of complexity and even possible downtime if not designed and operated correctly. Alongside technology costs, the size and complexity of CAPEX financing rises significantly in tandem with the size of the project. Uncertainties around stack lifetime, degradation under variable loads, and spare part availability all add intricacies to project underwriting.

Closing the confidence gap when moving to industrial scale

De-risking is the primary enabler of bankability and cost reduction for large scale hydrogen projects. A structured plan for risk management, implemented as early as possible, is a critical step in closing the gap between technical capability and investor confidence, and as the technology develops, so too must the standardisation needed to bring costs down at scale. Safety must be paramount throughout. As production scales, process safety expertise and culture must grow in lockstep. A 2023 DNV-supported study from the Institute of Sustainable Process Technology examined the current knowledge of hydrogen-related safety issues, highlighting that an ambitious production ramp-up creates a necessity for the industry to safeguard process safety across the design, implementation, and operation phases. Aimed at preventing and controlling large scale industrial accidents, process safety is an oft-misunderstood discipline, even by the most experienced of engineers. To achieve this, it is prudent to solve the misalignment of responsibility across the hydrogen supply chain. Developers typically assume that process safety is embedded in the systems delivered by manufacturers and engineering, procurement, and construction (EPC) contractors. Manufacturers and EPCs, in turn, rely on developers to specify what safety requirements must be met. With neither party fully defining or owning the problem, critical safety considerations can be left unaddressed. This, however, is not a failure of intent, but of clarity. All stakeholders in the chain want to deliver successful projects, but in a commercial environment where scope is defined by what is explicitly requested, any requirement that is not clearly specified is unlikely to be delivered. This may result in a systemic accountability gulf that should be bridged by the project developer, as the most effective point of intervention. They must ensure they issue clear, technically grounded specifications at the procurement stage, setting out what process safety documentation and evidence is required, instead of accepting whatever a supplier delivers. To remove risk from larger projects, early and deep engagement with the relevant authorities is a necessity. This includes clear design and interface responsibilities with advanced barrier management, new and updated sensors and alarm trigger algorithms, more standardisation across OEMs and EPC organisations, independent technical and safety reviews, and stronger operational readiness practices.

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Autumn 2026

DNV’s experts are deeply rooted in the development of hydrogen projects across Europe and around the world, carrying out risk assessments and due diligence, advising on electrolyser technologies, and verifying facilities and equipment against regulatory requirements. One recent example involved DNV carrying out a technology assessment, operational benchmarking, and safety advisory for RWE’s 300 MW GET H2 Nukleus development in Germany, which provided a robust decision basis for RWE to advance the project. DNV’s work in this space is underpinned by data gathered across its laboratory sites, including its Spadeadam testing and research facility in the UK, where experts conduct large scale pipeline rupture testing, venting and flaring, ignition consequence, and gas accumulation to build a greater understanding of the risks involved with hydrogen. Alongside Spadeadam, the company’s Technology Centre in Groningen, the Netherlands, supports the testing of industrial burners for blends and 100% hydrogen, covering product quality, NOX emissions, hydrogen purity and metering. This includes the H2MET joint industry project, which brings together global gas network operators including Gasunie, BP, Shell, and Aramco, alongside flow meter manufacturers such as Emerson, Endress+Hauser, and Siemens, to advance hydrogen flow metering, which is critical for accurate measurement of hydrogen volumes.

Moving forward

Clean hydrogen will play a niche, but indispensable, role in the energy transition for hard-to-electrify sectors, and its advancement depends on implementation of ambitious policies. There is no mature ‘one-size-fits-all’ approach towards deploying policies to support hydrogen sector development. Different countries must establish suites of measures tailored to their specific circumstances and resource endowments, alongside factors such as their ambitions to either import or export, or the political feasibility to provide incentives to decarbonise. What all countries do have in common is a significant cost differential between conventional and clean hydrogen. Where cost-reduction prospects remain uncertain, any significant ramp-up of projects relies on government policies and incentives for both production and demand, as well as for the related infrastructure. Carbon pricing will also play a crucial role in growing uptake and enhancing hydrogen’s competitiveness, but current pricing schemes are too volatile and often too low to foster meaningful investment. Regulatory clarity and structure for hydrogen are now evolving across all levels of safety and sustainability legislation, and early-adopter nations are in a position to lead the way, achieving consensus for how things can proceed and sharing workable solutions for any challenges that arise. Recent years have evidenced the coordination it takes to successfully build up a clean hydrogen sector, but when the right knowledge, policy, and effort are implemented in the right place and at the right time, hydrogen can be one of the most effective tools to not only decarbonise hard-to-electrify sectors, but bolster Europe’s energy security.

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Jens Conrad, Everfuel A/S, Denmark, discusses large scale green hydrogen production in Denmark and pipeline export to Germany.

urope’s green hydrogen market is at a crossroads. The hype of recent years is apparently over and reconsolidation is well underway. Significant projects have proven that the production of renewable hydrogen via electrolysis is viable. The next steps are, however, more challenging. Can large scale hydrogen production operate reliably, flexibly, and economically enough to serve industrial customers through cross-border infrastructure? Is the demand side ready to receive large quantities of hydrogen? How can the necessary infrastructure be put in place? The HySynergy project in Fredericia, Denmark, and the planned Frigg project in Vejen illustrate this transition from site-level demonstration to large scale hydrogen export. Germany is central to this story. Its hydrogen import strategy expects national demand for hydrogen and hydrogen derivatives to reach 95 - 130 TWh/yr by 2030, with 50 - 70% of this demand expected to be covered by imports. By 2045, hydrogen demand alone is projected to reach 360 - 500 TWh/yr, in addition to around 200 TWh of hydrogen derivatives. The government expects the share of imports to increase further after 2030.1 Denmark is explicitly among the expected supplier countries, alongside Norway and the UK. For German steel, refining, chemicals, e-fuels, and heavy transport, imported renewable hydrogen is not a niche topic; it is one of the enabling conditions for decarbonisation. Denmark’s role is equally strategic. Western Denmark has strong wind resources, grid interconnections, potential hydrogen storage, and proximity to northern German demand centres. The emerging Danish Hydrogen Backbone is intended to connect renewable power-based hydrogen production in Jutland with domestic demand and export routes to Germany.

Current plans for Danish Hydrogen Backbone 1 (DHB1) foresee a combination of newly built hydrogen pipeline and repurposed existing gas infrastructure in western Denmark. Energinet opened the DHB1 capacity sale via PRISMA on 30 January 2026, offering transport capacity for the period from December 2030 to January 2046. The first phase includes new and converted pipeline sections, with commissioning currently expected around the end of 2030.2

HySynergy: large scale hydrogen production

With 20 MW, HySynergy is Everfuel’s first large scale hydrogen production. The project is adjacent to the Crossbridge Energy refinery. HySynergy I is co-owned by Everfuel and Hy24, one of the world’s largest hydrogen private equity asset managers, with Everfuel holding a majority stake. HySynergy I consists of a 20 MW alkaline electrolyser supplied by Nel with a production capacity of up to 8 tpd of green hydrogen, powered by renewable electricity. These figures show that HySynergy is above laboratory and pilot scale. However, it is yet still below the future GW scale projects being planned for pipeline export, like Frigg. After making a final investment decision (FID) and entering execution phase of the project at the end of 2020, HySynergy was one of Europe’s largest electrolyser projects at that time. Many obstacles were encountered – some expected,

Figure 1. Overview of HySynergy with trailer filling.

Figure 2. The production hall of HySynergy.

GlobalHydrogenReview.com

Autumn 2026

some not. One of the key lessons from this project was that the critical path is not only the electrolyser procurement. The balance of plant, grid connection, distribution infrastructure, operational procedures, safety systems, and control architecture can be equally decisive. In February 2025, the first production and delivery of hydrogen from HySynergy to the Crossbridge refinery was accomplished. This was the initial step towards stable operations and production ramp-up. With Crossbridge being a significant user of hydrogen, production reliability was early on one of the main focuses. Replacing fossil-based hydrogen with renewable hydrogen in such processes is one of the most realistic early industrial use cases, particularly where the hydrogen can be delivered directly into an industrial offtake system. The second industry in focus is mobility. HySynergy is equipped with a distribution centre consisting of five trailer bays enabling Everfuel to deliver hydrogen to mobility customers via a ‘mobile’ pipeline. For this purpose, Everfuel is currently operating ten 380 bar trailers. HySynergy was formally inaugurated in November 2025. It is still among Europe’s largest green hydrogen production projects, supported by €6.5 million from the Danish Energy Agency and €3.8 million from the EU Connecting Europe Facility. The inauguration highlighted a concerted effort to establish more than 2 GW of electrolysis capacity in Denmark by 2035.

Lesson learned: flexibility has value

Since December 2025, HySynergy has been used to provide balancing services to the power grid while producing certified green hydrogen. This makes HySynergy the first large scale electrolyser plant worldwide to do so. The integration involved Everfuel, Energinet, and Centrica, with the plant participating in Automatic Frequency Restoration Reserve (aFRR) balancing. For the hydrogen sector, this is a major operational signal. Large electrolysers are often discussed as static industrial loads: connect renewable power, run at high-capacity factor, and minimise hydrogen cost. In real power systems dominated by wind and solar, that model is incomplete. Flexible electrolysis can absorb electricity when supply is abundant and reduce demand when the system needs balancing. This helps the electricity system accommodate variable renewable generation. Thus, the transition to renewable energies, with its fluctuating power supply is highly dependent on balancing and storage capacity. Electrolysers producing hydrogen are a perfect fit for this requirement. The long-term storage of large amounts of energy is currently – and will most likely continue to be in the future – only possible using molecules, not electrons. However, flexibility is not free. A plant designed for balancing must manage ramp rates, equipment lifetime, hydrogen purity, compression dynamics, storage buffer levels, offtake nominations, and certification constraints. The HySynergy experience shows that electrolyser stack performance is only one part of the business case;

dispatch optimisation, grid services, forecasting, and commercial trading interfaces are increasingly central. The HySynergy project was a long and arduous journey with a steep learning curve. However, it proved useful for understanding the experiences and competencies needed for the next strategic step towards large scale hydrogen production.

From HySynergy to Frigg: scaling from local offtake to pipeline supply

Frigg is the planned large scale successor to the HySynergy project. In June 2024, Everfuel submitted a project proposal for phased development of up to 2 GW of green hydrogen production capacity at Revsing Energy Park in Vejen. The project is intended to become Everfuel’s first large scale production facility dedicated to hydrogen supply via pipeline to industrial customers in Europe. Frigg is strategically located close to one of Denmark’s largest transformer station and within the area of the hydrogen backbone. It is planned to be expandable by up to 2 GW of electrolyser capacity, with a potential direct connection to local renewable generation from solar and wind and integration with district heating. Although not operational yet, there is already interest, especially from German industry. A letter of intent (LoI) for the initial supply of up to 10 000 tpy of green hydrogen supplied by Frigg is already in place. In May 2026, Frigg received notification of production support under the European Hydrogen Bank’s Auctions-as-a-Service mechanism. The award corresponds to €0.98/kg of hydrogen and €244.9 million for 200 MW of electrolyser capacity in the first phase of the project. This support is significant, but not sufficient on its own. The next key milestone is booking capacity in the Danish Hydrogen Backbone, while noting that commercial and regulatory conditions around the capacity booking framework still needed clarification. It became apparent that hydrogen project development is no longer primarily about announcing electrolyser capacity; it is about aligning renewable power, production support, pipeline capacity, and bankable offtake.

Pipeline infrastructure: the enabling constraint

The Danish-German pipeline is the central infrastructure condition for Frigg’s export model. In September 2025, Denmark had approved moving the Syvtallet pipeline project from Esbjerg via Egtved to Frøslev at the German border into the construction phase. The pipeline is planned at approximately 133 km, using both new segments and converted gas infrastructure, with an export capacity of around 3 GW and a target readiness date of 2030.3 For developers and offtakers, the pipeline creates both opportunity and risk. Once operational, it can unlock volumes that trailer distribution cannot handle economically. It can also reduce logistics complexity, enable firm industrial supply and integrate Danish renewable resources with German demand. But if pipeline timing, tariff design or capacity booking terms remain uncertain, upstream projects may struggle to reach FID. Furthermore, it is a misconception that with a pipeline all transport cost will vanish. Depending on the purity and pressure level required, the hydrogen extracted from a pipeline needs to be cleaned and compressed: contributing to the tariff costs for the pipeline use.

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Best practices for large scale hydrogen production and export

In recent years, Everfuel has gained extensive experience in the development and implementation of large scale electrolysis projects. Some of the key points are: y First, design production assets for flexible operation from day one. HySynergy’s aFRR participation indicates that future electrolysers should be capable of responding to power market signals while maintaining hydrogen quality and offtake reliability. This requires integrated control systems, sufficient buffer storage, and commercial optimisation tools. y Second, safe hydrogen operation depends on organisational systems as much as hardware. y Third, choose a location intelligently. HySynergy benefits from proximity to a refinery offtaker and district heating demand. Frigg is being positioned near grid infrastructure, renewable generation potential and the hydrogen backbone. Good siting reduces electrical, thermal, and logistics losses. y Fourth, secure offtake and transport capacity together. A hydrogen producer without transport rights is exposed; an offtaker without production commitments is equally exposed. y Finally, build for certification. Customers will require traceability, RFNBO compliance, and credible emissions accounting. Operational flexibility must therefore be aligned with certification rules, not added later.

Outlook

HySynergy and Frigg represent two phases of the same learning curve. HySynergy shows that 20 MW-class electrolysis can move from production to industrial delivery, district heating integration and grid-balancing participation. Frigg aims to convert those lessons into pipeline scale export, starting with a supported 200 MW phase and a long-term pathway towards 2 GW. The opportunity is substantial. Germany needs large volumes of hydrogen, while Denmark has renewable resources and a developing export backbone. The risk is also substantial: infrastructure delays, insufficient capacity bookings, uncertain offtake, and cost pressure could slow deployment. The practical conclusion is clear: Europe’s hydrogen economy will not be built by electrolysers alone. It will be built by integrated production hubs that combine renewable power, flexible operation, heat recovery, certification, industrial offtake, and cross-border pipeline access. HySynergy provides operating evidence. Frigg will incorporate this experience into a German-facing hydrogen export business. If the Danish-German backbone reaches operation around 2030, and if producers and buyers can align long-term commitments, then Denmark will become one of Germany’s most important early pipeline suppliers of renewable hydrogen.

References

1. ‘Import Strategy for hydrogen and hydrogen derivatives’, Bundeswirtschaftsministerium, (2024), https://www. bundeswirtschaftsministerium.de/Redaktion/EN/Hydrogen/Downloads/ importstrategy-hydrogen.pdf?__blob=publicationFile&v=1, (accessed on 1 July 2026). 2. ‘Capacity Sales for Denmark’s Upcoming Hydrogen Infrastructure Have Opened’, Fuel Cell Works, (2026), https://fuelcellsworks. com/2026/01/30/hydrogen/capacity-sales-for-denmark-s-upcominghydrogen-infrastructure-have-opened?utm_source=chatgpt.com, (accessed on 1 July 2026). 3. ‘Newsletter 05-09-2025’, Enerdata, (2025), https://www.enerdata.net/ publications/daily-energy-news/denmark-greenlights-construction-3gw-hydrogen-pipeline.html?utm_source=chatgpt.com, (accessed on 1 July 2026).

Erwan Bruneau, Air Products, investigates how refuelling stations can be designed to scale hydrogen deployment across Europe’s transport and industrial sectors.

urope’s hydrogen economy is entering a critical phase. The strategic rationale for hydrogen is well established in sectors where direct electrification is constrained, particularly in heavy-duty transport and selected energy-intensive industrial processes. Hydrogen also remains essential as a process gas or feedstock in a range of industrial applications. The key question is no longer whether hydrogen has a role to play, but how sustainable hydrogen supply chains can be integrated to support new applications at commercial scale. This transition is proving more complex than early expectations suggested. Across Europe, hydrogen markets are evolving along different pathways, shaped by varying regulatory environments, end-use requirements, and infrastructure constraints. Transport, industry, maritime, and even aviation are advancing technologies that use renewable and low-carbon hydrogen, while regulatory

environments continue to evolve and have yet to fully keep pace with deployment. At the same time, infrastructure must be designed with safety and scalability at its core, enabling it to support growing demand and accommodate both gaseous and liquid hydrogen. This is where the focus shifts from ambition to implementation. Supply alone does not create markets; what matters is how effectively hydrogen is delivered from production to end use, suited to its application, and with robust certification in place. The next phase of deployment will be defined by the quality and reliability of these systems.

Hydrogen markets are forming – but not uniformly

Policy is beginning to create demand signals across multiple sectors. Yet these signals do not produce a uniform market. Instead, hydrogen is increasingly differentiated by classification, certification status, and application. Its use

depends not only on its availability, but also on whether it qualifies within specific regulatory frameworks. This has practical implications for infrastructure. Supply must be aligned to the needs of the end user, often with strict traceability requirements. A refinery, a municipal bus depot, and a logistics hub each require different approaches. Implementation remains challenging because infrastructure must serve emerging markets while anticipating future scale. Projects are capital-intensive, depend on long development cycles, and require coordination across stakeholders. As a result, hydrogen deployment is shaped not only by technical readiness, but also by confidence in regulatory and commercial frameworks.

The growing role of liquid hydrogen

As hydrogen markets develop, liquid hydrogen is playing an increasingly important role. Its higher energy density compared with gaseous hydrogen makes it more efficient to store and transport over longer distances. It can also offer advantages when integrated into end-use applications, requiring less space and no need for on-site compression. These advantages are relevant across multiple sectors, not just mobility. Industrial users, electronics manufacturers, and aerospace applications all benefit from reliable, high-density hydrogen supply. In each case, infrastructure design is shaped by practical constraints such as available space, delivery frequency, and operational reliability.

This also enables supply to be decoupled from demand. Hydrogen no longer needs to be produced close to where it is used but can be transported between regions. Large scale liquefaction facilities, such as Air Products’ facility under construction in Rotterdam, the Netherlands, play an important role in enabling this by linking production with demand across wider geographies. In practice, this influences how infrastructure is designed and operated. Liquid hydrogen enables larger volumes to be delivered less frequently and can reduce on-site footprint where space is limited, while improving overall supply efficiency. As a result, it helps bridge the gap between technically feasible supply and commercially viable operation.

Refuelling infrastructure as a system-level test

Hydrogen refuelling stations provide a clear lens through which to understand these dynamics. They sit at the intersection of production, logistics, storage, dispensing, and end-user operations. As such, they reflect many of the challenges facing the hydrogen economy more broadly. There is no single standard approach to station design. Configurations vary depending on the application, with different use cases requiring different technical set-ups. Depot-based bus stations, multi-use municipal hubs, and public heavy-duty stations each require tailored solutions based on refuelling volumes and usage patterns. As utilisation increases, infrastructure needs to be more closely aligned to specific use cases, rather than relying on generic designs. Pressure levels, dispensing rates, storage concepts, and supply models must all be aligned with operational requirements. Moving beyond generic designs towards more tailored solutions is a necessary step in scaling hydrogen systems.

Depot-based stations: throughput and reliability

Figure 1. Air Products HRS and MAN ICE truck.

Figure 2. Air Products HRS Crawley, UK.

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Autumn 2026

However, liquid hydrogen is not the default solution in all cases. For many applications today, particularly those with defined, high-utilisation demand, gaseous systems remain a practical and efficient option. Bus depots are one of the most established early use cases for hydrogen. Where operations are centralised, demand is predictable, and refuelling can be integrated into fixed schedules. In this context, the priority is reliable throughput rather than flexibility. The Air Products hydrogen refuelling station in Meckenheim, Germany, illustrates this approach. Designed to refuel up to 50 buses per day, it uses 350 bar dispensing supported by high-pressure (640 bar) trailer supply, eliminating the need for on-site compression. This design reduces complexity while maintaining operational performance. Compression systems can be energy-intensive and maintenance-heavy; avoiding them at the customer’s site improves reliability. Features such as pre-cooling and parallel or back-to-back dispensing support fast, high-throughput refuelling, further enhancing efficiency.

Meckenheim shows that infrastructure must be designed around real operations. Stations must support fleet schedules, minimise dwell times, and deliver consistent performance rather than simply meeting theoretical capacity metrics.

Liquid hydrogen storage for gaseous systems: bridging supply and use

An emerging station concept combines liquid hydrogen storage with gaseous dispensing. This approach leverages the logistics advantages of liquid hydrogen while maintaining compatibility with current vehicle technologies. This decouples supply logistics from dispensing requirements. Hydrogen is delivered in liquid form, stored cryogenically, and then vaporised for dispensing at typical pressure levels such as 350 bar for heavy-duty vehicles or 700 bar for passenger vehicles. This approach minimises energy demand by enabling the use of efficient cryogenic high-pressure (CHC) pumps, allowing hydrogen to be handled internally in its liquid state, with vaporisation as the final step in the process before dispensing to the refuelling nozzle. The benefits are clear. Liquid hydrogen use reduces delivery frequency and improves supply efficiency, while gaseous refuelling ensures compatibility with existing vehicle platforms. This configuration is already being deployed in real-world operations, such as the Metrobus bus depot in Crawley, UK, where Air Products’ liquid hydrogen supply supports gaseous refuelling of the largest H2 bus fleet in the UK. It represents a practical intermediate step between purely gaseous infrastructure and fully liquid refuelling systems. Hybrid systems may play a crucial role in market development, allowing operators to benefit from expanding liquid hydrogen supply chains without requiring immediate changes to vehicle technology.

Multi-use stations: improving utilisation

Multi-use stations are designed to serve multiple vehicle classes from a single site. This approach is particularly relevant in regional markets where demand is still emerging and utilisation rates are critical. The Air Products hydrogen refuelling station in Hürth, Germany combines 350 bar and 700 bar refuelling, supporting buses, municipal vehicles, and passenger cars. While this adds complexity to the station design, it also reflects a forward-looking approach, helping to prepare infrastructure for future applications, including the potential adoption of 700 bar heavy-duty vehicles. Such flexibility can support station utilisation during early market development, although demand across vehicle segments is still evolving. It also provides resilience in the ramp-up phase, when no single fleet type may justify dedicated infrastructure on its own. Multi-use stations illustrate an important early-phase consideration: infrastructure design must balance current demand with future requirements. As the market matures, solutions can become more tailored, but at this stage, enabling scalability and readiness for emerging applications remains a key factor.

Figure 3. Air Products HRS Hürth, Germany.

Figure 4. Air Products HRS Meckenheim, Germany.

Mobile refuelling solutions: enabling early deployment Mobile hydrogen refuelling solutions provide an additional pathway for early market development. Available for both gaseous and liquid hydrogen, they offer a flexible means of supplying vehicles where permanent infrastructure is not yet justified or where demand is still being tested. This makes them particularly well suited to pilot projects, temporary operations, and early deployment phases, as well as supporting OEMs during vehicle testing and validation campaigns. Their value lies in adaptability. Mobile solutions can support a wide range of vehicle applications, from trains and refuse collection vehicles to terminal equipment such as straddle carriers used in ports. In these cases, they enable operators to begin practical testing under real operating conditions without waiting for fully built-out fixed stations. From an infrastructure perspective, mobile systems can also serve as a bridge to permanent deployment. They allow refuelling profiles, throughput requirements, safety procedures, and site interfaces to be validated before larger capital investments are made.

Shared-access stations in logistics hubs

In logistics hubs and ports, hydrogen infrastructure must serve multiple users efficiently. Shared-access

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stations address this requirement by providing common infrastructure that can be used by different fleets and operators. In environments such as Rotterdam, publicly accessible stations support both dedicated fleets and third-party users. This reduces duplication of infrastructure and improves overall network efficiency. In parallel, integrated solutions that connect hydrogen production, refuelling infrastructure, and distribution logistics are helping to establish more cohesive hydrogen value chains. In the Port of Rotterdam, for example, hydrogen from a single production source is used to supply a public refuelling station, fill trailers for onward distribution to other stations and industrial users, and support a fleet of hydrogen-powered delivery vehicles. This approach demonstrates how shared supply infrastructure can serve multiple applications simultaneously, linking mobility and industrial demand. By reducing fragmentation and making use of common assets, such integrated concepts can accelerate market development and support the emergence of local hydrogen ecosystems at scale. In the long-term, such sites may evolve into integrated energy hubs, linking road transport with industrial use, maritime applications, and potentially bunkering operations. Their value therefore extends beyond refuelling to system integration.

Liquid hydrogen stations for long-haul transport

Long-haul heavy-duty transport presents distinct requirements: long range, fast refuelling, and high energy density. Under these conditions, gaseous hydrogen systems may become constrained.

At the same time, OEMs are advancing projects for heavy-duty trucks powered by liquid hydrogen, further highlighting the potential of this pathway for long-haul applications. Stations designed for liquid hydrogen fuelling store and dispense hydrogen in cryogenic form, enabling higher storage density and faster refuelling. This configuration reduces further the footprint and power used by the station. The vehicle advantage is performance. Liquid hydrogen can support longer vehicle ranges and shorter refuelling times, making it well suited to long-haul transport where downtime has direct economic implications. Rather than replacing gaseous systems, liquid hydrogen introduces an additional pathway. Different station types can coexist, each suited to specific applications. The future of hydrogen refuelling infrastructure is therefore a portfolio of solutions rather than a single standard.

Remaining challenges: certification, permitting, and confidence

Certification of hydrogen is a key constraint to the development of its usage. In regulated markets, hydrogen must meet defined criteria to qualify for specific applications. This makes traceability and verification essential. Infrastructure must therefore support not only physical delivery but also the data and certification required to demonstrate compliance with low-carbon and renewable hydrogen criteria. The ability to demonstrate compliance is increasingly central to project viability. Confidence remains a key constraint. Hydrogen infrastructure requires long-term investment and coordination across multiple stakeholders, but projects depend on both predictable demand and reliable supply. Addressing this interdependence requires stable policy frameworks that provide clear and consistent market signals. Where uncertainty persists, projects can stall if the right conditions are not in place. Progress depends on hydrogen suppliers, off-takers and regulators working together, along with a wider ecosystem of technology providers, investors and partners, to create viable projects.

From projects to systems Figure 5. Air Products HRS Botlek, Rotterdam, the Netherlands.

Figure 6. Air Products liquid hydrogen storage and trailer at Botlek facility, the Netherlands.

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Hydrogen deployment in Europe is gradually shifting from isolated projects to integrated systems. Liquefaction, distribution networks, depot stations, multi-use hubs, shared-access infrastructure and liquid hydrogen systems are all part of this transition. Individually, these elements are not sufficient. Together, however, they form the foundation of a scalable hydrogen economy. The key takeaway is clear: hydrogen will not scale through generic solutions. It will scale through infrastructure designed for specific applications, grounded in real operational requirements and supported by reliable supply and certification systems. This is the point at which hydrogen moves from concept to reality – not as a single technology, but as a system of interconnected solutions capable of supporting industrial scale deployment.

Priyan Mistry, Honeywell Technologies, details how ammonia is the key to unlocking hydrogen transportation to support the global hydrogen economy.

he global low-carbon hydrogen economy is approaching an important moment. Over the past decade, governments, developers and technology providers have concentrated on scaling production. National hydrogen strategies have been published across Europe, Asia, and the Middle East, investment has flowed

into low-carbon hydrogen projects, and significant advances have been made in electrolysis, carbon capture, and process technologies. Together, these developments have laid the foundations for a global hydrogen market. As the industry moves from ambition to implementation, however, the focus needs to move from production

to delivery. The challenge is no longer simply how to produce low-carbon hydrogen, but how to transport it economically from regions with abundant renewable resources to those where demand is expected to grow rapidly. Countries such as Australia, India, Chile, Oman, and parts of Africa and China possess exceptional wind and solar resources that can support large scale hydrogen production, while industrial economies including Japan, South Korea, and many European nations are expected to rely on imports to supplement domestic supply as they seek to decarbonise heavy industry, transport, and power generation in addition to boosting energy security. Rather than developing as a series of isolated national markets, the hydrogen economy is expected to resemble today’s global markets for LNG, with resilient international supply chains connecting exporters with importers. Developing those supply chains requires more effort than producing hydrogen competitively. It also requires transport solutions that are technically robust, commercially viable, and capable of operating at the scale demanded by global energy markets. Several options are being explored, including compressed hydrogen, liquid hydrogen, liquid organic hydrogen carriers (LOHCs), and ammonia. Each has a role to play depending on transport distance, infrastructure availability, and end-use requirements. Pipelines are likely to become the preferred solution for regional hydrogen networks, while liquid hydrogen may be attractive where direct delivery of hydrogen is required. LOHCs also offer advantages in specific applications by utilising existing liquid fuel infrastructure. Among these options, ammonia is emerging as a competitive carrier for long-distance hydrogen trade, with advantages that extend beyond its physical properties. Unlike many alternative transport solutions, ammonia already benefits from a mature global production and logistics network developed over decades to support the fertilizer and chemicals industries. Around 20 million tpy of ammonia are traded internationally through established export terminals, shipping fleets, storage facilities, and import infrastructure. This existing ecosystem provides a significant commercial advantage, reducing both investment requirements and deployment risk as international hydrogen supply chains develop. The physical characteristics of ammonia further strengthen its position. Containing approximately 17.8% hydrogen by weight, it can be liquefied at around -33°C under atmospheric pressure or stored under moderate pressure at ambient temperature. These conditions are considerably less demanding than those required for liquid hydrogen, reducing energy consumption across the transport and storage chain while allowing operators to utilise proven handling technologies that are already deployed at commercial scale. While different hydrogen carriers will each have a role depending on the application, these characteristics give ammonia a strong position in long-distance international trade. Perhaps more importantly, ammonia enables renewable energy to be decoupled from hydrogen consumption.

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Renewable hydrogen produced in resource-rich regions can be synthesised into ammonia, transported efficiently, and converted back into hydrogen close to where it will be used. Several independent energy studies conclude that many industrialised economies are unlikely to produce sufficient renewable hydrogen domestically to meet projected demand, making international trade an essential component of future hydrogen supply. Ammonia therefore offers a practical route to connect regions with abundant renewable resources to industrial centres where hydrogen demand is expected to be greatest. To meet this demand, a growing proportion of future low-carbon ammonia production is expected to be traded as an energy carrier rather than solely as a chemical feedstock, fundamentally changing ammonia’s role within the global energy system. As this transition gathers pace, the technologies that convert ammonia back into high-purity hydrogen are important. In this sense, ammonia cracking is no longer simply a downstream process within the value chain. It is the link between large scale renewable energy production and the industries that will ultimately consume hydrogen.

Ammonia cracking moves to centre stage

Although ammonia cracking has been employed in industrial applications for many years, the requirements of the emerging hydrogen economy are significantly different from those of traditional niche markets. Commercial scale cracking facilities will be expected to operate reliably at much larger scales, integrate with complex industrial infrastructure, and deliver hydrogen that meets demanding purity specifications, all while maintaining competitive operating costs over decades of continuous service. The focus is therefore shifting from demonstrating that ammonia can be cracked successfully to optimising cracking systems for long-term commercial deployment. This is changing how ammonia cracking technology is evaluated. High ammonia conversion remains important, but it is now only one measure of overall performance. Project developers and investors are assessing technologies according to operational reliability, energy efficiency, maintenance requirements, life-cycle cost, and their ability to deliver predictable long-term performance. Catalysts remain central to ammonia cracking performance. Continued advances in catalyst formulation have improved activity, thermal stability and resistance to poisoning, helping to extend catalyst life while supporting more consistent hydrogen production. Alongside these developments, reactor design is evolving to improve heat transfer, reduce pressure losses, and maximise catalyst utilisation. Since ammonia cracking is an endothermic process, efficient heat management has a significant influence on plant performance. Because the reaction requires a continuous heat input, effective heat integration can have a significant effect on both overall process efficiency and operating costs. Recovering heat from adjacent industrial processes or integrating cracking systems with renewable electricity sources

can improve plant performance while reducing energy consumption. Ultimately, as projects move towards commercial deployment, optimising the complete cracking system rather than individual pieces of equipment will be essential to reducing life-cycle costs and improving operational performance. Hydrogen purity requirements vary considerably between applications. Fuel cells, for example, require significantly higher purity than many industrial heating or combustion applications, meaning cracking systems must be designed alongside appropriate purification technologies to meet specific end-use requirements without imposing unnecessary energy or capital penalties. At the same time, future plants will need to operate flexibly as hydrogen demand becomes more diverse. Industrial users may require continuous baseload supply, while demand from power generation, mobility, or grid balancing applications is likely to fluctuate. Technologies capable of maintaining high efficiency across a broad operating window will therefore be well positioned as hydrogen markets continue to develop. For Honeywell Technologies, these developments reinforce the importance of viewing ammonia cracking as an integrated process rather than a single unit operation. Drawing on decades of expertise in catalyst science, ammonia processing and hydrogen technologies, the company believes future projects will be differentiated by their ability to combine catalyst selection, reactor design, heat integration, and process engineering into complete systems that maximise efficiency, reliability, and operational flexibility.

Building the infrastructure for global hydrogen trade

As international hydrogen markets take shape, the deployment model is unlikely to be uniform, with different regions adopting solutions that reflect their industrial base, geography, and hydrogen consumption patterns. In many cases, the first commercial projects are expected to be developed around major ports and industrial clusters, where imported ammonia can be converted into hydrogen before being distributed to nearby users. This approach capitalises on existing import infrastructure while serving multiple industrial consumers from a single location. Refineries, chemical plants, steelworks, and power generation facilities are already concentrated around many of the world’s major ports, creating natural demand centres where hydrogen can be integrated into existing industrial processes. Large scale hydrogen hubs are likely to form the backbone of future global hydrogen trade, offering economies of scale in ammonia handling, hydrogen purification, and process integration. At the same time, smaller, decentralised ammonia cracking systems are expected to play an important complementary role where hydrogen demand is more dispersed, or users lie beyond dedicated hydrogen pipeline networks. Smaller cracking units positioned close to hydrogen refuelling stations, remote industrial facilities or local energy systems could

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improve security of supply while allowing hydrogen markets to develop incrementally before larger regional networks become established. Together, these deployment models provide the flexibility needed to support different regional requirements while strengthening energy security through more diversified sources of low-carbon hydrogen. Policy and regulation will also influence the pace of deployment. In Europe, the Renewable Energy Directive (RED III) and the Renewable Fuels of Non-Biological Origin (RFNBO) framework are stimulating demand for low-carbon hydrogen while establishing certification requirements that provide confidence in the origin and carbon intensity of imported energy carriers. Meanwhile, Japan and South Korea have recognised the strategic role that imported ammonia could play in meeting ambitious decarbonisation targets despite limited domestic renewable resources. As these policy frameworks mature, they will help create the investment certainty needed to accelerate international hydrogen trade and the infrastructure that supports it. At the same time, the development of hydrogen import terminals and industrial clusters is helping translate policy into commercial projects. By bringing together ammonia import infrastructure, cracking facilities and concentrated industrial demand, these hubs have the potential to reduce infrastructure costs while accelerating the deployment of low-carbon hydrogen across multiple sectors.

Conclusion

The hydrogen economy will ultimately be judged not by the number of announced projects or installed electrolysers, but by its ability to deliver reliable, affordable low-carbon energy wherever it is needed. The next phase of market development will be defined not by proving that hydrogen can be produced, but by delivering it at the scale, reliability, and cost required by global industry. Attention is therefore shifting from proving that ammonia cracking can operate successfully to delivering commercial hydrogen supply chains capable of reliable long-term operation. The next generation of projects will need to do more than prove technical performance. They must also deliver reliable operation, predictable economics, and seamless integration with existing industrial infrastructure. As investment gathers pace, these factors will play a decisive role in determining which technologies are adopted at scale. Ammonia has emerged as one of the most credible carriers for international hydrogen transport because it combines established infrastructure with favourable transport characteristics and commercial maturity. Its full potential, however, depends on efficient, reliable, and scalable ammonia cracking technologies that complete the value chain. As hydrogen markets evolve from demonstration projects to commercial reality, ammonia cracking is set to become one of the enabling technologies that transforms hydrogen into a globally traded energy commodity, connecting the world’s richest renewable resources with the industries that need them most.

Daniel Patrick, Atlas Copco Gas and Process, explores the compressor and expander technologies that can support the liquid hydrogen value chain.

s global hydrogen trade takes shape, liquid hydrogen (LH2) is emerging as one of the most practical ways to move large volumes over long distances. A 2024 study by the European Commission’s Joint Research Centre found that LH2 shipped beyond 2500 km carries a lower environmental impact than chemical carriers like ammonia or liquid organic hydrogen carriers (LOHCs), largely because LH2 avoids the energy-intensive step of unpacking the hydrogen at the destination.¹ But between the production plant and the final customer, there is a complex chain of infrastructure: liquefiers, storage tanks, loading terminals, carriers, and import terminals. Every step in that chain depends on rotating equipment, and every step presents its own operating conditions and machinery requirements. This article examines each stage of the LH2 value chain, from plant to port, and looks at the compressors and expanders that make each step possible. See Figure 1 for an overview of the hydrogen value chain and the specific liquid hydrogen subsection this article will focus on. In every part of the value chain, the equipment must be designed around hydrogen’s unique properties. With a molecular weight of just 2 g/mol and a boiling point of -253°C, hydrogen presents unique challenges for machinery designers. Fortunately, decades of experience from LNG and hydrogen-rich petrochemical services provide a strong foundation to build from.

Production: the first compression step Before hydrogen can be liquefied, it must be produced and compressed. Electrolysers typically deliver hydrogen

at relatively low pressures, while downstream steps like liquefier feed, pipeline injection, and buffer storage require higher pressure. This first compression step looks different from the rest of the chain. Flow rates at a single production site are still modest by turbomachinery standards, and hydrogen’s low molecular weight limits the pressure ratio a centrifugal stage can deliver. As a result, positive displacement machines carry the production workload today. The two most common positive displacement compressors in hydrogen production plants are reciprocating and screw. Reciprocating compressors handle high pressure ratios efficiently and remain the workhorse for hydrogen compression. Screw compressors provide steady flow with fewer pulsations and lower maintenance demands but at moderate pressure ratios. Hybrid arrangements, such as a screw machine boosting the suction of a reciprocating unit, combine the strengths of both. The right selection depends on flow, pressure, and duty cycle, and quite often the best answer is a combination. Renewable-powered production adds another design consideration, since intermittent electrolyser operation favours machines that tolerate frequent starts, wide turndown, and variable suction conditions. As production scales toward world scale facilities, centrifugal compression will eventually enter the conversation for feed and pipeline service. For now, positive displacement machines remain the practical choice for production compression, and the centrifugal story begins at the liquefier. Figure 2 summarises the main compressor and expander applications covered in the following sections.

Liquefaction: where the cold chain begins

So why liquefy at all? Liquid hydrogen is roughly 800 times denser than hydrogen gas at atmospheric conditions, so liquefaction transforms hydrogen into something you can effectively transport via trucks and carrier ships. Liquefaction requires one or more refrigeration cycles to chill the gas below -253°C, and two machinery types do the heavy lifting: refrigeration compressors and cryogenic turboexpanders. The precooling stage borrows directly from LNG, where nitrogen reverse Brayton and mixed refrigerant cycles have operated reliably for decades. The refrigeration compressors sit in the warm section of the process, circulating refrigerant through the cycle. For medium and large scale liquefiers, these are large centrifugal machines, often integrally geared, and they account for the majority of the liquefier’s power consumption. The heavier refrigerants used in these precooling cycles often favour integrally geared compressor configurations, allowing each stage to operate near its optimal speed. Just like in LNG, larger liquefiers enable higher machinery efficiency by allowing

compressors and expanders to operate at optimal speeds, along with proportionally lower secondary losses providing improved specific energy consumption for the whole plant. The primary cooling cycle is where the novel design features emerge. This cycle typically uses hydrogen as the refrigerant, although there are alternative refrigerant concepts including mixtures of neon, helium, and hydrogen, or even more traditional hydrocarbon refrigerants that get removed after compression to avoid freezing. This article will focus on the pure hydrogen cycle. Similar to the production step of the value chain, the compression on the hydrogen cycle is done today by reciprocating type compressors. As plants scale, the preferred technology will shift towards centrifugal type compressors as the main hydrogen refrigerant compressors. The hydrogen turboexpanders operate in the coldest part of the plant, extracting work from the refrigerant to generate the deep refrigeration that hydrogen demands. Hydrogen’s low molecular weight produces a large enthalpy drop for a given pressure ratio, pushing these cryogenic turboexpanders toward high tip speeds and multistage configurations. Meanwhile, the plant’s brazed aluminium heat exchangers are extremely sensitive to oil contamination, so oil-free machinery is highly preferred. Active magnetic bearing turboexpanders have become the ideal oil-free solution for medium and large scale liquefiers, backed by more than three decades of history in hydrogen-rich petrochemical service. Figure 3 shows an example of a magnetic bearing turboexpander for hydrogen liquefaction duty.

At the export terminal: managing the boil-off gas

Figure 1. Hydrogen value chain showing production to end-use, with the LH2 transport route highlighted.

Rotating equipment along the LH2 value chain

H2 Feed Gas (from pipeline)

LH2 Liquefaction Plant

Flash gas compressor

Warm N2 Expander

Cold N2 Expander

Warm H2 Expander

HD BOG Compressor

Fuel gas

Cold H2 Expander

LD BOG Compressor

Primarycooling

BOG Expander – Generator Compressor

Pipeline

BOG reliquefaction

PLD or ORC

BOG compressor

Pre-cooling

LH2 Receiving Terminal

LH2 Carrier

BOG reliquefaction

LH2

Storage

Marine Transport Storage

or N2 or mixed refrigerant compressor

N2 compander

H2 refrigerant compressor

Atlas Copco Gas and Process

Figure 2. Key compressor and expander applications across the liquid hydrogen value chain.

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Even the best insulation will not keep hydrogen a liquid forever. Heat continuously leaks into storage tanks, vaporising a small fraction of the liquid and generating boil-off gas (BOG). Without active BOG management, tank pressure climbs until relief valves open and valuable hydrogen vents to the atmosphere. At the export terminal, BOG compressors keep tank pressure under control and route the vapour to reliquefaction or local consumers. The demanding case arrives when a carrier arrives: loading LH2 transfers thousands of cubic meters of cryogenic liquid into the ship’s tanks, displacing cold vapour that must go somewhere. High-duty BOG compressors (located onshore or on the LH2 carrier) return this displaced vapour

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design features and cryogenic operating conditions are already being proven.

The import terminal: the final port

Figure 3. Cryogenic turboexpanders designed for hydrogen liquefaction service. to shore at the required pressure. These centrifugal machines face a unique design envelope. Suction temperatures around -250°C in normal operation, yet the same compressor must also handle warm hydrogen during initial startup and cooldown scenarios. The density difference between cryogenic and ambient conditions is dramatic, and it directly affects the achievable pressure ratio. Managing this variation in density and volume flow, together with the sealing and insulation requirements of deep cryogenic service, is a primary design challenge for the LH2 BOG compressors in this step of the value chain.

Across the ocean: boil-off becomes fuel

Once the LH2 carrier leaves port, boil-off continues throughout the voyage. LNG carriers often reliquefy BOG on board but repeating that trick at -253°C is less practical. Instead, current LH2 carrier concepts generally rely on utilising the BOG as a fuel source. Low-duty BOG compressors located on the ship draw vapour from the cargo tanks and deliver it to the fuel-gas system at the pressure the engines or fuel cells require. This manages tank pressure while putting the BOG to work as fuel for the vessel. Because this duty typically involves relatively low flow rates and higher pressure ratios, positive displacement compressors are often preferred. Reciprocating and screw compressors are therefore well suited for this application. The approach builds on the experience of using LNG as fuel on LNG carriers, and it is now being planned for commercial vessels in development with LH2 carrier capacities in the range of 40 000 - 160 000 m3. Marine service adds its own considerations. The machinery must tolerate ship motion and be designed with a compact footprint. Thankfully, machinery for marine service is already well defined and understood from the LNG industry. The bearing systems, rotordynamics, and seal performance must be validated as vessels continue to scale. However, thanks to pilot vessels such as the Suiso Frontier, many of the novel

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At the receiving end, LH2 must be unloaded, stored, and prepared for delivery to downstream users. Unloading LH2 displaces vapour from onshore tanks as liquid arrives, and BOG compressors again manage the balance between ship and terminal. Storage tanks at the import site face the same steady heat ingress as elsewhere in the LH2 value chain, so continuous BOG handling remains part of daily operations. Unlike export terminals, import facilities also require send-out compression to match downstream pipeline or industrial user pressure requirements. Regasifying is mostly a heat exchange task, since vaporising LH2 requires only ambient temperatures. The more interesting opportunity is the cold locked inside the liquid. The refrigeration invested at the liquefier does not have to be wasted at the import terminal. That exergy can be recovered for local refrigeration duties or even power generation using a turboexpander in an Organic Rankine Cycle (ORC). Repurposing this cold energy can improve the economics of the entire chain. After regasified hydrogen enters a pipeline or industrial network, compression completes the final delivery step to downstream consumers. The import terminal is also where the LH2 chain remains the least defined. Early designs draw heavily on LNG receiving terminal practice, with tank sizes, transfer rates, and BOG loads adjusted for hydrogen’s properties. As the first commercial terminals progress through front-end engineering, the machinery scope is coming into focus: BOG compression for unloading and holding modes, recovery compression to send-out pressure, and cold energy recovery where a nearby user can take advantage of it. Terminals that account for these systems early will be better prepared for reliable LH2 import operation.

Conclusion

From the production plant to the import terminal, the LH2 value chain is defined by the same basic hydrogen characteristics as the rest of the hydrogen value chain, although with much colder operating conditions. Hydrogen’s low molecular weight influences the design and performance of every compression and expansion stage. Its -253°C boiling point drives the materials, seals, and thermal design of every cryogenic machine. Positive displacement compressors prepare the gas, refrigeration compressors and turboexpanders produce the liquid, and BOG compressors manage vapour generation and tank pressure throughout the value chain. Much of this does not require a technological leap. The machinery draws on decades of LNG and hydrogen-rich petrochemical experience, adapted to hydrogen’s unique demands. What the hydrogen market needs now is deployment at scale. As the first commercial LH2 corridors take shape, these compressors and expanders will be doing the essential, continuous work that makes the global hydrogen trade possible.

Reference

1. ARRIGONI, A., DOLCI, F., et al., ‘Environmental life cycle assessment (LCA) comparison of hydrogen delivery options within Europe’, Joint Research Centre, European Commission (2024).

Katsuyuki Takano, Ebara Elliott Energy, analyses how return gas blowers can be designed to safely manage liquid hydrogen during storage and transfer.

s the global momentum toward decarbonisation accelerates, countries are increasingly shaping their energy strategies around available regional resources and economic budgets. For nations with limited local renewable energy but robust financial means, importing large quantities of hydrogen is expected to significantly drive up demand for vital applications in power generation, mobility fuels, and steelmaking. Liquid hydrogen (LH2) stands out as a highly promising carrier for transporting these massive volumes across the global supply chain. However, successfully transferring and storing LH2 at loading and receiving ports presents distinct infrastructure challenges, particularly regarding tank pressure management. Much like conventional LNG operations, a specialised blower, known as a return gas blower (RGB), is vital to handle boiled-off hydrogen gas, ensuring that tank pressure balance is maintained safely and effectively during the transfer process. In order to maintain the pressure balance in LNG carrier tanks when receiving LNG at receiving terminals, a return gas blower is required to return boiled-off natural gas

generated in onshore storage tanks to tanks onboard LNG carriers (Figure 1). For LNG, the temperature of the gas is about -162°C, which is higher than the boiling point of nitrogen (-196°C); nitrogen itself is an inert gas, so it could be used to seal the blower. The temperature of LNG is also higher than the boiling point of oxygen, eliminating concerns regarding the generation of liquefied oxygen on the outer casing surface. On the other hand, unlike conventional LNG, liquefied hydrogen has a lower temperature of -253°C. If a comparable unloading process is applied to liquefied hydrogen, even the boil-off gas from onshore tanks is expected to be approximately -253°C. If this gas is returned to the carrier like LNG, the -253°C flow will cool the blower’s metal parts, potentially liquefying the surrounding oxygen and nitrogen. When air is liquefied, a large amount of liquid oxygen is produced, causing a risk of explosion. Therefore, in order to safely operate a blower at extremely low temperatures under normal operating conditions, a vacuum insulation structure must be installed on the casing blower body to prevent liquefied oxygen from being generated, and the outer surface of the blower must be -183°C or higher.

Alternatively, the boiled-off gas (BOG) could be heated and returned to the ship for equalisation. In this case, no special handling of hydrogen is required for the blower. However, if the warmed BOG were to be returned to the ship’s tanks, the temperature in the tanks would rise, and the liquid hydrogen in the tanks would vaporise, reducing the amount of liquid hydrogen in the product. Therefore, it is necessary to return the product to the tanks in a cryogenic state in order to prevent the discharge temperature from rising. The process described occurs at the receiving port for liquefied hydrogen. Hydrogen production is preferable in locations abundant in renewable energy sources such as wind and solar power, as this enables carbon-free production. Hydrogen will also likely be liquefied at these same locations. Naturally, ports for shipping the liquefied hydrogen will be required at these sites. At the loading port, boil-off occurs in the ship’s tanks when liquid hydrogen is transferred to the vessel. If this boil-off hydrogen is not removed from the ship’s tanks, the pressure inside the tanks may rise, potentially hindering the smooth progress of the liquid transfer. In such cases, blowers or compressors are also required to transfer the BOG. Additionally, when transporting liquefied hydrogen by tanker, the hydrogen continues to boil off, necessitating compressors and blowers to handle the boiled-off hydrogen. While still quite some time away, the hydrogen supply chain could potentially expand to include aircraft and hydrogen-powered inner harbour vessels. In that case, large scale hydrogen storage facilities would likely be installed at inner harbour vessel transfer bases and airports, thus requiring equipment to handle boil-off hydrogen at those locations.

Process gas conditions

Various formulas exist for gas state prediction. The commonly used gas performance prediction formulas may not be accurate under cryogenic conditions. When comparing commonly used gas performance calculations with REFPROP, which is closer to

Figure 1. Return Gas Blower (RGB) process conceptual diagram.

Figure 2. Difference of specific heat ratio (NIST, REFPROP).

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experimental values, it is recognised that there is a difference in the cryogenic temperature range (less than -200°C). In particular, there are differences in compressibility and specific heat ratio. The specific heat ratio for hydrogen, which is derived from the modified BWR equation, differs by approximately 13% from that derived from REFPROP (Figure 2).1 Furthermore, when compared with JSME2 experimental values, the discrepancy between the JSME experimental values and the specific heat ratio calculated from REFPROP is less than 1%. Therefore, the gas properties calculated from REFPROP are more suitable for this cryogenic temperature range. In addition, hydrogen molecules (H2) have two quantum mechanical isomers with different nuclear spin orientations: ortho-hydrogen and para-hydrogen. The ratio they exhibit near room temperature (ortho-hydrogen: para-hydrogen) is 3:1, known as normal-hydrogen. On the other hand, at cryogenic temperatures, para-hydrogen accounts for the vast majority of the mixture. Therefore, the comparison is between para-hydrogen and normal-hydrogen. When comparing the specific heat ratio and compressibility of para-hydrogen and normal-hydrogen, there is almost no difference in compressibility, but there is a slight difference in the specific heat ratio. However, since it is generally accepted that para-hydrogen is dominant in the cryogenic temperature range, the characteristics of para-hydrogen gas are generally used. Even in this case, it is considered appropriate to evaluate aerodynamic performance under more severe conditions when designing a blower. Also, given the drastic change in the gas’ density near the boil-off temperature, the performance in this temperature range is highly temperature dependent and very sensitive, making it difficult to predict. Therefore, it is necessary to use variable speed control to adjust performance and a sufficient surge margin to ensure stable operation.

Material selection

The gas handled by a return gas blower is cryogenic hydrogen. It is necessary to select materials that are applicable to the cryogenic environment and hydrogen embrittlement. Cryogenic embrittlement is a phenomenon in which metal tends to separate and fracture at the cleavage surface below a certain temperature. It is observed in metals with a body-centred cubic structure (such as ferritic steel [SUS430]), but not in metals with a face-centred cubic structure (such as nickel, aluminium, and austenitic stainless steel [SUS304L and SUS316L]). This is a phenomenon in which absorbed hydrogen reduces the ductility and toughness of steel. However, it is still not fully understood due to factors such as stress. In particular, high strength high-carbon steels and stainless steels are said to have significant reductions in ductility and toughness due to hydrogen embrittlement. This causes the sudden, brittle fracture of high-strength steels, necessitating careful material selection. Although the pressure is lower in return gas blowers, selecting high-strength materials is critical given the structural demands on the impeller. There are already products that handle liquefied hydrogen in mobility hydrogen stations and in the aerospace sector, and numerous materials have a proven track record of reliable, long-term operation, including austenitic stainless steels such as SUS316L. The coefficient of linear expansion, specific heat, and thermal conductivity of each component in a low-temperature

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environment must also be well understood. The combination of material forming the clearance between the stationary and rotating parts is also important, as the clearance changes significantly due to differences in thermal shrinkage.

Vacuum-insulated casing design

In order to safely operate a return gas blower at extremely low temperatures under normal operating conditions, a vacuum insulation structure must be provided between the inner and outer surface of the blower to keep the outer surface of the blower at -183°C or higher and to prevent the formation of liquefied oxygen on the outer surface of the casing (Figure 3). However, due to the structure of the shaft seal, hydrogen leaks into the vacuum layer through the gap between the seal and the shaft. During operation, hydrogen must be constantly aspirated and ejected to a safe place. In a hydrogen environment, explosion protection requirements are strict, and hydrogen must be ejected in such a way that there is no leakage. When manufacturing a casing, forging is preferred due to heat treatment issues. In addition, the nozzle must be designed to accommodate thermal contraction.

Bearing design

Given the complexities associated with using oil film bearings, magnetic or foil bearings are a recommended alternative. Even though the casing itself is vacuum insulated, the shaft is exposed to extremely low temperatures, so a conventional oil bearing

may not function properly. Properly sealed systems prevent problems from occurring, but oil bearings still pose a leakage risk into the machine. They must be buffered at all times during shutdown to prevent oil from entering the machine, which is economically impractical. If the oil were to enter to machine, it would also contaminate the inside of the tanks on board. Once a tank is contaminated, it is almost impossible to remove it until maintenance. Therefore, an oil-free environment is desired, making magnetic bearings or foil bearings suitable. There are some material challenges regarding use in a hydrogen environment, but they can be addressed. The advantage of magnetic bearings is that they have very low mechanical losses. Similarly, in foil bearings, the damping of the bearing is smaller than that of an oil film bearing, so rotordynamics need to be considered.

Mock-up test

A test was conducted to determine the temperature distribution on the casing’s surface by the hydrogen heat transfer leaking into the vacuum layer and the heat exchange by the inner casing’s latent heat. This test would verify if the time to reach -160°C or higher matches simulation results. However, since it is very difficult to conduct tests in a hydrogen environment, liquid nitrogen was used to see if the results matched the simulation. Test results showed that after nitrogen gas injection began, only the upstream pipe section of the test apparatus experienced a sudden temperature change, while temperatures elsewhere gradually decreased (Figure 4, left). The analysis assumed temperatures would drop to around -60°C, but in reality, they only reached approximately -30°C. This suggests that heat gain from the atmosphere contributed more to the temperature rise than anticipated. The frost formation on the casing surface was only faint even after five hours, significantly differing from the frost formation seen with LNG (Figure 4, right). This indicates that the vacuum layer is functioning adequately.

Conclusions

Figure 3. Vacuum-insulated casing configuration.

Figure 4. Temperature change on outer casing surface (left), and ice covered casing (right).

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Magnetic bearings and insulated casings are all existing technologies already adopted in turbomachinery, but their simultaneous implementation is rare. The insulated casing, in particular, represents an unprecedented operating method, forming a vacuum layer within the casing for operation. Maintaining a constant vacuum during operation prevents the generation of liquid oxygen to the casing surface caused by cryogenic hydrogen temperature. This technology is essential for achieving safe operation when handling hydrogen at the cryogenic temperature of -253°C. Developing and advancing return gas blowers using these technologies could increase demand for liquid hydrogen in hydrogen storage and transportation. This necessitates designs capable of withstanding higher torque and high-speed rotation. Solving this challenge requires structures enabling high-speed and leak-free operation, such as adopting integrated designs incorporating high-speed motors and developing high-strength materials better suited for cryogenic hydrogen. Progress is anticipated in the development of these materials and technologies.

Reference

1. NIST, Reference Fluid Thermodynamic and Transport Properties Database (REFPROP). 2. JSME, 1983, Data Book: Thermophysical Properties of Fluids, p. 99.

Tobias Moss, Dräger, Germany, describes how safety enables profitable hydrogen scale-up.

ydrogen is becoming an increasingly important energy source – worldwide, but particularly in Europe, which is poor in natural resources. In a time of global energy transition and ongoing raw material crisis, it is a crucial factor in ensuring the security of supply for critical infrastructure. That is why, for example, the German Federal Government’s National Hydrogen Strategy aims to expand the technology massively by 2030 and to achieve at least 10 GW of electrolysis capacity in Germany.1,2 But every gigawatt of new capacity multiplies the number of connections, valves, and storage vessels through which hydrogen can escape. Whether that growth stays safe depends entirely on how reliably this extremely flammable, and therefore highly explosive, substance is detected in case of a leak. As the volume of hydrogen produced and used each year increases, so too does the complexity operators must manage. Plants that combine electrolysers with solar arrays, wind turbines, and legacy process systems now have to monitor, coordinate, and interoperate across equipment from many different vendors, each with its own conventions. Green hydrogen, produced emission-free via electrolysis using offshore wind power, is another growing sector. On offshore converter platforms, however, all components (electrolyser, compressor, and buffer) are usually housed together in a single, compact, enclosed building within a very confined space. This significantly increases the potential risk in the event of a gas leak. Layered on top of this operational complexity is a physical one: hydrogen itself possesses a number of dangerous physical and chemical properties that make errors and delays far less forgiving than in most other process industries.

A source of hope with potential dangers Hydrogen (H2) is the lightest and smallest of all molecules. It diffuses rapidly, penetrates many materials and escapes more easily than most other gases. Even seemingly airtight containers and seals can allow hydrogen to escape over time. Furthermore, it is invisible, odourless and tasteless, and therefore offers no sensory warning signs. Leaks cannot therefore be detected by humans – unlike natural gas, which is usually mixed with an odourant. Hydrogen forms explosive mixtures with air at concentrations ranging from around 4% by volume, the lower explosive limit (LEL), to 77% by volume, the upper explosive limit (UEL). This range is considerably wider than that of methane (LEL 4.4%, UEL 17%) or propane (LEL 1.7%, UEL 10.8%), meaning that dangerous concentrations can be reached very quickly. As little as 0.02 mJ is sufficient to ignite hydrogen – significantly less than for methane or petrol vapour. Static electricity, small sparks and high temperatures are sufficient to cause ignition. Hydrogen ignites at temperatures of around 560˚C. This is the same as methane, but lower than for many other industrial gases. Furthermore, hydrogen is approximately 14 times lighter than air, meaning that leaked hydrogen gas rises rapidly and accumulates under ceilings or in poorly ventilated rooms. The substance burns with a pale blue flame that is almost invisible, particularly in daylight. Combined with its tendency to give off very little radiant heat whilst burning, this makes it difficult to detect fires and increases the risk of injury to staff at industrial sites. There is no carbon in the molecular structure of hydrogen. Conventional infrared gas detectors, which detect

hydrocarbon bonds, are therefore generally ineffective when it comes to hydrogen.

The more plants, the more dangers

Electrolysis plants are considered highly critical due to the system pressure required. In the downstream hydrogen compressors, the numerous mechanically moving parts lead to a constant risk of leaks at flanges, valves, and pipe connections. Storage tanks and buffer systems are also under high pressure; as storage pressure rises, the likeliness and severity of potential gas releases increase dramatically. The causes of accidents in a hydrogen plant are varied. They can arise not only from inadequate seals at joints and valves, or from component failure, but also from operators losing time to confusion or delay when systems, alarms, and displays do not speak a common language. In September 2025, for example, a fire in Louisville, US, led to the explosion of a hydrogen tank at a vegetable oil factory, which even claimed one life.3 Due to the typically extremely high pressure involved in hydrogen storage, its minimum ignition energy is sufficient to trigger a catastrophic explosion in the event of a container or valve failure. Regardless of the type of plant, an accident usually hits the operator twice: not only are people at risk of harm, but the company’s infrastructure is also generally affected. Furthermore, virtually every incident results in regulatory investigations and, consequently, downtime. This usually costs a company money and, in extreme cases, can even threaten the operators’ very existence. To minimise these risks, a comprehensive plant safety system is required – one that includes the rapid, reliable and precise monitoring of the lower explosive limit (area monitoring),

Figure 1. Ex-Zone in a chemical plant.

Figure 2. Alarm panel at Ex-Zone entry.

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that detects leaks, for example of flanges, immediately and gives operators a single, unambiguous picture of what is happening. Devices installed outdoors must be resistant to gas dilution, wind direction, and other weather factors such as rain. To optimise the efficiency of their safety and maintenance processes, operators should also regularly analyse their measurement data.

The ‘explosion triangle’

An explosion occurs when three elements come together: fuel (a concentration of flammable gas or vapour above the LEL and below the UEL), an oxidiser (a sufficiently high concentration of oxygen/atmospheric oxygen or another oxidiser), and an ignition source (a sufficiently high temperature or energy release from an ignition source, e.g., a spark, flame, hot surface or static electricity). If any one of these factors is missing, an explosion cannot occur. Explosion prevention strategies therefore focus on preventing or disrupting this combination. In practice, this means – in accordance with the international standard IEC/EN 1127-1, for example – first and foremost preventing the formation of an explosive atmosphere. This is achieved either by reducing or increasing the concentration of the flammable substance to a level outside the explosive range or by reducing the oxygen concentration to a level below the lower oxygen concentration (LOC). Secondly, all potential ignition sources must be eliminated and/or, thirdly, the potential effects of explosions must be limited to an acceptable level through structural protective measures.

Strategies and practical implementation

A comprehensive explosion protection plan, for example in accordance with ATEX 1999/92/EC, combines technical, organisational, and procedural measures. Primary explosion protection involves ensuring that no flammable mixtures form. This includes the substitution of hazardous substances, ventilation, inerting, and control of temperature and concentration, for example with gas detection equipment. Secondary explosion protection aims to prevent the ignition of explosive atmospheres. Suitable measures include the elimination of ignition sources, such as electrical sparks, hot surfaces, mechanical friction, and electrostatic discharges. In addition, there is earthing and equipotential bonding through the use of ATEX-compliant equipment, which is certified and marked in accordance with the protection type (EPL). Pressure-resistant enclosures (Ex d) protect against internal explosions and prevent flames from escaping. Limiting electrical energy to levels that cannot cause the ignition of hazardous atmospheres, even under fault conditions, serves to ensure intrinsic safety. Another aspect is the encapsulation (Ex m) of flammable components in a protective compound. Finally, enhanced safety (Ex e) is achieved by improving the mechanical and thermal design to reduce the likelihood of ignition. Tertiary explosion protection, finally, focuses on limiting the damage should an explosion nevertheless occur. Suitable measures include pressure relief (e.g., burst discs, explosion relief panels) and explosion suppression systems, such as the rapid release of extinguishing agents. Added to this are explosion isolation via valves, barriers and flame arresters, explosion-proof design of plant, and flame and pressure containment within the plant.

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Sensor technologies and their selection

The selection, installation, and maintenance of gas detection systems are crucial for reliable explosion protection. Sensors and alarm devices must be selected and installed taking into account their strengths and limitations. The applicable standard IEC/EN 60079-29-2 provides guidance on best practice for the use of detectors in occupational safety applications. Particularly in the case of hydrogen, the choice of technology and placement strategies are of crucial importance. Ultrasonic gas leak detectors (UGLDs), such as the Dräger Polytron 8900 UGLD transmitter, are early-warning area monitors designed to detect high-pressure gas leaks in the outdoor areas of industrial plants. They detect the ultrasonic waves emitted by the escaping gas, rather than measuring the concentrations of accumulated gas clouds, and therefore respond sooner than conventional gas detectors – regardless of wind direction. Particularly in the case of outdoor hydrogen plants, it is an important feature that these devices are unaffected by gas dilution, wind direction, rain or other weather conditions. In compressor stations, these devices can also detect leaks of compressed hydrogen and methane-hydrogen mixtures at an early stage. Conventional catalytic point gas detectors are used to monitor the LEL. The Dräger Polytron 8200 CAT, for example, is an explosion-proof transmitter that measures and detects flammable gases such as hydrogen within a few seconds. These types of devices are characterised by a long service life when exposed to toxic substances, are approved for temperatures up to 80˚C and can detect very low gas concentrations in the range of 0 - 10% LEL.

Figure 3. Flammable gas detector Dräger Polytron 8200.

Selective point gas detectors with electrochemical sensors detect hydrogen and other gases at very low concentrations – in the parts per million (ppm) range. Detecting hydrogen flames requires sensor technology capable of identifying their radiation frequencies early and reliably. Flame detectors fitted with three infrared sensors – specifically developed for hydrogen flames – only trigger when they measure a unique ratio between the infrared rays detected by the three sensors. Technology like the Dräger Flame 1750 H2, with its triple IR sensor, thus detects fires involving hydrocarbons and hydrogen precisely, quickly and reliably. This makes them highly resistant to false alarms, which are often triggered by welding work, hot objects or other radiation sources such as sunlight or lightning. They operate more effectively and reliably than conventional UV or IR hydrogen flame detectors and have a significantly greater range.

Not without the right design

However, no matter how smart, innovative and powerful the technology is, it only realises its full potential within the framework of the right safety design. Whether it is a compressor station, a storage facility or an electrolysis plant: every facility is different and therefore requires a bespoke safety concept. Determining the optimal number and positioning of gas and flame detectors requires a professional risk assessment including gas mapping – a holistic, structured, and scientific process that identifies sources of danger, defines the potential for escalation, sets the objectives of the safety measures, reviews the safety measures already in place, selects the appropriate detector technology and, finally, models and verifies the chosen design. Carried out competently, this approach also reveals the right combination of different technologies, which is the key to a plant safety system that is as efficient as possible. Done well, operators benefit from the lowest possible number of devices, low cabling and installation costs, and minimal maintenance burdens throughout the system’s entire life-cycle. After all, more sensors do not automatically mean greater safety. The engineer in charge is crucial in this context. They must understand the existing infrastructure and its specific challenges even before gas mapping is carried out. These include the hazards present, the potential for escalation, the physical layout, occupancy, response philosophy, and the technologies selected. Consequently, this requires knowledge of all existing detector technologies – their strengths, weaknesses, response characteristics, environmental sensitivities, and limitations. This is what distinguishes excellent consultancy from standard procedures. Only those who can place their trust in an innovative, yet conscientious partner can ensure not only maximum safety but also optimum cost-efficiency. As hydrogen scales from pilot to industrial volume, that trust – and the detection design behind it – is what will determine whether the sector’s growth stays safe.

References

Figure 4. Controller for gas detection system.

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1. Wasserstoff, Bundesverband der Energie- und Wasserwirtschaft (BDEW), (22 May 2026), https://www.bdew.de/energie/gas-wasserstoff-biogas/ wasserstoff/. 2. Die Nationale Wasserstoffstrategie, Bundesministerium für Wirtschaft und Klimaschutz, (6 June 2020), https://www. bundeswirtschaftsministerium.de/Redaktion/DE/Publikationen/Energie/ die-nationale-wasserstoffstrategie.html. 3. ‘Hydrogen Tank Explosion at US Louisville Plant Leaves One Dead’, SMM News, (10 November 2025), https://news.metal.com/ newscontent/103613159-hydrogen-tank-explosion-at-us-louisville-plantleaves-one-dead.

Ariel Kigel and Galina Gurina, Modcon Systems, explain the risks posed by oxygen ingress in high pressure hydrogen systems, discussing how measurement integrity can mitigate this.

s the global energy transition accelerates, hydrogen has emerged as a cornerstone of decarbonisation, particularly for ‘hard-to-abate’ sectors such as heavy industry, maritime shipping, and long-haul transport. The shift from localised pilot projects to a global hydrogen economy necessitates a massive scaling of infrastructure, characterised by high-pressure storage and distribution networks. In modern applications, ranging from tube trailers to Type IV composite tanks, pressures often exceed 350 bar for heavy-duty vehicles and 700 bar for passenger fuel cell electric vehicles (FCEVs).1 In these high-stakes environments, the integrity of the process stream is no longer merely a matter of fuel efficiency or catalyst longevity; it is a primary safety imperative. Ensuring hydrogen purity, specifically by preventing and monitoring oxygen ingress, represents one of the most significant engineering hurdles. A single contamination event can lead to catastrophic hardware failure or, in the worst-case scenario, a combustion event

within the high-pressure containment. Therefore, understanding the intersection of gas physics, material science, and real-time analytical chemistry is essential for any engineer operating within the hydrogen value chain.

Oxygen ingress in hydrogen systems Sources of infiltration Oxygen (O2) is the most critical contaminant in a hydrogen system due to its role as a potent oxidiser. Infiltration typically occurs at mechanical interfaces. While systems are designed to be positive-pressure, transient states – such as compressor start-up, thermal cycling, or high-flow depressurisation – can create localised pressure drops or vacuum effects that draw atmospheric air through compromised seals. Furthermore, electrochemical sources are prevalent in upstream production. In water electrolysis (AEM, PEM, or alkaline), membrane degradation or pressure imbalances across the stack can lead to O2 ‘crossover’. This is a phenomenon where oxygen molecules migrate through the electrolyte membrane into the hydrogen stream. As electrolysers are increasingly pushed to operate at higher current densities to maximise yield, the risk of crossover increases, making upstream monitoring the first line of defence.

Flammability and detonation dynamics The safety implications are dictated by the explosive limits of the H2- O2 mixture. Under standard atmospheric conditions, the Lower Explosive Limit (LEL) of hydrogen in air is approximately 4%, with an Upper Explosive Limit (UEL) of 75%. However, these figures are misleading when applied to high-pressure industrial processes. As pressure increases, the flammability range widens. More critically, the Minimum Ignition Energy (MIE) required to trigger a combustion event – already exceptionally low for hydrogen (0.017 mJ) – drops even further. In a high-pressure environment, a static discharge or even the kinetic energy of a fast-moving particulate within the pipe can provide sufficient energy for ignition if oxygen levels are not strictly controlled.

Oxidative stress and material integrity The presence of oxygen also alters the long-term structural health of the infrastructure. While ‘hydrogen embrittlement’ (HE) is a well-documented risk for high-strength steels, the introduction of oxidisers can create complex corrosion profiles. In some instances, a trace amount of oxygen can actually form a temporary protective oxide layer that inhibits hydrogen adsorption; however, if the oxygen concentration fluctuates, this layer can crack, leading to localised pitting and accelerated fatigue. For engineers, the goal is not ‘random’ purity but a stable, controlled atmosphere that adheres to the material specifications of the vessels and pipelines.

Engineering challenges of high-pressure environments The physics of permeation

Figure 1. Pressure-dependent flammability and ignition thresholds.

Designing for hydrogen requires a departure from standard industrial gas handling. Hydrogen is the smallest naturally occurring molecule, capable of permeating through materials – such as certain polymers and low-grade steels – that are considered gas-tight for larger molecules like nitrogen or methane. At 700 bar, the ‘driving force’ for permeation is immense. This necessitates the use of high-performance elastomers (e.g., specific grades of Viton or EPDM) and high-nickel alloys (e.g., 316/316L Stainless Steel) that maintain structural stability. Engineers must also account for ‘rapid gas decompression’ (RGD). If a system is quickly depressurised, hydrogen absorbed into the internal structure of a seal can expand, causing the seal to ‘explode’ from the inside out. This damage creates microscopic pathways for oxygen to enter the system during the next cycle.

The Joule-Thomson effect and thermal management Figure 2. Mechanical ingress vectors and thermal expansion risks.

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Unlike most gases, hydrogen has a negative Joule-Thomson coefficient

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at room temperature. This means that when hydrogen expands through a leak or a valve (moving from high to low pressure), its temperature increases rather than decreases. In a high-pressure leakage scenario, the escaping hydrogen can reach its auto-ignition temperature simply through the heat generated by its own expansion. If oxygen is present at the leak site, the probability of a ‘jet fire’ becomes an immediate reality.

Hazardous area classification Every component in a high-pressure hydrogen skid must be scrutinised under ATEX or IECEx standards. The challenge for instrumentation engineers is that many traditional oxygen sensors require a ‘reference gas’ or involve heated elements (such as Zirconia sensors). In a Zone 0 or Zone 1 environment, the instrumentation itself must be intrinsically safe or housed in explosion-proof (Ex d or Ex p) enclosures to ensure that the device intended to monitor safety does not become the source of a disaster.2

Real-time measurement: technologies and trade-offs

Historically, gas purity was verified through periodic laboratory sampling, but in a high-pressure, high-flow hydrogen economy, this ‘grab-sample’ approach is fundamentally insufficient. Transient events, such as a seal failure during a compressor start-up or an electrolyser membrane breach, can introduce dangerous levels of oxygen in seconds, making real-time monitoring an absolute safety requirement. To achieve a prompt safety response, the industry has shifted toward in-situ optical analysis, though several traditional methods remain in use despite their varying limitations.

Quenched phase fluorescence sensors

A leading method for high-accuracy, high-pressure applications is quenched phase fluorescence, more commonly known as photoluminescence. This technique employs an oxygen-sensitive luminophore that is excited by a specific wavelength of light to measure oxygen levels based on the physical phenomenon of collisional quenching. The primary advantage of this method lies in its near-instantaneous response time and exceptional sensitivity at the trace levels required by international fuel quality standards. Furthermore, by utilising an optical interface, the delicate electronic components remain completely isolated from the 700 bar process environment, which ensures high-pressure reliability and resistance to pressure broadening. The disadvantage of this method is primarily Figure 3. Configuration of a high-pressure photoluminescence analyser. the initial cost of the optical interface and the necessity of ensuring the optical path remains clear of heavy particulate contamination, though it requires significantly less maintenance than chemical-based alternatives.3

Electrochemical sensors

Figure 4. Functional logic of a safety instrumented system (SIS).

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Electrochemical sensors, including galvanic and potentiometric types, are frequently utilised in lower-pressure environments due to their high sensitivity and relatively low entry cost.

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From Electrolyser to Transport and Storage

Historically Mokveld axial valves are found in syngas applications in the Steam Methane Reforming (SMR) process, the hydrogen flow in refineries and fertiliser plants and in the ammonia flow in chemical plants. The minimum pressure loss, perfect tight-shut-off and excellent controllability is highly appreciated by our clients. Recently new applications are seen. At the outlet of the electrolyser a high integrity safety valve is required to avoid pressure and flow to return from the compressor into the electrolyser. In the production, transport and storage of hydrogen Mokveld over-pressure protection systems, often with mechanical initiators are installed to protect equipment and personnel.

Tightness

Hydrogen appears as H2, H alone is the smallest molecule. Although H2 is slightly bigger than for example Helium it is still very small. Therefore attention shall be paid to leakage to atmosphere. Also while H2 could be considered a GreenHouse Gas, the 20 year Global Warming Potential is over 30 times that of CO2. Testing for leakage could be performed with Helium. While Helium is finite in the world we prefer to use forming gas (5% H2 + 95% N2) as a safe and sustainable alternate. API 6D Annex M covers forming gas as well.

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These sensors operate by facilitating a chemical reaction where oxygen molecules physically contact an electrolyte to produce a current. However, they face significant hurdles in high-pressure hydrogen skids where the electrolyte is prone to saturation or drying out under extreme conditions. Their main disadvantage is a significantly slower response time (T90) and the requirement for frequent calibration and sensor head replacement as the chemicals deplete. This makes them less ideal for high-speed safety shut-offs in critical infrastructure compared to optical methods.

Paramagnetic sensors Paramagnetic analysis takes advantage of the fact that oxygen is unique among gases for being attracted to a magnetic field. The advantage of this approach is that it is a recognised industrial standard for accuracy that does not rely on consumable chemical parts, providing a stable long-term reading. The disadvantage, however, is that paramagnetic sensors are extremely sensitive to mechanical vibration and tilt.4 In facilities housing heavy reciprocating compressors, the resulting mechanical noise can easily interfere with the signal. Additionally, these systems generally require the gas to be depressurised and conditioned before measurement, which introduces a transport lag that prevents true, ‘prompt’ in-situ monitoring of the high-pressure line.

Zirconia sensors Zirconia ceramic sensors measure oxygen ion conductivity at high temperatures, typically around 600°C. While they offer a very fast response time, their high operating temperature represents a significant disadvantage and an inherent risk in a hydrogen environment. In the event of a ceramic element failure or a crack in the housing, the sensor itself becomes a potential ignition source.5 Consequently, their use is heavily restricted in high-pressure hydrogen process lines due to stringent hazardous area safety concerns and ATEX/IECEx compliance requirements.

Operational safety and mitigation strategies Safety Instrumented Systems (SIS) Data is only valuable if it is actionable. Modern hydrogen plant design utilises Safety Instrumented Systems to automate the response to an oxygen spike. A common configuration is the ‘2oo3’ (two out of three) voting logic. Three independent oxygen analysers monitor the same process point; if any two sensors agree that oxygen has exceeded a setpoint, the system initiates an emergency shutdown (ESD).6 This prevents a single faulty sensor from causing a costly ‘nuisance shutdown’ while maintaining a high Safety Integrity Level (SIL).

Multi-stage thresholds Engineering protocols should define clear, tiered responses: y Alert level (e.g., 0.5% O2): triggers a control room notification. Operators may switch to a redundant filter or check compressor seals. y Alarm level (e.g., 1.0% O2): automated isolation of the affected storage bank to prevent cross-contamination. y Critical shutdown (e.g., 2.0% O2): immediate closure of all main valves and initiation of a nitrogen (N2) purge to inert the system.

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The role of predictive maintenance

By integrating real-time analyser data with IoT platforms, engineers can move beyond reactive safety. For example, if oxygen levels show a micro-trend of 0.01% increase over three months, it serves as a ‘leading indicator’ of seal wear in a specific compressor. This allows for scheduled maintenance during planned downtime, rather than an emergency stop during peak production.

Standardisation and the path forward The hydrogen industry is currently navigating a complex landscape of evolving standards. ISO 14687 and SAE J2719 provide strict guidelines for hydrogen fuel quality, particularly for FCEVs. These standards are exceptionally stringent; for example, they require oxygen levels to be below 5 ppm for fuel cell grade hydrogen. However, as hydrogen becomes a globally traded commodity, transported via pipelines and ammonia carriers, there is a pressing need for international harmony. It is important to standardise not just the limits, but the methods of measurement.7 A ‘5 ppm’ reading in a lab in Europe must be verified by the same rigorous sensor standards as a reading in a production plant in the Middle East. Innovation in this space is moving toward solid-state sensing and ‘smart’ analysers that use machine learning to compensate for pressure and temperature fluctuations in real-time. These advancements will reduce the ‘cost of quality’ and make high-pressure hydrogen infrastructure more bankable and insurable.

Conclusion

The transition to a hydrogen-led energy sector is a multi-decade endeavour that hinges on public and industrial confidence in safety. High-pressure systems bring inherent risks, but through disciplined engineering, rigorous material selection, and the implementation of real-time process measurement, these risks are manageable. Precision in measurement is not merely a technical requirement; it is the foundation of a safe, viable, and scalable hydrogen economy. As we move from megawatt to gigawatt scales, the industry must treat oxygen monitoring and process analysis not as an optional add-on, but as a critical component of the primary safety infrastructure. The future of energy depends on our ability to keep the smallest molecule under the strictest control.

References 1. BARLAS, A., ‘Hydrogen infrastructure and potential development in the EU’, (unpublished master’s thesis), University of Piraeus, (2022). 2. ANALYZER, P. ‘ProTech903 process analytics operational manual’, Galvanic Applied Sciences, (2019). 3. SHAHNOVSKY, G., COHEN, T., and MCMURRAY, R., ‘Integrated monitoring for optimising crude distillation’, Petroleum Technology Quarterly (PTQ), Q1, pp. 43 - 51, (2019). 4. MEYER, K., KERN, S., ZIENTEK N., GUTHAUSEN, G., and MAIWALD, M., ‘Process control with compact NMR. TrAC Trends in Analytical Chemistry’, 83, pp. 39 - 52, (2016). 5. GREENWALD, M., BADER, A., BAEK, S., BAKHTIATI, M., BARNARD, H., BECK, W., and GARCIA, O., ‘20 years of research on the Alcator C-Mod tokamak’, Physics of Plasmas, 21(11), 110501, (2014). 6. HIGH, T. A. N., ‘Advanced solutions for efficient crude blending’, Modcon Systems technical whitepapers, (2014). 7. HIMONA, E., ‘Beyond the grid: Modeling, optimization and economic evaluation of future hydrogen autonomous home energy systems’, Energies, 19(6), 1527, (2026).

Anton Korobeynikov, Integrated Global Services (IGS), Czech Republic, presents case studies outlining strategies for the improvement of existing steam methane reformer assets.

lobal hydrogen demand reached almost 100 million t in 2024, yet more than 99% is still produced using fossil fuels, primarily through steam methane reforming (SMR). Improving the efficiency of existing hydrogen, ammonia, or methanol production assets, therefore, remains one of the fastest and lowest-capital opportunities to reduce operating costs and carbon emissions.

The primary reformer is the most energy-intensive asset within an SMR-based hydrogen plant (Figure 1); even modest improvements in thermal efficiency can significantly reduce fuel consumption, emissions, and hydrogen production costs. While burner optimisation often receives considerable attention, maintaining efficient heat transfer throughout the radiant and convection sections is equally important, ensuring more combustion energy is transferred into the process rather than lost through the stack. This article explores how thermal efficiency evaluations, targeted maintenance, and condition-based repair strategies

can help hydrogen producers recover lost performance, improve reliability and maximise the value of existing SMR assets.

Figure 1. Typical refinery top-fired hydrogen production (pre-reformer is optional).

Radiant section performance begins with efficient heat transfer

Identifying opportunities for efficiency gains

Although rising stack temperatures, increasing fuel consumption, or declining hydrogen production efficiency often indicate deteriorating SMR performance, identifying the underlying cause requires a more detailed assessment. Multiple factors, including refractory condition, burner performance, process tube condition and convection section fouling, can simultaneously reduce thermal efficiency, making it difficult to identify the most effective corrective action based on operating data alone. As a result, many hydrogen producers are adopting comprehensive thermal efficiency evaluations before committing to maintenance or capital investment. These assessments combine plant operating data with heat balance calculations, thermal modelling and, where appropriate, infrared thermography to quantify energy losses and determine which improvements will deliver the greatest operational benefit.

A high emissivity refractory coating was identified as a practical efficiency measure for this reformer, requiring neither process modification nor an extension of the planned outage. Cetek was applied to the radiant refractory surfaces of a side-fired primary SMR during the turnaround (Figure 2). Post-application data were compared against a pre-coating baseline at a matched hydrogen production rate of 31 knm3/hr, with excess air held at 4.9 O2 vol.% and a steam:carbon ratio of approximately 2.4 in both windows. The effect of convection section cleaning performed during the same turnaround was excluded from the analysis by examining external fouling coefficients.

Results Figure 2. High emissivity refractory coating applied to side-fired reformer.

y Fuel savings of 2.2 Gcal/hr (4.1%). y CO2 emission reduction of 4130 tpy. y Radiant fuel efficiency gain from 49.1 to 52.0%. y Bridgewall temperature reduction of 50 - 70°C, depending on severity and load. y Tube metal temperature (TMT) reduction under the same severity.

Key takeaway

Figure 3. Rovex™ by TubeTech – robotic fouling removal system.

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The outcome is consistent with the behaviour generally reported for high emissivity refractory coatings in high-flux radiant service: improved radiant efficiency and lower specific energy consumption. In addition to the measured fuel savings, post-application monitoring indicated a reduction in TMT, attributed to improved uniformity of radiant heat distribution. Lower, more uniform tube temperatures extend tube life by reducing thermal stress and limiting exposure.

Figure 4. Before (left) and after (right) robotic convection section fouling removal.

Convection sections recover valuable energy

While the radiant section provides the heat required for the SMR reaction, the convection section determines how much of the remaining energy is recovered before flue gases leave the stack. By preheating process streams, steam and/or combustion air, convection section performance determines the total fuel efficiency of a primary reformer. Over time, combustion by-products, refractory particles, and other process contaminants accumulate on convection tube surfaces, reducing heat transfer and restricting flue gas flow. As fouling develops, less heat is recovered from the flue gas, requiring additional fuel to maintain hydrogen production. Typical indicators of convection section fouling include: y Stack temperature more than 10 - 20°C above the design stack temperature. y Increased pressure drop between arch and ID fan (which promotes more air ingress, exacerbating the situation). y Lower radiant and/or pre-reformer inlet temperatures. y Higher TMT under the same severity. y Increased fuel consumption. Elevated stack temperature is often the clearest indicator that heat recovery is deteriorating. Combined with performance data and inspection findings, it provides a strong basis for planning targeted maintenance to restore heat recovery and improve SMR efficiency. The following case study illustrates how inspection and performance evaluation identified convection section fouling as the primary cause of declining heat recovery, allowing a targeted cleaning programme to restore thermal efficiency and improve reformer performance.

Case study one: robotic convection section cleaning Background A hydrogen generation unit (HGU) had experienced a gradual decline in performance after more than 20 years of operation. An OEM’s assessment identified fouling within the convection section as a primary constraint on heat recovery, limiting overall reformer efficiency and increasing fuel consumption. The lack of process preheat forced operating personnel to reduce the coil outlet temperature (severity) by 8°C below the target temperature, not to exceed TMT. Since this primary SMR is located within a refinery, there is no secondary

reformer where additional methane conversion reactions can continue. Overall, fouling of the convection section led to increased methane slip and higher specific fuel consumption.

Solution Based on the inspection and thermal performance evaluation, robotic cleaning of the convection section is recommended (Figure 3). To overcome access limitations, IGS enlarged six existing openings in the convection section and installed six reusable access doors while the unit was offline. During a planned turnaround, remotely operated cleaning equipment removed accumulated deposits from closely spaced finned-tube bundles, restoring heat-transfer surfaces without any modification to the reformer (Figure 4).

Results y 14% increase in convection section heat recovery. y 64°C radiant inlet temperature increase. y 8°C coil outlet temperature (COT) gain without hitting TMT limitation. y 0.6 percentage points methane slip reduction: from 4.7% to 4.1% vol. (dry). y 1.2% improvement in overall fuel efficiency. y 1.3 Gcal/hr of fuel savings and 2600 tpy CO2 emission reduction. y US$220 000/yr savings on fuel only, without considering debottlenecking.

Key takeaway The project demonstrated how targeted convection section re-fouling can not only restore total fuel efficiency but also eliminate the existing COT limitation, bringing methane slip to its intended level, reducing specific fuel consumption without hitting TMT limitations.

Maintaining SMR efficiency between turnarounds Although planned turnarounds remain the preferred means of performing major maintenance, many forms of performance degradation develop gradually during normal operation. Refractory deterioration, shell hot spots, and other developing defects can reduce thermal efficiency and increase energy consumption long before the next scheduled turnaround. Rather than allowing these issues to progress until a shutdown is required, many hydrogen, ammonia,

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Figure 5. Hot spot before repair with a maximum temperature of 469°C (left) and after with a maximum temperature of 117°C (right). and methanol producers are adopting condition-based maintenance strategies supported by online inspection and targeted repair. By identifying and addressing developing problems while reformers remain in service, operators can maintain thermal efficiency, improve reliability and defer major maintenance until the next stop.

Online refractory repair

Localised refractory failure is one of the most common causes of shell hot spots and avoidable heat loss in operating steam methane reformers. Left untreated, these defects can reduce radiant efficiency, increase fuel consumption and, in severe cases, compromise continued operation. Online refractory repair enables damaged areas to be restored while the reformer remains in service, reducing shell temperatures, minimising heat loss and maintaining production until permanent refractory replacement can be completed during a planned turnaround. By repairing refractory before defects become critical, operators can avoid unnecessary production losses and maintain reformer efficiency throughout the operating cycle. The following case study demonstrates how online refractory repair restored refractory integrity, significantly reduced shell temperatures and enabled a hydrogen producer to avoid an unplanned shutdown while maintaining safe operation.

Case study two: online refractory repair Background Routine inspection of two critical SMRs revealed extensive shell hot spots due to refractory deterioration. With the next planned turnaround still years away, the operator required a solution that would restore refractory integrity while allowing both reformers to remain in operation.

Solution Following a detailed engineering and safety assessment, an online refractory repair programme was undertaken while both reformers remained in service. More than

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50 refractory defects were repaired across the two units, restoring the refractory without interrupting production.

Results y More than 50 hot spots repaired across two primary SMRs. y Shell temperatures reduced from approximately 550°C to 70 - 118°C in one reformer and from 469°C to 117°C in the second one (Figure 5). y Zero unplanned downtime throughout the repair programme. y Emergency shutdowns avoided, ensuring safe operation until the next scheduled turnaround. y ~US$30 million production losses were avoided as conventional repairs would have taken 8 - 10 days to complete.

Key takeaway The project demonstrated how online refractory repair can restore refractory integrity, reduce heat loss and maintain safe operation without interrupting production, enabling operators to preserve SMR performance and defer major refractory replacement until a planned turnaround.

A comprehensive approach to SMR efficiency

Improving SMR efficiency requires a comprehensive approach to heat transfer that combines performance evaluation with targeted maintenance across the radiant and convection sections. Rather than treating efficiency losses as an inevitable consequence of ageing equipment, operators can identify where energy is being lost and implement targeted interventions to deliver measurable performance improvements. The case studies presented demonstrate that optimising radiant heat transfer, restoring convection section heat recovery, and adopting condition-based maintenance strategies can reduce fuel consumption, lower CO2 emissions, and improve operational reliability. Just as importantly, many of these improvements can be achieved without major capital investment or extended production outages, as improving competitiveness while reducing emissions often comes not from revamping assets but from maximising the performance of those already in service.

Romeu Kleinubing, Emerson, USA, details how hydrogen producers must plan predictive maintenance and safety strategies early to successfully complete projects at scale.

s the world explores the multitudinous decarbonisation strategies that will define the future of energy and manufacturing, hydrogen – green hydrogen, in particular – has increasingly gained focus. Organisations around the globe are launching pilot projects and feasibility studies for

Hydrogen magnifies maintenance and safety challenges

Figure 1. Device management software, like the AMS Device Manager, provides real-time, online visibility into the health and performance of intelligent instruments and final control elements. It supports predictive maintenance, enabling teams to respond proactively to alerts, minimise unplanned shutdowns, and drive operational efficiency. new hydrogen initiatives in hopes of being in the vanguard of innovators that will capture significant competitive advantage in the years ahead. Across these emerging projects, one key factor is becoming clear: as hydrogen becomes part of industrial infrastructure, reliability and safety are non-negotiable. Unlike some energy technologies, hydrogen production is highly machinery intensive; failures are not just costly, but also potentially catastrophic. Maintenance, reliability, and safety are therefore the foundation of hydrogen’s long-term viability. As organisations expand their hydrogen infrastructure, these capabilities cannot be an afterthought, so maintenance and reliability strategies should be carefully planned from the earliest stages of project design.

A reliability-intensive industry

Hydrogen operations place extreme stress on equipment and its associated maintenance strategies, with modern hydrogen operations dominated by rotating machinery. Massive compressors, pumps and motors, turbines and generators, air separation units, cryogenic, and liquefaction systems must all work in careful synchronisation to create safe, efficient, and productive processes. Many of these assets are unique, highly customised, and non-redundant. Because each asset in the value chain is so critical, a single failure can halt production entirely, and the consequences can be dire. With safety issues, lost revenue, and potential contract penalties, unexpected outages create significant risk. In addition, because many assets are so specialised, long lead times on replacement parts and the need for very specific maintenance expertise can lead to extended outages for unprepared organisations.

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Hydrogen is especially unforgiving compared to other process media because it is odourless, highly flammable, and diffuses quickly, with leaks potentially escalating rapidly into fires or explosions. Hydrogen is also prone to embrittlement effects that accelerate wear on rotating equipment. Due to these and other issues, maintenance and reliability teams often find that hydrogen assets require more intervention earlier in their life-cycle than equipment in other industries. This makes it even more important to implement modern reliability technologies with predictive maintenance capabilities from the earliest stages of operation. The realities of the hydrogen industry also create challenges for traditional maintenance models, which rely heavily on regular maintenance routes where plant personnel perform manual data collection on a regular cadence with handheld vibration monitors. The collected data is then submitted to data analysts for post processing. However, many hydrogen plants are extremely remote, and skilled vibration and reliability expertise are often not available on site. In some cases, teams collect data but lack the experience to properly interpret it. In others, the plant lacks the personnel even to manage a regular cadence for inspection rounds, meaning data is not collected as frequently as is ideal, creating gaps in visibility. In either case, if the team does not have a deep bench of data analysts, raw data without diagnostics does not effectively improve reliability. These workforce shortages increase the need for automation and decision support.

Modern reliability architecture for hydrogen facilities

Today’s most effective hydrogen operations are planned from the earliest stages to include reliability-focused technologies as part of a structured approach. Many hydrogen plants benefit from layered reliability strategies aligned to asset risk and consequence. In most cases, this approach consists of three primary asset tiers: y Critical rotating equipment. y Essential production assets. y Balance-of-plant equipment.

Protecting the most critical assets

Continuous protection and diagnostics are mandatory for top-tier rotating assets like hydrogen compressors, high-speed turbomachinery, and large cryogenic systems. Typically, these assets are large, complex, and expensive. They also rarely have spares, meaning a failure will likely halt all production. A hydrogen facility’s critical assets will likely all ship with some form of protection system provided by the original equipment manufacturer (OEM). However, in most cases, forward-thinking organisations will want to implement additional reliability solutions to provide protection beyond the OEM-provided solution. These organisations

are deploying modern API 670-compliant protection systems that extend beyond shutdown logic by embedding comprehensive diagnostics. When employing a protection system with built-in advanced diagnostics, reliability teams enable detection of developing issues before catastrophic failure. These systems use continuous monitoring to identify developing faults in asset operation, and to then immediately notify users and the control system of aberrations. With intuitive alarm severity information streamed to the distributed control system, reliability teams can more easily prioritise maintenance responses.

Predicting failure in essential equipment

While critical assets are of the utmost importance, essential assets such as air separation compressors, cryogenic pumps, and medium-criticality compressors must also be carefully monitored and maintained to avoid unplanned outages. However, essential assets tend to benefit from asset monitoring technologies rather than full protection systems. The most advanced asset monitors can be installed right at the asset by a plant’s own technicians. The devices collect both vibration and core process data, providing teams with clear visibility to asset health and the root causes of any issues. Moreover, these advanced solutions leverage embedded AI and analytic tools at the edge to automate data collection, perform diagnostics, identify common failure modes, and recommend corrective actions.

All these features reduce dependence on local expertise and accelerate decision making to help ensure every reliability team in the organisation is operating at peak performance, collaboration, and confidence.

Scalable monitoring for balance-of-plant

While most balance-of-plant equipment will not cause extended production shutdowns upon failure, the small pumps, motors, and auxiliary compressors in hydrogen production still contribute significantly to quality, throughput, and even safety. To maintain visibility into these assets, reliability teams can implement intelligent wireless vibration monitors, which can be rapidly and flexibly deployed to provide periodic automated data collection. Because they are small and easy to install, wireless vibration monitors also provide easy scalability across facilities. An organisation can start by instrumenting the most important balance-of-plant equipment, and they can then add additional sensors as the need becomes apparent, maximising the reliability value provided per dollar invested.

Supported by software

Having the right hardware in place is a critical enabler of hydrogen industry reliability, but it is not enough. Supporting reliability hardware investments with the right software will further increase visibility, drive decision support, and enhance collaboration, across both the plant and enterprise.

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data and create a centralised historical repository for vibration and condition monitoring information. In the most advanced software, intuitive dashboards bring everything together to provide a single view into plant health and detailed root cause analysis, helping teams enable prioritisation and establish better planning and collaboration. Centralised diagnostics empower experts to analyse multiple sites remotely and provide a tool for consistent analysis, even in the face of workforce shortages (Figure 2).

Figure 2. Asset management and condition monitoring are simplified with AMS Machine Works, a software suite for monitoring, diagnosing, and resolving mechanical issues for rotating production assets like compressors, turbines, pumps, fans, blowers, gearboxes, and assets – before they affect outputs or batch quality.

Enterprise reliability software As organisations expand their footprint, management will likely want insight into reliability performance. Enterprise machinery health platforms provide key performance indicators and fleet-level dashboards to deliver visibility across multiple plants and regions. This enables knowledge sharing across sites and standardised reliability practices across the enterprise. Advanced enterprise reliability solutions also integrate seamlessly with enterprise resource planning and computerised maintenance management systems. Teams taking advantage of these capabilities can make opening and closing work orders part of their enterprise strategy, helping close the loop from incident detection to repair (Figure 3).

Predictive maintenance delivers real results

Figure 3. Enterprise workflow software, like the AMS Optics, orchestrates closed‑loop reliability across the enterprise by unifying data from rotating equipment, field devices, control loops, and advanced analytics into one modern, intuitive platform.

Device management software Device management software is critical in hydrogen plants due to the high density of process instruments and final control elements. First and foremost, to keep operations safe, teams must ensure these devices are working as expected. Device management software gives teams visibility into instrument and final control element health so they can intervene before a bad device becomes a critical blind spot (Figure 1). In addition, device management software provides benefits across the entire life-cycle with faster commissioning and start-up, bulk configuration and diagnostics, online health testing without removing devices, and calibration support.

Machinery health software Today’s most effective reliability teams are also leveraging centralised machinery health software to deliver a single view of asset health across the plant. The software connects directly to intelligent field devices to collect

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Perhaps the most important thing to understand about including reliability planning from the earliest stages of hydrogen plant engineering is that it delivers demonstrable business value across the life-cycle of the facility. Teams that implement reliability strategies and systems early and develop a clear baseline for optimal performance see significantly extended mean time between outages, lower spare parts consumption, and a 30 - 50% reduction in unplanned downtime due to their ability to intervene early, before small flaws turn into equipment failures and asset damage. Moreover, reliability directly impacts the cost per kilogram of hydrogen, contract performance, and overall competitiveness – critical areas of success in an increasingly competitive marketplace. Ultimately, with regards to hydrogen, economics, reliability, and safety are deeply intertwined.

Reliability enables hydrogen at scale

Hydrogen’s future depends on safe, reliable, and economically viable operations. That means maintenance, safety, and reliability must be built-in from the start, not retrofitted. Planning an effective reliability strategy from the earliest phases of plant design empowers teams to unlock the most effective predictive maintenance, which in turn transforms how assets are protected, personnel work, and risks are managed. As hydrogen scales globally, reliability becomes a strategic differentiator and a prerequisite for success.

Garry Hanmer, Atmos International, UK, explains how advanced AI algorithms are transforming hydrogen pipeline monitoring and safety.

ydrogen is set to play a central role in the global energy transition, with governments and industry investing heavily in production facilities, transmission pipelines and cross-border infrastructure. As these networks evolve from isolated demonstration projects into interconnected energy systems, operators face an increasingly complex operational environment. Hydrogen’s unique physical properties, combined with variable production sources, changing demand profiles and more dynamic network configurations, require new approaches to pipeline monitoring and operational decision-making. Traditional pipeline monitoring systems remain fundamental to safe operations, providing operators with

continuous measurements of pressure, flow, temperature, and gas quality. However, as hydrogen networks grow in scale and complexity, the volume of operational data generated can quickly exceed what engineers can realistically interpret in real time. The challenge is no longer collecting data, but transforming it into meaningful operational insight. Advanced artificial intelligence (AI) algorithms are increasingly being integrated alongside proven pipeline simulation and monitoring technologies to help address this challenge. Rather than replacing engineering judgement, AI enables operators to analyse large volumes of operational data, identify subtle patterns that may otherwise go unnoticed and evaluate potential future operating scenarios before they

affect pipeline performance. By combining AI with high-fidelity hydraulic simulation, operators can move beyond reactive monitoring towards more predictive, data-driven decision making.

Why hydrogen networks demand greater operational intelligence

Hydrogen presents several challenges that distinguish it from conventional natural gas transmission. Its lower density influences pressure losses and flow behaviour, while hydrogen’s interaction with pipeline materials requires careful management to minimise the risk of embrittlement in suitable steel infrastructure. In blended gas networks, hydrogen concentration can also vary spatially and temporally as gas moves through the system, creating operational conditions that are significantly more dynamic than those experienced in traditional networks. At the same time, hydrogen infrastructure is becoming increasingly interconnected. New production facilities, storage sites, industrial consumers, and export terminals introduce multiple injection and withdrawal points, while cross-border transmission projects require operators to work within different regulatory frameworks and operating constraints. These developments increase the number of variables influencing pipeline operations, making it more difficult to understand how changes in one part of the network will affect conditions elsewhere. Conventional monitoring systems provide accurate measurements at instrumented locations, but they cannot directly observe every kilometer of pipeline. As networks become more complex, operators need greater visibility into what is happening between physical measurement points, as well as confidence in how the system is likely to behave over the coming hours rather than simply understanding its current state.

field instrumentation. Pressure transmitters, flow meters, temperature sensors and gas quality analysers continuously monitor key parameters across the network. Individually, these measurements provide valuable local information. Collectively, they form a rich dataset describing the behavior of the entire pipeline system. The challenge lies in extracting actionable insight from this data. This is where advanced AI algorithms can add significant value. Machine learning techniques can identify recurring operating patterns, detect subtle deviations from expected behaviour and prioritise anomalies that warrant further investigation. Rather than requiring engineers to manually interpret thousands of individual measurements, AI can rapidly assess changing operating conditions across the network and present the information in a way that supports faster, more informed decision-making. Importantly, AI is most effective when combined with engineering models that accurately represent the underlying physics of pipeline operation. Rather than relying solely on statistical relationships within historical data, AI-assisted systems can analyse live operational data alongside high-fidelity pipeline simulations, allowing recommendations to be grounded in both observed behaviour and established hydraulic principles.

AI-powered digital twins and virtual instrumentation

One of the most significant developments in hydrogen pipeline operations is the growing use of digital twins, virtual representations of physical pipeline systems that combine real-time operational data with high-fidelity hydraulic simulation. Rather than simply displaying current operating conditions, digital twins provide operators with a continuously updated picture of how the entire network is behaving over time. In conventional pipeline systems, operators rely on Modern hydrogen pipelines already generate vast strategically positioned field instrumentation to measure quantities of operational data through SCADA systems and pressure, flow, temperature, and gas quality. While these measurements provide highly accurate information, they only represent conditions at specific locations. Between those measurement points, pipeline behaviour must be inferred. Virtual instrumentation extends this visibility by combining live measurements with transient simulation models to estimate operating conditions throughout the network. Pressure profiles, flow distribution, and gas composition can all be calculated in areas where physical sensors do not exist, creating a far more complete operational picture without significantly increasing instrumentation costs. AI further enhances this capability by continually analysing incoming operational data (see Figure 1) and comparing it with historical behaviour and simulated operating conditions. Figure 1. A visual workflow of the process involved in Atmos AIO providing Instead of simply reporting measured recommendations for optimised pipeline operation. values, AI algorithms can identify

From data collection to operational intelligence

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linepack all influence the safe operation of the network. These constraints are closely interconnected, meaning changes made to optimise one parameter can have unintended consequences elsewhere. Advanced AI algorithms help operators understand Figure 2. Trending data from a live pipeline’s recent activity (light background), along with the these complex look-ahead’s prediction of a future scenario. The circled area signposts a potential minimum pressure relationships by violation that can be prevented by taking actions early. analysing multiple operational relationships between multiple variables simultaneously, helping variables simultaneously. Rather than monitoring individual operators distinguish between expected operational changes measurements in isolation, AI can evaluate how changing and behaviour that warrants further investigation. operating conditions influence overall system performance and As hydrogen networks become increasingly interconnected, identify emerging trends that may otherwise remain hidden this system-wide visibility allows operators to make decisions within large volumes of operational data. based on the behaviour of the entire network rather than Importantly, these algorithms do not replace engineering isolated pipeline points. analysis. Pipeline behaviour continues to be governed by well-established physical principles, and high-fidelity simulation remains essential for accurately representing transient flow, Historically, pipeline control has been largely reactive. Operators gas quality and hydraulic performance. AI complements these identify changing conditions through alarms or operational models by accelerating analysis, identifying patterns and limits before taking corrective action. While this remains an supporting faster operational decision-making. effective approach for many situations, hydrogen networks The result is improved situational awareness, allowing present additional operational challenges that benefit from operators to respond more effectively to changing operating greater foresight. conditions while maintaining confidence that operational Changes in hydrogen production, storage operation or decisions remain grounded in validated engineering models. industrial demand can propagate through a pipeline over time, influencing pressure, flow and linepack well beyond the point where the original change occurred. Similarly, variations in hydrogen concentration can alter the physical behaviour of As hydrogen infrastructure continues to expand, operators will the gas, affecting pressure losses and operating margins across be required to manage increasingly diverse pipeline systems. the network. Future networks are expected to incorporate multiple hydrogen By combining AI with transient pipeline simulation, operators production pathways, blended gas supplies, underground can move beyond monitoring current conditions to evaluating storage, industrial consumers, and cross-border transmission, all how the network is likely to behave over the coming hours. operating within evolving regulatory frameworks. Forecast-based simulation (see Figure 2) enables multiple Successfully managing this complexity will require more operating scenarios to be analysed before they occur. AI can than additional instrumentation or increased computing then evaluate these scenarios, identify those most likely to power. It will require intelligent systems capable of violate operational constraints and highlight the most effective transforming vast quantities of operational data into practical response. Rather than overwhelming operators with hundreds engineering insight. of possible outcomes, intelligent algorithms can prioritise the Advanced AI algorithms are beginning to fulfil this role scenarios requiring attention and present recommended actions by supporting anomaly detection, predictive analysis and based on predicted system behaviour. operational optimisation across increasingly complex hydrogen This allows operators to identify potential pressure violations, networks. Combined with digital twins, transient simulation and capacity constraints or inventory issues before they affect high-quality operational data, they provide operators with a live operations, providing valuable time to adjust compressor more complete understanding of pipeline behaviour and greater operation, storage schedules or network configuration. confidence when making operational decisions. AI will not replace experienced pipeline engineers. Instead, it is becoming an increasingly valuable decision-support tool, Hydrogen’s physical properties require operators to manage helping operators interpret complex system behaviour, evaluate a wider range of operational constraints than traditional future operating scenarios and maintain the high standards of natural gas systems. Material compatibility, operating safety and reliability required as hydrogen becomes an integral pressure, gas velocity, hydrogen concentration and available part of the global energy system.

Looking ahead, not back

The future of AI-assisted hydrogen infrastructure

Supporting safer pipeline operations

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Danny Nicholas, Rotork, UK, provides insight into how electrification and digitalisation support maritime decarbonisation with hydrogen and other alternative fuels.

he maritime industry carries over 80% of global trade and is under growing pressure to move towards net zero.1 Regulators, financiers, charterers, and cargo owners are all tightening greenhouse gas (GHG) expectations. Shipowners are looking for practical, scalable interventions they can implement today, including solutions that cut fuel consumption, reduce leakage and maintenance, improve operational reliability, and provide verifiable data for emissions reporting.

Figure 1. The transition to alternative marine fuels is key to the future of maritime shipping.

Flow control and valve actuation are vital to vessel operation, and support fuel handling, ballast, cooling water, bilge, HVAC, cargo processes, and deck machinery. Their use across the operations creates an opportunity to improve overall vessel efficiency and performance. Electrification and digitalisation provide a practical way to enhance these operations. Electrically powered, digitally enabled actuators can help reduce auxiliary energy demand, improve control accuracy and provide greater visibility of system performance through diagnostics and data. In turn, this can support more efficient operation, simplified maintenance and better decision-making. While not a substitute for alternative fuels or propulsion changes, these technologies can complement wider decarbonisation strategies by improving efficiency and reliability onboard the vessel.

Rethinking auxiliary energy demand

Auxiliary systems use energy throughout a journey and are essential to maintaining safe and efficient operation. Across many applications, established pneumatic and hydraulic systems provide robust, reliable control, supported by compressors or hydraulic power units to ensure consistent system availability. Electric actuation offers an alternative approach to improving energy efficiency in several applications. It can help reduce overall auxiliary power demand where duty cycles are suitable. Across systems with large numbers of actuated valves, this can reduce electrical consumption. Maintenance strategies can also become predictive and preventative. Diagnostics and performance monitoring provide clearer visibility of valve condition, supporting planned maintenance activities based on actual usage and performance rather than fixed intervals. This helps reduce unplanned downtime, improve reliability and support more efficient asset management over time. This creates scope for a customisable maintenance approach, where support can be aligned to the specific assets, operating conditions, and priorities of the vessel. For operators, this creates an opportunity to optimise system design by selecting the most appropriate actuation method for each application. When applied effectively, electric actuation can support improved efficiency, reliability, and operational insight into vessel performance.

Figure 2. Supporting efficient vessel operations is a core component of the transition to alternative fuels.

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Digitalisation and condition-based maintenance

A crucial element of asset operations is intelligent asset management, which enables a company’s coordinated activities to correlate information and use it to better understand and predict maintenance needs. Data loggers built into intelligent electric actuators store data, including the number of alerts, alarm frequency, and torque profiles for individual valves. The valve health may be determined by looking at its torque average, deviation, peak levels, and opening/closing torque. A possible issue may be indicated by sudden changes. A comprehensive asset management system that analyses this data helps operators operate equipment or a site as efficiently as possible, increasing productivity and reducing operational risk. Operators can identify patterns, compare performance, and assess the effectiveness of efficiency measures.

Electrification and insetting

As well as regulatory reporting, voluntary insetting schemes are emerging as a way to reduce emissions within maritime value chains. Unlike offsetting, which relies on external projects, insetting is based on measurable improvements within shipping operations. In this context, the electrification of auxiliary systems becomes a practical way. Reductions in compressor or hydraulic demand, improved process efficiency, and lower maintenance-related losses can be directly linked to fuel savings. When supported by actuator diagnostics and system data, these improvements can be measured and verified, helping operators demonstrate tangible emissions reductions. There is a clear link between engineering upgrades and emissions outcomes. It also allows efficiency gains to be recognised within wider decarbonisation strategies, particularly where value-chain emissions are a focus.

Alternative fuels to support net zero

The transition to lower-carbon fuels is reshaping vessel systems. Hydrogen, methanol, ammonia, and LNG present different storage, handling and safety challenges, requiring new system architectures, including storage modules, pressure regulation, ventilation, venting, and purge systems. For example, hydrogen systems require high-pressure storage and controlled delivery to fuel cells, alongside dedicated ventilation. Reliable isolation and rapid shutdown are essential for safety. Actuators in these applications must operate in hazardous areas, withstand marine conditions, and provide rapid fail-safe movement. Equipment must also comply with hazardous area classifications and maintain performance in potentially explosive atmospheres. Advances in electric actuation mean that electrically powered solutions can now meet many of these requirements. Compact, explosion-protected actuators offer an alternative to traditional hydraulic systems, combining safety compliance with lower energy demand and simplified infrastructure.

Electric actuation in hydrogen fuel systems

A newbuild project demonstrated how electric actuation is being applied in hydrogen-powered vessel design. The vessel, under construction in Europe, is designed to operate using a combination of hydrogen, wind, and solar power. Its fuel system uses modular hydrogen storage, with multiple racks of high-pressure composite cylinders supplying onboard fuel cells. Each storage rack contains several cylinders storing hydrogen at pressures of up to 700 bar. Valves installed at the outlet of each rack provide isolation and must operate reliably under normal and emergency conditions. Compact electric actuators with hazardous-area certification have been specified for emergency shutdown duties. These actuators are designed to operate safely in hydrogen-rich environments and incorporate mechanical fail-safe functionality, allowing valves to move to a defined safe position within seconds during an alarm or system fault. The compact design supports installation within space-constrained modular systems, enabling direct mounting without extensive supporting infrastructure. This is particularly important where multiple valves are installed in close proximity. The actuators draw power directly from the vessel’s electrical system, which may incorporate renewable energy sources. Standardising valve components streamlines commissioning and maintenance. Embedded diagnostics offer ongoing visibility into actuation cycles and performance.

Figure 3. Condition monitoring supports preventative maintenance. While hydrogen vessels are still emerging, this project demonstrates how actuation technology is advancing to meet the safety and performance needs of alternative-fuel systems.

Actuation technologies in context

Marine applications require a range of actuation solutions depending on the operating environment and duty. Compact hazardous-area electric actuators are suited to fuel systems and safety-critical applications where explosion protection, fast response, and a small footprint are essential.

Hydrocarbon Engineering

Rieks de Rink, Joost Timmerman, and Jan Henk van Dijk, Paqell B.V., the Netherlands, alongside Maitham Shidi, Petroleum Development Oman (PDO), and David Street, SLB – Process Technologies and Solutions (PTS), USA, discuss the start-up and operation of a new biodesulfurisation unit for flare gas recovery in Oman.

The leading magazine D for the global downstream oil and gas sector uring crude oil production, natural gas is often released as a by-product, known as ‘associated gas’. When there is no infrastructure or market available, this gas is typically flared on-site. The International Energy Agency (IEA) has estimated the global flaring and venting of associated gas to be 200 - 250 billion m3/yr (approximately 25% of the total amount of associated gas).1 Besides huge economic losses, the venting and flaring of associated gas causes massive emissions of carbon dioxide (CO2), methane, and sulfur dioxide (SO2).1-3 In 2015, the World Bank launched the ‘Zero Routine Flaring by 2030’ initiative to eliminate continuous flaring of associated gas by the end of this decade.3 The Sultanate of Oman and its main oil and gas company, Petroleum Development Oman (PDO), joined the initiative in 2017.4 To stop flaring and enable effective use of associated gas, field-level implementation of gas treatment processes is required. At an existing production facility of PDO in Oman, the main gas processing system is at the end of its

lifetime and due for replacement. PDO decided to install a new gas treatment plant for the recovery of sour flare gas from oil production for export into the existing gas network. Due to the high H2S concentration of the sour flare gas, desulfurisation of the gas is required. In the new gas treatment plant, the flare gas streams are first pressurised to 4 bar(g), mixed, and then routed to a gas sweetening unit (GSU) for the removal of H2S and recovery of elemental sulfur. Subsequently, the gas is further pressurised to 70 bar(g) for dehydration and dew pointing, before injection into Oman’s existing fuel gas network. After a careful assessment by PDO, the Thiopaq O&G (TOG) technology was selected for the project.

The biodesulfurisation process

The GSU is a TOG unit, a biotechnological process driven by the conversion of H2S into elemental sulfur. Originally developed for the desulfurisation of biogas, the process was introduced in the oil and gas industry in 2002 as an environmentally friendly and cost-effective alternative

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For other systems, intelligent electric actuators support multi-turn and quarter-turn valves across ballast, cooling water, cargo handling, and auxiliary processes. These provide robust performance alongside integrated control, diagnostics, and communication capabilities. Smaller electric actuators can be used for precision control and pressure regulation duties, including fuel delivery and refuelling systems. Selecting the appropriate technology for each application is essential to balance safety, performance, and efficiency.

Transitioning to electric actuators

The transition to electric actuators can be managed over time. An inspection would identify processes with high energy use, product life-cycle management, or operational risk. Priority is often given to applications where improved control, reduced energy demand, or enhanced safety will have the greatest impact. These include hazardous fuel systems, ventilation and purge control, ballast operations, and HVAC. Integration with vessel automation systems should be considered early to ensure compatibility and effective use of data. Establishing baseline performance allows improvements to be measured after implementation. While electric systems simplify many aspects of operation, effective use of diagnostics and control functions depends on familiarity and understanding.

Incremental progress towards decarbonisation

Maritime decarbonisation will depend on a combination of technologies and operational changes. Alternative fuels such as hydrogen, propulsion systems, vessel design, and operational efficiency all contribute. Electrification and digitalisation of actuation systems represent a practical, complementary approach. By reducing auxiliary energy demand, simplifying maintenance, improving control and providing verifiable data, electric actuation supports more efficient and transparent vessel operation. As systems become more complex and data-driven, these capabilities will become increasingly important, particularly as vessels integrate hydrogen and other alternative fuels, in which safety, precision, and reliable system control are critical. While not a standalone solution, electrified actuation is an enabling technology that supports safer fuel systems, improved efficiency and more robust performance verification. In a sector characterised by long asset life-cycles and complex integration, these progressive improvements play an important role in the transition towards lower-emission shipping.

Reference

1. Shipping data: UNCTAD releases new seaborne trade statistics | UN Trade and Development (UNCTAD).

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