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Winter 2023 Volume 2 Number 7 ISSN 2977-1927

03 Comment 04 The journey to a hydrogen future

34 The transformative role of tunable diode

08 The reality of building a green hydrogen

38 Focusing on oxygen in hydrogen analysis

laser spectroscopy

Frederic Thielland, David Janssens and Sebastian Fischer, Siemens, Germany, outline the benefits of using tunable diode laser spectroscopy (TDLS) in green hydrogen production plants.

The pathway to 2030 is set to be one of decisive action for the hydrogen economy, Manish Patel, Air Products, UK, explains.

plant

A. Kigel and A. Shats, Modcon Systems, UK, reveal how advances in in-situ analysis are resulting in precise oxygen monitoring in hydrogen production.

Brenor Brophy, Plug Power, USA, looks back at valuable lessons learnt from commissioning and building a green hydrogen plant and reviews how they can be applied to future projects.

44 Safety without compromise

Andrzej Janowski, MSA Safety, examines workplace safety risks and challenges posed when producing, handling, transporting and storing hydrogen.

14 Turning waste into hydrogen: a new path towards emissions reduction

Uwe Wagner, Endress+Hauser, Switzerland, introduces a new method of hydrogen production using thermal waste treatment and outlines the metrological challenges that must be overcome in the process.

48 Clearing the fog

Dinesh Pattabiraman and Manish Verma, TMEIC Corp. Americas, USA, address the impact that power supply can have on the cost and efficiency of electrolytic hydrogen production.

19 Feel the force

Brian Peters, Interface, explores how force measurement sensors can make production, storage and monitoring solutions for hydrogen more efficient.

53 Charged up

Nora Han, ABB System Drives, Switzerland, outlines the importance of efficient power supply in green hydrogen production.

23 Solving the paradox

Carbon capture requires significant energy input, generating more carbon and creating a new problem. Janka O’Brien, Emerson, UAE, explains how advanced automation technology will play a major role in helping to solve this.

57 Hydrogen’s marine fuel potential

Adoption of hydrogen as a marine fuel is still in its early stages but the opportunity to support shipping’s net-zero journey is clear. Panos Koutsourakis, ABS, explores how hydrogen can fulfil its potential role.

28 Pushing the boundaries

60 News

Dr Peter Geiser, Dr Viacheslav Avetisov and Ove Bjorøy, NEO Monitors, Norway, examine how tunable diode laser absorption spectroscopy (TDLAS) can aid industrial decarbonisation by pushing the limits of hydrogen measurement.

This month's front cover

A revolution in converting waste to sustainable energy With the help of reliable process measurement devices and support from Endress+Hauser, the new Wildfire Energy pilot plant is successfully showcasing the viability of hydrogen and syngas production from biomass and residual waste. Find out more, starting on p. 14.

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ydrogen was under the spotlight during the recent COP28 conference, held in Dubai, UAE. For the first time, countries agreed on the need to “transition away from fossil fuels in energy systems”, and there was a call for an acceleration of zero- and low-emission technologies, including low-carbon hydrogen production. A suite of flagship initiatives were launched with the intention of commercialising hydrogen and to unlock the socio-economic benefits of cross-border value chains for hydrogen and its derivatives. One of these initiatives was the intergovernmental ‘Declaration of Intent on Mutual Recognition of Certification Schemes for Hydrogen and Hydrogen Derivatives’, which was launched by more than 30 countries. Endorsers of the declaration seek to work toward mutual recognition of hydrogen certification schemes to help facilitate a global market. The declaration covers over 80% of the future market in hydrogen and its derivatives. Other initiatives launched during the conference included ISO methodology providing a global benchmark for greenhouse gas emissions assessment of hydrogen pathways on a life-cycle analysis basis, and a Public-Private Action Statement on cross-border trade corridors in hydrogen and derivatives in partnership with the International Hydrogen Trade Forum (IHTF) and the Hydrogen Council. The initiatives were launched at the COP28 Presidency’s High-Level Roundtable on Hydrogen, which was attended by over two dozen ministerial officials of the prospective hydrogen importing and exporting countries. A delegation of top executives from 15 industrial leaders in hydrogen (members of the Hydrogen Council) were also present at the roundtable. Executives from Air Liquide, Air Products, Baker Hughes, Chart Industries, InterContinental Energy, Kawasaki Heavy Industries, Linde, Topsoe and others outlined their significant investments in the sector, and called for incentives and clear regulation to help advance the industry. Dr Fatih Birol, Executive Director of the International Energy Agency (IEA), noted that the initiatives launched during COP28 can be a “vital catalyst for accelerating clean energy transitions.” Meanwhile, Gerd Müller, Director General of the United Nations Industrial Development Organization (UNIDO), praised the work carried out during the conference to advance clean hydrogen as the fuel of the future, arguing that “a just, low carbon hydrogen transition needs all of us to work together, share our knowledge and resources.” In this issue of Global Hydrogen Review, we share the expertise of a number of industry leaders who are helping to advance the hydrogen revolution. As you read through this issue, you will discover lessons learnt from the commissioning and building of a green hydrogen plant, a new method of hydrogen production using thermal waste treatment, the important role of advanced automation, and the impact that power supply can have on hydrogen production, plus much more. I’d also like to take this opportunity to thank those of you who joined us for the third edition of our Global Hydrogen Conference back in November. The event was a great success, with around 1300 professionals from 95 countries registering to attend. I hope that you found the series of expert presentations insightful and informative. Stay tuned for more information about the fourth edition of the conference, coming next year.

The pathway to 2030 is set to be one of decisive action for the hydrogen economy, Manish Patel, Air Products, UK, explains.

he need to transition away from fossil fuels has been pressing for some time, but the global energy crisis is a driver that will accelerate the role of hydrogen in energy security, as well as decarbonisation. The most efficient low-carbon hydrogen production pathway varies according to the availability of renewable energy sources and the capability of the existing infrastructure around the world. In regions where there is limited availability of renewable energy, such as North West Europe, providing reliable green hydrogen at scale can be achieved by the use of imported renewables, as well as local electrolysis operated on renewable power when available. There can be no doubt that hydrogen will play a crucial role in decarbonising energy supply to industry. It is already widely used as a process gas, from metal processing to chemical production and glass manufacturing. Attention must now turn to how hydrogen’s potential as a low-carbon energy source can be unlocked and how its ability to decarbonise many more hard to abate sectors can be utilised. So far, progress has been made, but it also needs to be financially viable. Financial support for hydrogen must be technology agnostic. End users, i.e. industry, should decide on the most efficient production pathways to ensure the most appropriate infrastructure is built for their needs. This will avoid leaving the UK’s industry with inefficient infrastructure once subsidies stop. In short, narrow production pathways risk leaving UK industry with a higher cost base for hydrogen than countries who are technology agnostic. This would, in turn, weaken the UK’s position on an international market. By combining domestically produced and imported renewable energy to produce green hydrogen, there is an opportunity to propel the international hydrogen economy forward and build a globally-viable market more quickly. To deliver, there are three core areas that require immediate attention: supply, infrastructure, and market support.

Energy security and the global market

How the production pathway works

Air Products’ three proposed hydrogen energy import terminals in Europe in Immingham, UK; Hamburg, Germany; and Rotterdam, the Netherlands, are examples of how renewable energy could be received and used to produce green hydrogen in large, reliable quantities, providing a secure baseload to specific geographies. The detail behind these proposed import terminals is interesting. In the UK, Air Products and Associated British Ports (ABP) are proposing to bring a new green hydrogen facility to the Port of Immingham, based on imported renewable energy. The scheme would supplement another Air Products initiative to develop the UK’s largest blue hydrogen cluster in the same area, making Immingham a major new location in the UK for low-carbon energy production, businesses, and jobs. The green hydrogen terminals would receive the renewable energy, in the form of ammonia, by ship. The ammonia would be kept refrigerated at -32°C so that it is a liquid, making it easier to transport. From the very large gas carrier (VLGC), it would be pumped into a very large tank and from there, as needed, into the hydrogen production facility. The ammonia molecules would be split into nitrogen and hydrogen. The hydrogen gas produced would then be purified and transferred via pipe to the hydrogen liquefier unit. In this unit, the hydrogen would be refrigerated into a liquid to make it easier to store and transport by road tanker to hydrogen refuelling stations around the country, or directly to industry. The ambition is that these terminals will store the renewable energy which will be used as feedstock to produce hydrogen: domestic renewable hydrogen. This approach will complement and encourage production based on domestic renewable energy. However, hydrogen production based on imported renewable energy has the advantage of providing a reliable source of green hydrogen independent of domestic weather patterns and, if Figure 1. A CGI of Air Products’ proposed green hydrogen production facility in approved, these facilities would go some Immingham, UK (for illustrative purposes only). way to alleviating supply issues in the hydrogen market. This is truly a step-change: if these projects are approved, they will be creating a new, global renewable energy supply chain, moving renewable energy from where it is produced to where it is needed. ‘Hydrogen hubs’ are also developing across the globe, responding to the accelerating demand for clean and secure energy to meet climate objectives and the need to diversify energy sources. Air Products’ terminals can play a vital role in these hubs – specifically the company’s plans to build the country’s first large-scale, renewable energy import terminal in the Port of Hamburg with Mabanaft. The Figure 2. Heavy goods vehicles are particularly suited to be fuelled by hydrogen. terminal’s location offers strategic access Consider the UK market as an example. Meeting the UK’s net zero ambitions will mean relying on a secure and diverse energy mix, for which all technologies will need to play a role. Green hydrogen produced with renewable ammonia can support the UK to decarbonise, while local electrolyser capacity can be established in parallel. However, it is worth noting that local production of renewable energy will always bring challenges as the UK does not have an abundance of wind and solar. Hydrogen plays an important role, not just as a strategic clean energy reserve, but as a product to generate economic growth for the country. The Department for Energy Security and Net Zero said the UK needs to be noted as a ‘world leader’ in investigating the use of hydrogen for a range of functions.¹ Recognising the opportunity, the UK government has set accelerated ambitions to grow the hydrogen market, including by using imports. In its ‘Hydrogen Strategy Update’ in July 2023, it set out a commitment to define a hydrogen standard and create a certification scheme by 2025, to ensure that high quality hydrogen, whether imported or locally produced, meets the same high standards. The results of this consultation will undoubtedly unlock opportunities for the hydrogen economy to grow.

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Winter 2023

to renewable ammonia from facilities such as NEOM and could provide hydrogen to Germany by 2026. Elsewhere in Europe, Air Products and Gunvor Petroleum Rotterdam have also signed a joint development agreement for an import terminal in Rotterdam. The import terminal could provide green hydrogen to the Netherlands from 2026 onwards.

What needs to happen now?

The UK government has been at the forefront of developing a decarbonisation roadmap but other countries are now catching up. There is a risk that the UK could be left behind as companies choose to invest in countries with favourable Figure 3. Hydrogen fuelling demonstrated at Air Products’ refuelling station at policies. Distinguishing between conceptual Heathrow, UK. projects (with target pricing) and actual projects (post financial investment The government has two options to ensure targets for decision [FID]) is also important. Failure to do so is leading to emissions reductions are met: mandate the use of only off-takers delaying signing up to real projects. low-carbon fuels or provide enough support mechanisms Globally, Air Products is investing more than US$15 billion to encourage early take up. That support has to be directed in actual projects that will be onstream by 2027, such as the to at-scale supply of low-carbon energy to ensure value NEOM project in Saudi Arabia. The company also aims to drive for money and the largest environmental benefit for every the decision forward for a green energy import terminal and pound spent. For fuel switching, there needs to be support in associated domestic hydrogen production in Immingham. This the early days, particularly in modifying equipment to ensure facility would create 1400 direct jobs and deliver £4.6 billion in the quality of the end product is not affected. financial benefits for a key levelling up area. The role of hydrogen for transport should also not be forgotten. Air Products operates several hydrogen refuelling stations in the UK. Existing (and future) stations need green Generating a cleaner future requires experience, investment, hydrogen to support transport decarbonisation, which could and innovation on a world scale. To drive this forward, be brought from Immingham. experts need to be called upon to showcase the latest In the future, local production with domestically produced technology, provide the capital, and deliver on the ambition renewables at scale can be viable. However, this is decades to bring the hydrogen economy to scale. This includes away and the decarbonisation of hard to abate industries export-driven projects in regions of the world where the needs to be kickstarted by offering reliable green hydrogen conditions favour the generation of the renewable energy now. The technology exists today, however there are a needed for the production of green hydrogen. number of significant barriers that need addressing. Heavy Collaboration and support across industry and government industry requires a large scale, reliable supply of hydrogen is required to ensure that investment is encouraged, and which will be difficult to develop under current policy. hydrogen is available at scale. By producing and distributing Clearer policy needs to be seen on green and blue hydrogen renewable and low-carbon hydrogen solutions for use in to de-risk private sector investment. heavy-duty fuel cell vehicles, industrial applications, and It will be many years before local renewable energy energy storage, the energy transition can accelerate. sources are sufficiently established and can provide a reliable Deadlines are upon us, and the challenge ahead is all supply. The reality is that subsidising local electrolytic and too real. However, with greater collaboration between not subsidising imported renewables, risks favouring small governments, producers, OEMs and industry operators, scale intermittent supply at the expense of larger scale hydrogen can – and will – provide a critical part of the constant green supply sources which are more suited for solution. The goal on the pathway to 2030 remains the same those industries that are hard to abate. – to minimise carbon emissions, reduce reliance on finite There is an urgent need to fix this cycle, with demand for resources, and allow diversification of energy sources. The renewable energy in the near and medium-term set to grow journey to a hydrogen future is well underway. rapidly. Local economies need guidance and support to help overcome the key barriers to investment in infrastructure fuel: high upfront costs and uncertain financial returns in an 1. https://www.gov.uk/government/publications/energy-securitybill-factsheets/energy-security-bill-factsheet-enabling-theemerging market means that there is hesitation to begin the hydrogen-village-trial. journey to decarbonisation.

The pathway ahead

Reference

Winter 2023

GlobalHydrogenReview.com

Brenor Brophy, Plug Power, USA, looks back at valuable lessons learnt from commissioning and building a green hydrogen plant and reviews how they can be applied to future projects.

enewables are now the least expensive way to produce energy, putting the dream of a cost-effective, carbon-free, energy-dense molecule within striking distance. Many companies across industries are now looking at producing green hydrogen. Demand for electrolysers, or even full-scale electrolytic hydrogen plants, is actively increasing. The problem is that few companies know what it takes to get a project done – especially at commercial scale. There is a lot of excitement surrounding the potenital of green hydrogen for decarbonising fertilizers, refineries, mobility/transportation sectors, and more. However, such projects are often complicated. Because Plug has built a liquid green hydrogen plant at scale, it is in a good position to inform those interested just what it takes to get it done.

At 45 MW, Plug’s new 17 tpd green gaseous and liquid hydrogen plant in Camden County, Georgia, US, is not only currently the largest green hydrogen plant in North America, it is also the largest operational proton exchange membrane (PEM) plant in the world. This is a title that the plant is unlikely to hold for long, as Plug and other companies have larger projects in the works. However, as the first of a new generation of PEM electrolysis plants to reach commissioning and production, it is helpful to look back on the lessons learnt and discuss how these can be applied to future projects.

Two plants in one

The Georgia plant is in fact two plants in one: a 5 MW gaseous plant capable of producing 2 tpd of hydrogen at 550 bar and an additional 40 MW liquid hydrogen plant. The smaller plant was built first, both to provide an early cycle of learning with the

PEM electrolyser equipment, and as a valuable production plant to service gaseous customers in the southeast region. Plug called this small, self-contained plant, ‘Pathfinder’, which was its main function during the debugging and tuning of the first single-skid 5 MW PEM electrolyser produced. This allowed the larger liquid plant to start construction with a significantly more mature base technology. The liquid plant is comprised of eight of the same 5 MW PEM electrolyser skids used in Pathfinder. These modules are housed in a single building that provides shelter, ventilation, and other critical safety systems. Upstream of the electrolyser building, the electrical infrastructure includes eight 5 MW transformer rectifiers packaged in 40 ft containers, an e-house holding medium-voltage switchgear and motor controllers, and a small substation that interfaces to the 115 kV transmission voltage supply to the site.

Downstream of the electrolysers is a pressure swing absorption (PSA) stage to remove water and then a 15 tpd helium-cycle hydrogen liquefaction plant. This plant is an evolved version of the same plant that Plug has operated for several years at its hydrogen facility in Tennessee, US. Two 90 000 gal. liquid hydrogen storage tanks provide 48 t of storage, or approximately three days of production. A common loading area allows the filling of gaseous tube-trailers or liquid tankers.

Site selection and permitting

There are at least three considerations required before breaking ground: site selection, due diligence, and obtaining the right permits. In many locations, this will be a slow and arduous journey. For Plug’s first plant, the initial site selection criterion was simply the southeastern US. The best locations for hydrogen

plants are sited within a service territory defined by the distance a truck can drive in 11 hours. In this case, the facility must serve all of Florida. The final site was selected in Camden County, Georgia, because it met the first criteria and had easy freeway access. The local authorities in Camden County – in conjunction with the local electric utility – were key to the project’s success. They went above and beyond to win the project for their location. At this stage, many battles are won or lost before they start, but this project was one of the smoothest early-stage developments Plug has completed to date. While the people of Camden County could not have been more welcoming, the soil of the county was a different story. Like much of the area, the site had a high water-table and poorly consolidated ground. This required a significant amount of civil work to prepare the site for construction and then significant piling and heavy foundation work.

acres in the northwest corner of the site, the site preparation took place across the full site of approximately 20 acres. The Pathfinder project, which included a single 5 MW electrolyser skid in its own building and associated 5 MW transformer rectifier, e-house, cooling tower, gas dryer skid and dual PDC compressors, was declared mechanically complete in April 2022. Development of the 5 MW electrolyser was completed at the same time as construction of the Pathfinder project, so final development, including controls integration of the equipment was completed onsite. The first hydrogen gas was produced in August 2022, one year after breaking ground. The decision to build the smaller project first was a valuable one. A good deal of the project was first of its kind, and there were many obstacles and problems to understand and overcome, but on a smaller scale they were more manageable and less expensive to resolve. It enabled the larger project to start from a far more mature equipment base, with a more experienced commissioning and operations team. The preliminary engineering study (FEED) for the larger liquid Plug broke ground on the initial Pathfinder 5 MW gaseous plant plant kicked off in September 2021. This continued through the in early August 2021. While this plant occupies just a couple of winter while civil site preparation was underway. The purpose of a FEED study is to do enough engineering to accurately cost and schedule the project and to enable the start of procurement on long lead-time equipment. It also forms the basis for the EPC contract bid and is the gate to a final investment decision (FID). The full EPC contract was awarded in May 2022 and full construction mobilised on the site the next month. The plant produced its first gas in August 2023. At the time of writing, commissioning of the liquefaction train is ongoing, with full production expected before the end of 2023. The development speed of this project Figure 1. Plug’s Pathfinder plant has been producing up to 2.1 tpd of gaseous green hydrogen has been exceptional given that this since August 2022. is the first large facility using the first generation of large-scale electrolyser equipment.

From groundbreaking to production

Plant design

Figure 2. Eight 5 MW PEM electrolysers are installed for Phase 1.

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Winter 2023

The plant is designed around Plug’s 1 MW PEM electrolyser stack. The decision to group them into 5 MW skids was driven by availability of off-the-shelf 5 MW transformer rectifiers. This equipment is essentially a solar inverter converted for use as a rectifier. The fact that thousands of these systems have been deployed, and that there is a robust and cost-engineered supply chain, drove the decision to minimise risk on a piece of equipment that has historically been an Achilles’ heel for electrolyser systems. Much of the equipment on the electrolyser skid, including the stacks,

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are not designed for outdoor installation. The equipment must be protected from freezing conditions and kept clean and dry. While temperature extremes were not a primary concern at the location, hurricanes, wind, and rain certainly were. Plug needed a building to enclose and protect the electrolyser skid. The presence of hydrogen within the stacks, pipes, and vessels on the skid also meant that the area within the building had to be ventilated sufficiently, and the ventilation interlocked with hydrogen production to avoid classification as a hazardous area. As a result, the building was an integral part of the plant safety functions. The size of the liquefaction train, rated at 15 tpd, drove the grouping of eight skids to create a 40 MW plant. At 40 MW, the electrolyser plant is slightly oversized with a nameplate capacity of about 17 tpd. This excess capacity serves two purposes. First, electrolyser stack efficiency increases as current-density reduces. That means there is an optimal operation point that is a cost-per-kg minimum for a given capital cost and energy cost. For this plant, that point is about 86% of nameplate. Second, this also allows one full skid to be offline for maintenance and for there to be sufficient capacity in the remaining seven skids to keep the liquefaction plant running at full capacity. The basic decisions around plant architecture were made more than two years ago. Since then, Plug has learnt a great deal over the course of the project that has helped to refine the design of future plants. Plug is also refining its own electrolysers based on the hardwon experience of building a full-scale plant. Over the last two years, the green hydrogen space has accelerated, especially in the US. The passage of the Inflation Reduction Act (IRA) and the introduction of the low-carbon hydrogen production tax credit has lit a fire under hydrogen development. This acceleration is probably best reflected in plant scale. Today, Plug’s minimum plant size is 30 tpd and multiples of that.

Capital cost structure considerations

The capital cost structure of the project looks like a typical gas or chemical processing plant. Engineering, construction management, and labour are more than half of the total invested capital. The typical model of an EPC integrating many separate pieces of equipment generates a huge amount of engineering and construction.

While this is not surprising, this cost structure is not sustainable if green hydrogen is to become a truly renewable technology and achieve the scale of deployment required to move away from fossil fuels. It also means that when planning a green hydrogen plant, the major cost driver is not the electrolyser equipment. The engineering and construction costs are far more significant. For Plug’s plant, the need for a building to house the electrolyser skids drove the cost significantly. While pre-engineered-metal-buildings are relatively low-cost, their foundations, erection, and provision with electrical, ventilation, fire-suppression, and other systems is a cascading series of costs that was a significant piece of the overall budget. Green hydrogen plants use a lot of energy – it is their main feedstock. This means that even though this is a relatively small facility compared to other industrial sites, it is still energy hungry. Consequently, the upstream medium and high voltage equipment was also a significant cost driver, with a considerable portion of the site given over to switch stations, substations, transformers, and switchgear.

Lessons learnt These plants are complex, early learning is critical The smaller Pathfinder project was invaluable given the early stage of the electrolyser equipment development. But it is an expensive way to learn and only made sense for Plug as there was a market need for gaseous hydrogen. The electrolyser equipment has matured and Plug now offers a Basic Engineering Design Package (BEDP) that provides the engineering and plant integration details to allow a full plant FEED study to proceed quickly.

Electrolysers need to live outside Equipment that is designed with its own all-weather enclosure and that solves the hazardous area classification, ventilation and safety issues within its own footprint is enormously valuable.

Scale matters It is almost as difficult to build a small plant as it is to build a large plant. Building at the largest scale possible helps amortise the costs, effort, and time across the largest possible output and income.

Figure 3. Plug’s Georgia plant will produce 15 tpd of liquid green hydrogen by the end of 2023.

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Winter 2023

There are huge cost savings to be realised in equipment integration Fundamentally, plant engineering is about the connections between equipment. Encapsulating those connections within the equipment can vastly simplify the plant engineering and subsequent construction. One of the lessons of the renewable energy industry is that highly integrated equipment, manufactured in factories, drives relentless cost reduction. Today, hydrogen equipment is only just starting down that path, but for companies that are focused on making green hydrogen a true renewable technology, the path forward is clear.

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Uwe Wagner, Endress+Hauser, Switzerland, introduces a new method of hydrogen production using thermal waste treatment and outlines the metrological challenges that must be overcome in the process.

he move towards zero-emissions energy generation is gaining importance within the context of climate change driven by human activities. Hydrogen is a vital energy source in a renewable energy economy of the future: it has the potential to replace fossil resources and fuels in the medium to long-term, not only in the mining, minerals and metals industries, but also in transport. In addition to electrolysis using renewable electricity – the standard process for producing climate-neutral, ‘green’ hydrogen – other emissions-free or reduced-emissions methods of production could also have a major impact in the future. Today, approximately 98% of hydrogen is generated from fossil fuels, primarily through the steam reforming of natural gas (‘grey’ hydrogen).

The thermal recycling of municipal waste (and similarly composed waste) provides another possible source of hydrogen. In 2022, over 2600 waste treatment plants were in operation worldwide with a capacity of approximately 460 million tpy.¹ Up until now, this sector has been dominated by traditional incineration processes that fully utilise the energy content of the largely organic waste to generate electricity and/or heat. Given that, according to a forecast by the World Bank, the global volume of waste will continue to grow significantly from today’s approximate 2.1 billion tpy to 3.4 billion tpy in 2050, alternative treatment processes, which should ensure more efficient recycling of the waste and therefore a reduction in the landfill space required, are coming to the fore.² The reason for this is that the methane emissions from landfilled organic waste – about 25 times more harmful to the climate than CO2 – contribute significantly to the warming of the earth’s atmosphere. While 100% of municipal waste is thermally treated in Switzerland today, and only the residues that remain after incineration and cannot be used for other purposes are landfilled, the dumping of untreated waste is still widespread in developing and emerging countries. Approximately one seventh of global methane emissions can be traced back to landfill.³

Alternative methods for thermal waste treatment: waste-to-X

Alternative methods can be used either as a further treatment stage in addition to combustion, or as a stand-alone process. Examples include thermochemical processes such as pyrolysis and gasification: in this case, the feedstock is not fully oxidised, but partially converted to liquid and/or gaseous components (‘synthesis gas’ or ‘syngas’) at temperatures of up to 1200 °C.⁴,⁵ These components can then be thermally recycled or separated and used for secondary purposes, for example as a raw material in the chemical industry or as a fuel in transport – the hydrogen separated from the syngas can be used as a fuel for fuel cell vehicles, for example. While conventional incineration processes focus primarily on the generation of electrical energy (waste-to-energy [WtE]), a broader range of valuable end products can therefore be produced using alternative processes. Therefore, we generally speak of ‘waste-to-X’ (WtX) solutions in this case or, if the focus is mainly on hydrogen production, of ‘waste-to-hydrogen’ (WtH). The aim of using alternative waste treatment technologies is to achieve higher energy efficiencies, higher-quality conversion products and/or lower emissions than would be achievable by simply incinerating the feedstock. For example, in terms of the energy balance, a WtH process must therefore be more efficient than electricity generation from a traditional incineration plant and subsequent electrolysis. These requirements generally call for significantly more complex, and therefore cost-intensive, plant technology compared to conventional combustion. Although they have been tested for approximately 50 years already, alternative methods have only become established Figure 1. Simplified illustration of the MIHG process. Copyright: Wildfire. under special conditions, in Japan for example.⁵ However, stricter climate protection regulations and increasing landfill costs could also be expected to lead to a change in the competitive situation in Europe and other densely populated regions of the world in favour of more efficient waste recycling. This prospect, along with the current focus on hydrogen production with lower greenhouse gas (GHG) emissions, has led to more intensive research and development in this area. Currently, several companies are Figure 2. Possible feedstocks and products. Copyright: Wildfire. working on optimised processes

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Winter 2023

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requirements. This facilitates short distances from the source to the recycling of the waste and a corresponding reduction in CO 2 during transportation. In addition, plants can be easily adapted or moved to another location if the volume of waste increases. Wildfire Energy therefore sees the MIHG process as a flexible addition to recycling in order to drive forward the transition to a circular economy for materials and products.

Challenges for the measurement technology Figure 3. The team from Wildfire Energy at the pilot plant site. that also aim to be competitive. One such example is the Australian start-up, Wildfire Energy, whose process is based on the familiar gasification process which takes place at over 800 °C, but differs fundamentally from conventional gasifier technologies in terms of plant design. In a process known as moving injection horizontal gasification (MIHG), oxygen is injected horizontally under the waste layer to enable particularly efficient conversion of the organic waste into syngas.⁶ The basic operating principle of MIHG is shown in Figure 1.

Higher overall efficiency, scalable plant engineering

According to Wildfire Energy, the MIHG process offers multiple advantages. Firstly, heterogeneous waste – which can be problematic for many of the processes in place – can also be treated without complex pre-processing (for instance sorting and shredding of waste fractions). Secondly, the process should ensure high WtX yields: this means that roughly 42 kg of hydrogen can be produced per t of feedstock (mixed waste with a calorific value of 12 MJ/kg). Alternatively, the CO and hydrogen components contained in the syngas can also be used for the production of fuels, methanol or ethanol. The various possible uses are shown in Figure 2. Wildfire Energy cites the more favourable GHG balance compared to sending untreated waste to landfill as a further advantage of its process: in the case of WtE, negative emissions of up to 850 kg CO2 eq/MWh could be achieved with MIHG by avoiding methane emissions. In this comparative calculation, the WtH path would also be CO2-negative and therefore have an advantage over conventionally produced grey hydrogen in terms of climate protection. Thanks to its modular design, the MIHG process should also open up the possibility of creating small, flexible plants. This is important for the competitiveness of the process with conventional waste incineration, which for the most part takes place in large plants far away from urban centres today. While typical capacities of large incineration plants are several hundred kilotonnes of waste per year, a MIHG reactor processes small quantities from 4000 tpy, whereby upscaling to approximatley 50 000 tpy is possible. Housed in standard containers, the number of modules can be customised to suit local

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Reliable measurement and monitoring of key process parameters such as temperatures, pressures and gas volume flows are central in optimising the process flow. When setting up its first pilot plant, Wildfire Energy therefore placed its trust in the Swiss measurement technology manufacturer, Endress+Hauser. One particular challenge was to ensure accurate measurement at very low pressure in the MIHG reactor – an important requirement for the precise calculation of the volume flow in the syngas and hydrogen production. In addition to flow meters with different measuring principles, temperature sensors, pressure transmitters and level switches for accurate level measurement were used in the Wildfire pilot plant. With this pilot plant, Wildfire Energy was able to demonstrate that MIHG technology delivers on the expected results. Production is currently being upscaled with the aim of commercialising the technology worldwide. Endress+Hauser is also involved in this next development stage as technology partner to guarantee a high yield and quality in the production of syngas and hydrogen. The measurement technology manufacturer also hopes to gain new insights and economic potential from participating in this groundbreaking project. If the Wildfire technology proves its worth in practice, this would not only open up new perspectives for thermal waste treatment as a whole, but also for emission-reduced hydrogen production. Wildfire Energy is confident that it will be able to achieve a favourable hydrogen price of US$2/kg and therefore create the conditions for widespread use of the MIHG process.

References

1. ‘Waste to Energy 2022/2023: Technologies, plants, projects, players and backgrounds of the global thermal waste treatment business’, (2022), https://ecoprog.com/de/publikationen/datawte 2. ‘What a Waste 2.0, A Global Snapshot of Solid Waste Management to 2050’, World Bank Group, (2018), https:// datatopics.worldbank.org/what-a-waste 3. ‘A critical review on the principles, applications, and challenges of waste-to-hydrogen technologies, Renewable and Sustainable Energy Reviews’, (2020), https://www.sciencedirect.com/ science/article/pii/S1364032120306535?via%3Dihub 4. ‘Sachstand zu den alternativen Verfahren für die thermische Entsorgung von Abfällen’, Umweltbundesamt, (2017), https:// www.umweltbundesamt.de/sites/default/files/medien/1410/ publikationen/2017-03-06_texte_17-2017_alternativethermische-verfahren_0.pdf 5. ‘Abfallverbrennung in der Zukunft (Waste Incineration in Future)’, Dechema Position Paper, (2022), https://dechema.de/dechema_ media/Downloads/Positionspapiere/2022+03_Positionspapier_ Abfallverbrennung+2022-p-20008505.pdf 6. Wildfire Energy, https://www.wildfireenergy.com.au

Brian Peters, Interface, explores how force measurement sensors can make production, storage and monitoring solutions for hydrogen more efficient.

he use of hydrogen as a clean and reliable renewable energy source has been a carrot on a stick for green energy innovators for many years. Scientists and technologists have understood the positive impact of hydrogen for a long time, and even harnessed it at times, but the ability to reliably transport, store and harness this energy at a reasonable cost has previously eluded them. However, hydrogen is back in full force as storage and battery technology has advanced, giving new life to the promise of hydrogen. Hydrogen is critical to the future of green energy because it is an optimal solution to storing renewable energy from other sources such as wind and water. Certain areas, such as California, US, are actually producing too much energy from renewable sources as there is nowhere to store it. This is leading

to a tremendous amount of resource loss. Therefore, hydrogen innovation investment is on the rise to solve production, storage and monitoring application challenges, aimed at curtailing waste and holding enough energy to power more infrastructure with green energy. To start, production of hydrogen in its current state is expensive because the element is difficult to handle and the equipment and processes available today are scarce or subpar. Many of the traditional production and storage methods also lead to excessive waste. One of the key reasons that storage has become such a challenge is due to the unique nature of hydrogen energy. Hydrogen is an incredibly light element in liquid form (a popular way of storing it in higher volumes). However, in liquid form it can be very volatile and hard to maintain due to temperature constraints. Therefore, storage and metering

requires extreme precision. In a compressed form, hydrogen takes up more space and needs to be carefully monitored for pressure related concerns. Due to the volatility of hydrogen, transportation has also become a barrier to the reliable transfer and use of the energy. The cost alone of transporting liquid or compressed hydrogen can become immense with the current lack of stable transportation and storage methods and the danger they can pose to the individuals shipping the substance.

Force measurement

The road to hydrogen becoming a real solution to meeting the renewable energy demand has been filled with hundreds of technological advancements. One of the lesser known, but extremely critical, solutions to making hydrogen a reality on a large scale is force measurement. Force sensors are capable of being used at every level of hydrogen advancement, from harnessing the power of hydrogen, to storing, monitoring and transporting it – and more use cases for hydrogen applications are being implemented frequently. When considering the challenges that have created barriers to harnessing the full power of hydrogen, force measurement can help to assist with, or solve, several of them – most notably, the production and storage of hydrogen. Today’s force measurement sensors have reached a level of precision that is ideal for measuring liquid hydrogen to be stored, as well as monitoring the pressure of stored hydrogen in its gaseous form. Force sensors are being used to measure the exact amount of liquid hydrogen being dispensed in a storage container by measuring incredibly small weights with extreme precision. Miscalculations of the weight can lead to waste via over/underfilling. For hydrogen in gas form, the same principles apply with force sensing, although instead of weight, pressure sensors can be used. There are also structural requirements for the actual containers storing hydrogen in any form. Force sensors are used in the research and development of many types of containers used for hydrogen storage to develop the optimal container dimensions, materials and more. From a transportation perspective, mitigating safety concerns and reducing waste are the critical challenges

that force measurement can help solve. With wireless, high-precision force measurement sensors, handlers can receive real-time updates on the pressure of the hydrogen in storage tanks. Another method of transportation is packaging hydrogen in a fuel cell, where force measurement sensors can be used as a metering device in the energy transfer. Transferring this energy into a fuel cell also allows for easier transportation. Included below is a list of the various hydrogen solutions that force measurement can enable: yy Compression: to prevent leaks or ruptures in hydrogen systems, force sensors are used to monitor and control the compression of hydrogen gas. yy Dispensing: to stop leaks, ensure a more efficient refuelling process, and create a secure connection between pump and vehicle, force sensors are integrated into hydrogen refuelling stations. yy Pipelines: during the construction and maintenance of hydrogen pipelines, force sensors are used to monitor forces on pipeline components such as valves and fittings. yy Tank inspections: force sensors are used to assess the structural integrity of the tank walls and detect any anomalies or signs of stress. In addition, automated monitoring can be installed using wireless sensors to improve efficiency by automatically notifying users when a tank needs to be repaired or inspected. yy Safety relief valves: to monitor safety relief valves in an effort to prevent safety hazards from over-pressurised conditions, force sensors are integrated into the valves to monitor pressure and the force required to activate the valve. There is also currently one excellent example of the promise of force measurement as it relates to an efficient production, storage, and monitoring process for hydrogen energy: electrolysis. Included below is an example of a real-world application of force measurement in electrolysis, which demonstrates the positive cost and time efficiency improvement that can be provided.

Electrolysis and electrolyser farms

Electrolysis uses electricity to split water into hydrogen and oxygen to store renewable energy more efficiently. This reaction takes place in an electrolyser. Electrolysers can range in size from small, appliance-size equipment that is well-suited for small-scale distributed hydrogen production, to large-scale, central production facilities that could be tied directly to renewable or other non-greenhouse-gas-emitting forms of electricity production. Over the past few decades, organisations have invested in these ‘electrolyser farms’ to harness and safely store more Figure 1. Diagram of a hydrogen electrolyser equipped with Interface’s load washers for fuel energy from various sources. cell tie rod monitoring. However, electrolysers are volatile

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and inefficient in their current construction without the use of force monitoring. The electrolyser is made by stacking multiple anode and cathode plates and a membrane between each, and these are held together by gigantic tie-rods that secure the unit. Over time, if the rods are not monitored, they can loosen and can leak a tremendous amount of energy production efficiency. It is recommended that the users inspect the electrolysers periodically to check for leaks or damage. To do this, 10 or more electrolysers in a line need to be taken down for inspection. This is not only an inefficient process, but it can also lead to tremendous waste as taking the electrolysers down for inspection or repair can cause energy to leak. Therefore, more engineering innovation has been necessary to improve the promise of electrolyser farms. This is where force sensing comes into the equation. To reduce the downtime of an electrolyser, load cells can be used to measure the tie rod in real time. To do this, load cells are secured to the tie rod and connected to a strain bridge transmitter. This allows the user to always monitor the tension of the tie rod. This creates an autonomous monitoring system, which will tell users exactly when repair or inspection is needed, rather than a manual monitoring system that may shut down a portion of electrolysers when it is not necessary. Not to mention, the cost of downtime in electrolysers over time is significant compared to the one-time cost of purchasing a force measurement system to alert the user when repair is needed more accurately.

Additionally, load cells can last an infinite amount of time with the proper calibration and electrolysers rarely ever cycle, which reduces the opportunity for damage to the load cell. This means that this is a solution that will last as long as it is needed. Figure 1 visualises the process for monitoring an electrolyser unit using load cells.

Conclusion

Now is the time to truly invest in the promise of hydrogen energy in order to meet demands for green energy. Electrolysers have been around for a while now – there was a big push in the 1990s for this technology. However, the right elements were not there politically, economically, or climate crisis wise. Now time is running out as global warming becomes an ever-looming threat, pushing governments to mandate green energy innovation and usage. With force sensing capabilities, production, storage and monitoring solutions can become more efficient, safer and cost effective. Force measurement can also be used throughout the hydrogen energy innovation process, from R&D and testing, to real time measuring and monitoring. This promise can already be seen in electrolyser farms, which have become a real solution to help store huge amounts of green energy, while significantly reducing waste. As more applications take advantage of force sensing, its role will continue to grow throughout the journey of hydrogen innovation.

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hile many alternative sources are emerging, the bulk of hydrogen production today uses methane in natural gas as feedstock. Reforming methane liberates the hydrogen, but turns the remaining carbon into carbon dioxide (CO2). This is often released to the atmosphere, increasing greenhouse gas (GHG) levels. Carbon capture and storage (CCS) techniques can be integrated into the hydrogen production process, avoiding release of most of the CO2, but it requires large amounts of energy. This creates an ‘energy penalty paradox’ because trying to control one emission source creates another. Solving this paradox requires developing more energy-efficient capture technologies, improving the performance of current capture methods, and using renewable sources to power capture systems.

The reality of hydrogen production today

Traditional ammonia manufacturing, oil refining, and even renewable diesel manufacturing applications have a voracious appetite for

hydrogen for use as a feedstock. Reforming remains the primary source, accounting for approximately 90% of all hydrogen production, and most of it is still considered ‘grey’ (Figure 1) due to atmospheric CO2 release. Some facilities are beginning to make a transition to ‘green’ hydrogen. These are typically located where renewable electricity is available in substantial amounts, such as near a large wind farm, but they are rare, primarily due to capacity constraints on electrolysis technology. The best approaches today recognise that production from natural gas is still irreplaceable, but its climate effects must be mitigated. There is a hopeful sign: the hydrogen production method in these situations can be changed from ‘grey’ to ‘blue’ without disrupting capacity. In the short-term, this development promises to reduce emissions far faster than all the other processes since it has the potential to affect the bulk of existing hydrogen production. Getting the maximum benefit calls for two things: first, making the reforming process more efficient so it does not require such heavy use of fossil

Figure 1. The hydrogen value chain is growing more complex with new sources and uses of the gas. Environmental effects are characterised by a colour assigned to each source category.

Both processes consume large amounts of natural gas as fuel, and techniques for improving efficiency are similar. The primary reformer is the largest single consumer of natural gas as a fuel, so controlling combustion in this part of the process has a direct effect on overall energy consumption.

Figure 2. The SMR process requires several stages to break down methane into hydrogen and remove all other components. fuels itself; and second, increasing the efficiency and capacity of CCS technology.

Improving reformer performance

A key challenge with hydrogen production via reforming is the energy intensity of the process itself. In a typical reforming unit, producing a ton of hydrogen requires at least another half-ton of natural gas used as a fuel, creating CO2 emissions. While this issue remains a conundrum, it stresses the importance of making the reformer unit as efficient as possible. There are two reforming approaches that dominate the industry today. The first is steam methane reforming (SMR), which has been in use for decades. An SMR unit comprises of the several sections (Figure 2) necessary to produce high-purity hydrogen from methane in natural gas. Since steam consumption can be very high per unit of hydrogen produced, reactor heating and boiler operation areas deserve initial examination, especially burner control. The second option is autothermal reforming (ATR), which produces syngas, a mix of hydrogen, carbon monoxide, and CO2 (Figure 3). These are then separated into individual streams. ATR interfaces well with CCS technologies and is valued for its cost effectiveness.

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Carbon capture basics

Gas coming out of either reformer process must pass through a step (Figure 4) to remove as close to 100% of the CO2 as possible to deliver pure hydrogen. In the most commonly used capture method, mixed gas flows through an absorption vessel filled with liquid solvent. Gas enters at the bottom and liquid from the top, and they flow counter-currently. The solvent chemically bonds to the CO2, allowing hydrogen to flow out of the top. CO2-rich solvent is then pumped to the desorption (stripper) vessel where it is subjected to abrupt temperature and pressure changes, causing CO2 to bubble out. The solvent recirculates through a heat exchanger and then back to the capture vessel where the process continues. This system depends on multiple heat exchangers and a reboiler that consumes steam, so it has its own energy consumption. Ultimately, the objective of blue hydrogen carbon capture plants is to deliver high-purity hydrogen while isolating as much concentrated CO2 as possible, while using the smallest amount of energy.

Critical tools for improving process efficiency

There are many tools available to reduce fuel consumption and emissions while optimising SMR, ATR, and CCS processes. Given budgetary realities in many facilities today, major capital improvements are often not feasible, but improvements to

process measurement and control strategies can drive positive changes at far lower costs.

Combustion management

Fuel consumption throughout the process is the largest factor affecting emissions and cost. Boilers for steam production, along with fired heaters, call for the same combustion control tactics, each built around fuel flow control and oxygen content of flue gas. Most installations depend on traditional volumetric flow meters to measure fuel, but a far more complete picture of combustion performance Figure 3. ATR uses a mix of oxygen with CO2 or steam in a reaction with methane to form is available by measuring natural syngas. The reaction takes place in a single chamber where methane is partially oxidised in gas flow using a mass flow meter an exothermic reaction. (Figure 5). A mass flow reading gives a much clearer indication of the energy content, rather than simply volume. Combustion efficiency is monitored using a sensor to evaluate flue gas oxygen content (Figure 6). The target is to have only the stoichiometric amount of air to match fuel flow, but in most situations it is necessary to have slightly more because air and fuel do not mix perfectly. However, too much air decreases efficiency and increases emissions. A 2% increase of oxygen in the stack can increase emissions between 25 - 30%. An effective combustion control system uses feedforward control based on fuel measurement and feedback control based on oxygen measurement to optimise fuel flow and air, delivering the maximum recoverable heat with minimum emissions.

Other critical flow measurements

In addition to fuel flow measurements, there are many points where flows of gases and liquids must be controlled to balance reactions and heat transfer. Emerson’s Micro Motion Coriolis mass flow meters can handle gases, as well as liquids, and their ability to measure mass rather than volume Figure 4. Carbon removal from mixed gas leaving the reforming stage makes it simpler to compensate for changing densities. must extract almost 100% of CO2. Achieving this depends on effective A prime example in the CCS unit is matching solvent flow temperature and pressure control. to gas flow. There must be enough solvent to capture the required volume of CO2, so many units run solvent flow high. This is costly in terms of emissions and fuel as the solvent must This is in contrast to many situations where finding optimum pass through multiple heat exchangers and a reboiler to support operating conditions is a trial-and-error process supported by the required stripper temperature. The process must maintain a declining population of experienced operators. Mathematical an optimal balance between the two flows to ensure maximum modelling and simulation techniques, using tools such as capture with minimum flow. The ability of a mass flow meter to AspenTech’s Aspen Plus® asset management software, can measure solvent density, in addition to flow, helps determine provide better information more quickly and reliably than when it is necessary to add fresh make-up solvent. depending on human skill. A model captures the interactions among different components, in all phases of the operation, including the reformer and CCS stages. For example, the model can simulate different operational As important as advanced instrumentation is for improving scenarios and parameters, making it possible to assess operations, all elements must be tied together in a complete different capture rates on energy consumption, all without automation strategy to realise the greatest benefits. With its the risk of real-world experimentation. Techniques such power to improve efficiency, reliability, and safety, automation as experimental design, sensitivity analysis, and numerical technology is playing a central role in moving toward optimisation.

Control strategy for optimisation

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By analysing historical data and patterns, control systems can help operators identify new opportunities for efficiency, develop better predictive models, and recommend operational adjustments, improving the economic viability of capture systems over the long-term.

Storing carbon

Once captured, CO2 is compressed and removed from the facility via pipeline or tanker truck. Ultimately it is pumped into the ground at a well, frequently a depleted oil or gas well. Here it is compressed again to 70 to 140 bar for injection. Compressors used for this purpose are normally multi-stage centrifugal designs that are subject to surge Figure 5. Flow meters can provide extensive information about natural conditions at low flow rates. If sufficient flow is not restored gas characteristics, making it easier to control fuel flow precisely. quickly, the compressor’s internal components can be severely damaged. An anti-surge valve provides the required recycle flow, protecting compressors and avoiding costly failures. During startup, the anti-surge valve provides throttling control to recycle a portion of the discharge flow as the compressor is brought up to capacity. To prevent surge, the compressor’s controller modulates the anti-surge valve for throttling control. This requires a fast, stable response to its open-loop step command. During the onset of a potential surge event, the valve must open quickly – in less than two seconds – to recycle the discharge gas back to the suction side of the compressor. During normal operation, the Figure 6. Effective combustion control requires operating as close to anti-surge valve will remain closed, but it could be opened the stoichiometric balance as possible. A zirconia sensor, used with an to catch a surge event, or due to changes in demand or oxygen analyser, provides continuous measurement of excess oxygen production optimisation. from any combustion process, including reformer furnaces and boilers. Subsurface engineers monitoring an injection site must use software to help integrate control systems with pressure, optimisation algorithms can be used to determine the optimal flow, and temperature instrumentation above and below ground. operating conditions, which typically vary depending on specific This information feeds systems to provide automated control applications, industrial processes, and geographical locations. of pumps, compressors, valves, and other critical equipment, Aspen Plus interfaces directly with the process automation calibrated specifically for the storage site’s unique parameters. In system so strategies created through simulations can be addition, specialised hardware, including cryogenic valves rated implemented for the actual process. Emerson’s DeltaV™ Virtual to withstand high temperature and pressure excursions, enable Studio platform can provide all required distributed control precise control of injection of liquified or supercritical CO2, system functions, while reducing IT infrastructure complexity. improving efficiency, while reducing leaks and safety incidents. DeltaV virtualisation solutions provide easy scalability, while Each well site is different, and injection pressures depend improving sustainability, efficiency, and overall performance. greatly upon the depth and type of geologic formation at the Because maintaining full availability for compressors, heat specific site. Valves controlling automated injection can be exchangers, fans, valves, pumps, and other strategic assets subjected to thousands of pounds of pressure, high vibration, depends on monitoring condition and performance, automation and high noise – as well as corrosive conditions created when can help engineers and technicians optimise reformer and CCS trace amounts of water or hydrogen sulfide remain in the CO2. processes, save energy, and improve the reliability of essential Valve body, trim, and seal material selection is a critical aspect of equipment. valve sizing and selection.

Extending carbon capture

A high-volume hydrogen production unit usually exists in a larger plant environment, such as a refinery or petrochemical plant. Consequently, a carbon capture system may cover other processes in addition to a hydrogen reformer. This could include other manufacturing processes and plant utilities. Advanced process control software can coordinate operation of the capture system with the rest of the facility, optimising energy usage and load distribution, providing better utilisation of resources, and maximising overall efficiency. Integrated control systems also leverage advanced machine learning algorithms to optimise capture performance.

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Pick your partner carefully

Partnering with a supplier that is able to provide a complete portfolio of automation solutions, together with extensive domain expertise, can help reduce project complexity, drive operational efficiency, and maximise plant safety and reliability. Automation technologies are designed to optimise reforming and carbon capture units by delivering advanced control, increased process visibility, and actionable information for improved decision-making, all of which are necessary to meet global net-zero goals and realise a sustainable economy for future generations.

ecarbonisation of industrial processes is crucial to global efforts to minimise the impact of climate change. Governments worldwide have set aggressive targets for achieving net zero greenhouse gas (GHG) emissions by 2050, and the industry must take action to meet these objectives. Key elements of this effort include reducing the demand for primary resources by increasing the circular economy, improving energy efficiency, using carbon-free fuels, reducing the uncontrolled release of hydrocarbons and other GHGs into the atmosphere, and electrifying the heat supply using renewable energy sources such as wind, solar or hydropower. When carbon dioxide (CO2) generation cannot be avoided, carbon capture, utilisation, and storage (CCUS) can be employed to reduce CO2 emissions. Many of these activities require gas measurements for optimising processes and ensuring safety, as well as monitoring emissions. Tunable diode laser absorption spectroscopy (TDLAS), with its fast response time, high reliability, selectivity, and sensitivity, is a powerful tool for

these applications. Thanks to its exceptional performance and flexibility, TDLAS is now widely used across many industries, from petrochemicals and chemicals, to power and steel, as a standard technology for numerous applications.1-4 Some of the most important examples include, but are not limited to, improving energy efficiency by optimising processes to reduce fuel consumption, safety monitoring of process inertisation, detecting methane leaks in natural gas pipelines, and monitoring pollutant emissions. Hydrogen has long been utilised in various industrial production processes, including the hydrogenation of petrochemicals, ammonia production, and semiconductor manufacturing. Recently, much hope has been put on hydrogen as a carbon-free energy source for the future, and the Ukraine crisis has accelerated efforts to switch from fossil fuels to renewable alternatives. With the advent of a new energy sector and new carbon-free manufacturing processes, many existing production processes will have to be adapted or new processes introduced. This means that there will also be

new tasks and challenges for gas instrumentation. With its flexibility, TDLAS will play a key role and contribute to the successful and safe decarbonisation of the industry.

TDLAS – gas sensing with lasers

Photonics-based technologies for measuring gas concentrations exploit the fact that every gas, be it oxygen, carbon monoxide or complex hydrocarbons, has a characteristic infrared (IR) absorption spectrum that can be considered as its unique fingerprint. In many cases, this allows accurate identification of gas components and quantification of their respective concentration values. Lasers are among the most important photonic devices, and they are used for numerous applications thanks to their unique properties. In the context of TDLAS, the key features include the ability to emit light with narrow bandwidth and the ability to collimate, direct and focus the laser beam. The first property makes highly selective measurements in complex gas mixtures possible, while the second is crucial for directing the laser beam over longer distances. The use of TDLAS enables real-time, contactless measurements of gas concentrations directly in the process, known as in-situ measurements. This has several advantages: yy Instrumentation is not exposed to the process gases. yy Complex and high-maintenance sampling systems are generally not required.

yy Real-time measurements greatly improve the efficiency of process control and safety monitoring. The most commonly used configuration for TDLAS instrumentation is cross-stack, meaning that the transmitter (laser) is mounted on one side and the receiver (detector) on the diametrically opposite side of a stack, pipe or duct (Figure 1). The transmitter is mounted on the left-hand side of the stack, and the receiver on the right-hand side. Although the ability to perform in-situ assessments is a key feature of TDLAS, there are situations where direct in-process measurement is not possible or preferable due to system design, varying infrastructure, installed base, etc. In cases of high gas pressures or very low concentrations, extraction may be required. Multi-pass cells (MPCs) provide a well-established method for increasing the optical path. Since a TDLAS analyser’s lower detection limit (LDL) is directly proportional to the distance that the laser beam travels through the gas sample, improving LDL can be achieved by folding the optical path using two mirrors. At high gas pressures, a simple extraction cell with a transmitter and receiver mounted on both sides can also be utilised. A third principle configuration of TDLAS systems is called open path. Open path sensors can cover optical path lengths of several hundreds of metres. They are typically used for the detection of diffuse or fugitive emissions.

TDLAS for hydrogen

Figure 1. Sketch of a partial cross-section of a typical in-situ TDLAS installation. The transmitter is mounted on the left-hand side of the stack, with the receiver on the right-hand side.

Figure 2. Simulated IR transmission spectrum of 1% hydrogen.

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As mentioned above, TDLAS is used today for many applications and gases. Nevertheless, there are some important gases that were considered impossible to measure with this technology, and hydrogen is probably the most prominent example. This perception was based on the misconception that hydrogen does not have an IR absorption spectrum. There are, however, absorption lines spread throughout the IR region (Figure 2). These lines are very weak, so a high-quality gas analyser is required in order to obtain results that are useful in an industrial operation. When taking safety applications as an example, hydrogen has a lower explosive limit (LEL) of 4%; end-users usually require alarm levels of 1% or even lower. For many applications, a fast response time (T90) is essential, and typically a T90 of 1 second is demanded by customers. Finally, the analyser shall not have any cross sensitivities with other gas components in the process or in the air to avoid false alarms. NEO Monitors developed the world’s first hydrogen TDLAS analyser

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for in-situ applications in 2017.5 The latest version – LaserGas™ III H2 – is designed for Zone 1 applications, with the laser beam allowed to penetrate a Zone 0 and meeting IEC 61508 functional safety requirements (SIL2). One of the key figures of a TDLAS analyser is worth a closer look. The lower detection limit (LDL) of a TDLAS analyser can be determined by mounting it on an absorption cell filled with ambient air, placing it in a climatic chamber, and measuring the noise level over approximately 20 hours.

To simulate real ambient conditions, the set temperature of the climatic chamber is changed in several steps, from room temperature to -20 °C, up to 55°C, and back to room temperature. In general, the temperature changes lead to a drift of the optical fringes that are caused by reflections from optical components, such as lenses and windows in the beam path between the laser and the detector. Since such a climatic chamber test covers the entire operating temperature range of the analyser, it can be considered a ‘worst case scenario’ and the actual LDL is lower in many cases due to smaller temperature variations. From Figure 3, a noise level of less than 0.05 %∙m (3σ) or 0.1 %∙m (peak-to-peak) at a response time of 1 second was derived; the latter corresponds to a sensitivity of less than 3∙10-6 (rel. abs.) when related to the absorption line strength reported in spectroscopic databases. These sensitivities are close to the theoretical limit of TDLAS analysers. The results show that the sensitivity is dominated by stochastic noise Figure 3. Noise measurement in a climatic chamber (T90 = 1s). Left y-axis: and only a few optical fringes are visible. measured hydrogen concentration (purple) and lower detection limit (blue). Faster response times are also possible, Right y-axis: climatic chamber temperature (green). but with a certain penalty on the sensitivity as the stochastic noise level will increase while the level of optical fringes will be maintained. In summary, hydrogen measurements using TDLAS also meet the fundamental requirements for successful use in many process control and safety applications.

Hydrogen in natural gas

Figure 4. Set vs measured hydrogen concentrations in various hydrocarbon backgrounds.

Figure 5. Recorded spectra of (1) 6.1 ppm CO (sample 20) and 6.1 ppm CH4 (sample 50) in hydrogen background, purple trace, and (2) pure hydrogen, green trace.

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Hydrogen is becoming increasingly used as a fuel for vehicles, trains, ships, aeroplanes, and many other applications. In addition, blending hydrogen with natural gas through existing pipeline networks is seen as a possible first step in decarbonising natural gas systems. Accurate metering is a critical task in supplying energy to end users; they want to determine the energy content they are receiving, and the supplier wants to bill accordingly. Gas chromatographs are commonly used to measure key indicators such as calorific value or Wobbe index. However, this expensive, slow, and complex technology does not meet the needs of most users. Hence, there is also a desire to use optical technology for this purpose. Figure 4 shows results of hydrogen measurements in various hydrocarbon gas mixtures. For this purpose, a LaserGas™ II analyser with MPC was used in combination with a gas mixer to generate different gas compositions under well-controlled conditions. For the first five measurement

points, 10% hydrogen was mixed with different ratios of methane (CH4), ethane (C2H6), propane (C3H8), and nitrogen (N2). The last measurement point represents a zero measurement of a hydrocarbon mix without hydrogen. The respective gas mixture is indicated on the x-axis and the measured hydrogen concentration on the y-axis. The results demonstrated that there were no cross-sensitivities, and deviations of 1 - 2% relative from the expected hydrogen value were observed. This shows that the setup is very well suited to measure hydrogen in hydrocarbons with the required degree of precision.

Hydrogen impurities

When using hydrogen, the quality or purity of the supply can be critical. Impurities in hydrogen can interfere with the proper functioning of equipment that stores, distributes, or uses hydrogen as fuel. When hydrogen is blended with natural gas and used in boilers, the tolerance for impurities is generally higher than when hydrogen is used in vehicles powered by polymer electrolyte membrane fuel cells. The presence of impurities in hydrogen depends on the production process used. Carbon monoxide (CO) and CH4 may be present in hydrogen from steam methane reforming (SMR), while oxygen (O2) is present from chlor-alkali or water electrolysis. TDLAS can also be used for these types of applications. For hydrogen generated from SMR processes, a combined impurity measurement of CO and CH4 with low ppm ranges is often desired. By carefully selecting an IR wavelength, these two components can be measured with a single laser. This is illustrated in Figure 5, which shows a combined

measurement of these two gases. In real installations, LDLs of 0.05 ppm for CO and 0.2 ppm for CH4 have been achieved.

Conclusion

In summary, the innovative TDLAS technology has become a valuable tool to push the limits of hydrogen measurement in various industrial applications. As the world strives to achieve ambitious decarbonisation goals and transition to a sustainable future, TDLAS will play a key role in optimising processes, ensuring safety, and monitoring emissions in both established and emerging industrial sectors. Despite initial misconceptions about the feasibility of measuring hydrogen with TDLAS, advances in the field have led to the development of specialised analysers that can accurately and rapidly measure hydrogen in industrial environments. TDLAS technology also offers the advantage that it can be transferred very easily to other applications, from CCUS, to ammonia as an energy carrier, and much more.

References

1. GEISER, P. and AVETISOV, V., ‘A smorgasbord of measurements’, Hydrocarbon Engineering, (May 2018), pp. 81 - 84. 2. GEISER, P. and AVETISOV, V., ‘Switching to in situ analysis’, Hydrocarbon Engineering, (October 2018), pp. 67 - 70. 3. GEISER, P., ‘New Opportunities in Mid-Infrared Emission Control’, Sensors, Vol. 15, pp. 22724 - 22736, https://doi.org/10.3390/ s150922724, (2015). 4. WESTBERG, J., AVETISOV, V. and GEISER, P., ‘Contactless Combustion Analysis’, Hydrocarbon Engineering, (October 2021), pp. 33 - 36. 5. AVETISOV, V., BJORØY, O., WANG, J., GEISER, P. and PAULSEN, K.G., ‘Hydrogen Sensor Based on Tunable Diode Laser Absorption Spectroscopy’, Sensors, Vol. 19, No. 5313. https://doi.org/10.3390/ s19235313, (2019).

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Frederic Thielland, David Janssens and Sebastian Fischer, Siemens, Germany, outline the benefits of using tunable diode laser spectroscopy (TDLS) in green hydrogen production plants.

s the world shifts towards sustainable energy solutions, green hydrogen has emerged as a promising contender in the quest for decarbonisation. Produced through electrolysis using renewable energy sources, green hydrogen holds immense potential to revolutionise multiple sectors, including transportation, energy storage, and industrial processes. However, reliable and efficient production of green hydrogen requires precise monitoring and control of the entire process. In this regard, gas analysers play a pivotal role, ensuring the quality, safety, and efficiency of hydrogen production in green hydrogen plants. This article explores the applications and significance of gas analysers in facilitating the transition to a greener and more sustainable future.

There are two major fields of application for online gas analysers in green hydrogen production plants, both of which will be discussed.

Monitoring the electrolysis process

Gas analysers prove indispensable in monitoring the electrolysis process. They help in analysing the composition and purity of the hydrogen and oxygen streams, ensuring optimal electrolysis reaction and supporting plant safety monitoring. These analysers continuously measure the levels of hydrogen, oxygen, and water vapour, providing real-time data to operators. By monitoring and controlling these parameters, the analysers assist in maintaining the desired efficiency, preventing system failures, and optimising energy consumption.

Controlling impurity levels

One of the critical aspects of green hydrogen production is maintaining high purity levels throughout the process. Gas analysers allow for the accurate measurement and detection of impurities in line with the ISO 14687:2019 (hydrogen fuel quality – product specification) and 19880-8 (hydrogen fuel quality control). In fuel cells, contaminants can temporarily or permanently disable sites for catalytic separation of hydrogen, impede proton transport, or dilute hydrogen fuel and reduce efficiency. Key components that require continuous monitoring online include trace oxygen and moisture in pure hydrogen. Nitrogen measurement can also be required as the gas can be used to inert the electrolyser in the shut-down phase, and can potentially remain present during the restart of the electrolyser.

Conventional (legacy) approach

The aforementioned gases are traditionally measured using extractive methods, which extract the gas from the process to carry out an adhoc sample preparation. When the sample is under conditions within the analyser specifications, the sampling line will convey this sample to the analyser measurement chamber, where the relevant technology is applied. For the percentage of oxygen, the most commonly used method is paramagnetic. It is carried out using the magnetic property of the di-oxygen molecule. There are devices which measure a differential pressure, ensuring the process gas is never in contact with the sensors, avoiding potential contamination. Other techniques include the dumbbell effect principle, which is more subject to vibrations, and electrochemical-based sensors

with a limited lifetime, which is subject to drift and interference. The percentage of hydrogen is traditionally measured with the accepted thermal conductivity principle. This measurement technology uses the difference in thermal conductivity of hydrogen with another specie (oxygen) in contact with a heated detector. The percentage of water, or moisture, is commonly measured using phosphorus pentoxide (P2O5) and platinum-based electrodes. When water flows through the electrodes, a current is detected and is directly proportional to the water concentration, according to Faraday’s law. There are noticeable benefits of all these measurement technologies. They have been on the market for decades and they are low cost, or low CAPEX. Nevertheless, several drawbacks remain and must be taken into consideration, especially when safety, production availability and yields are at stake. Firstly, the main hurdle is at the sampling and conditioning system level. This requires significant care and expertise. For instance, the sampling system must be checked regularly to avoid potential failure and a lot of consumables must be replaced. Additionally, most of these technologies are drifting over time and must often be calibrated using a certified gas cylinder. This requires the presence of a skilled operator to conduct the maintenance operation, with the opportunity to install an automatic calibration system to reduce the effort. However, these systems still require regular checks and cylinder change. From a measurement quality standpoint, most of these technologies are not selective enough, meaning there are many potential interferences, and various compensations, if possible, must be applied. The response time is mainly dependent on the sampling system lag time and is typically close to one minute. This generates a delay between the crossing of an alarm threshold in the process and the actual signal going to the counter action programmable logic controller (PLC) or distributed control system (DCS) loop. When it comes to safety, this long response time could be a major concern.

Tunable diode laser spectroscopy analysers Figure 1. In situ TDLS analyser.

Figure 2. Typical in situ configurations: in a gas pipe (top) or directly to a storage vessel (bottom).

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Another class of gas analysers is based on the measurement principle of tunable diode laser spectroscopy (TDLS): the analyser’s emitter unit sends a laser beam through the gas, which is detected by the receiver unit (Figure 1). The laser beam’s wavelength is selected so that the laser light can only be absorbed by the gas species of interest. The gas concentration is then determined by the strength of the light absorption signal. TDLS analysers are commonly used in many industries and are available for a large variety of gas species, including oxygen and, more recently, hydrogen. They can be installed in situ, i.e., directly attached to the electrolyser plant, without any intermediate gas sampling system. This simplifies the system design and allows a fast concentration measurement with response times in the range of 1 second.

Modern TDLS analysers are equipped with internal reference gas cells, apply modulation schemes on the laser beam, and compensate for effects due to process pressure and temperature. These measures enable continuous analyser-internal performance monitoring, minimise sensor drift, and ensure the long-term validity of the analyser calibration. Selectivity is one of the major features of TDLS. The use of an infrared mono-chromatic light source (tunable diode laser), means that there is almost no interference expected when using TDLS. In contrast to electrochemical sensors, TDLS analysers do not have depleting sub-components that require regular exchange and recalibration. The absence of maintenance-prone gas sampling systems in the in situ configuration further reduces maintenance efforts. To produce green hydrogen, the electrolyser will be located in remote areas (e.g., a desert with solar panel fields) and even offshore, close to the offshore wind mills. Any maintenance on a conventional analyser requires a skilled service engineer and involves difficulties concerning reaching the site quickly, and at an affordable cost. Remote maintenance could be a potential alternative, but it requires extensive set-up. Given the low or non-systematic preventive maintenance, the use of TDLS technology offers the advantage of lowering the maintenance to its minimum requirement, whilst also having a positive effect on OPEX. In addition, the quality (no interference) and high availability of the measurement of TDLS analysers are strong arguments for producing high-quality hydrogen, with a clear impact on the production plant yield, not to mention potential shut-down due to a defective conventional analyser. Therefore, the eventual higher investment costs of TDLS analysers can be quickly compensated with a short return on investment. To ensure safety in electrolysis process applications, the oxygen concentration must be monitored in the hydrogen outlet stream. The same applies to the hydrogen concentration in the oxygen outlet stream. Measurement ranges are typically in the 0 - 5% range with a detection limit below 0.2% (2000 ppm). The distance between the emitter and the receiver unit is called the optical path length (OPL) and needs to be adjusted according to the required detection limit. According to the Beer Lambert law, there is a counter proportionality between the OPL and the sensitivity. The longer the path length is, the better the sensitivity is. Suitable path length can be achieved by installing the TDLS analyser either on a hydrogen gas storage tank, or by integrating the analyser into one of the gas pipes immediately after the electrolysis with the eventual use of a by-pass (see Figure 2). The TDLS analyser can also be used for hydrogen purity measurement, which typically occurs after purification and compression. The measurement of the impurities (water and oxygen) is in ppm levels or less. The mechanical set up of the electrolyser shows small diameter pipes and high pressure (over several hundred bars). In situ

Figure 3. Gas analysers play a critical role in ensuring quality and safety in green hydrogen production plants.

Figure 4. Electrolyser principle. configurations are not sensitive enough and larger OPLs are required. In addition, high pressure over 100 bar widens the absorption spectra and does not facilitate proper in situ measurement. For such applications, an extractive TDLS analyser with an internal multi-pass cell is a suitable alternative, and offers the same advantages as using the TDLS technology. The internal multi-pass cell creates a long OPL of tens of metres, required for low ppm measurement, and the pressure is reduced in the sample conditioning system. This solution is perfectly suited for measuring impurities in hydrogen. Trace nitrogen measurement is typically carried out using online gas chromatograph – which has the best detection limit – or by using a thermal conductivity gas analyser that will fulfill the threshold requirement of 300 ppm.

Conclusion

In conclusion, the efficient and safe operation of green hydrogen plants necessitates precise monitoring and control of various gas parameters. Gas analysers act as indispensable tools, offering real-time measurements and analysis to optimise the entire hydrogen production process. They enable the monitoring of electrolysis and control impurity levels. Total cost of ownership is becoming highly important in bringing down the cost of hydrogen. TDLS technology offers very low maintenance costs and utilities consumption with a high measurement quality and availability to increase yields and minimise potential shutdown of electrolyser plants.

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A. Kigel and A. Shats, Modcon Systems, UK, reveal how advances in in-situ analysis are resulting in precise oxygen monitoring in hydrogen production.

ydrogen is a highly volatile and explosive gas that is significantly lighter than air, with a molecular weight of 2.01. It has an extremely low ignition energy threshold, one-tenth of the energy ignition threshold of gasoline-air mixtures. This property, in combination with its broad flammability range of 4 - 74% by volume concentration in air and 4 - 94% in oxygen at atmospheric pressures, and its explosion limits of 18.3 - 59% by volume, makes hydrogen very susceptible to leakage. Consequently, explosion safety is a crucial consideration in the design of hydrogen containing systems. A high oxygen level in hydrogen piping can pose a significant risk of an explosion or fire. Moreover, in chemical reactions and processes, a high oxygen content can also result in side reactions which reduce the efficiency of the process and also cause unwanted reactions, resulting in product contamination, reducing its quality, or forcing additional purification

procedures. Therefore, accurate and reliable measurement of the oxygen content in high-pressure hydrogen piping is essential for increased process efficiency, product quality, and safety. To mitigate the hazards associated with hydrogen production, systems must be carefully designed. Dedicated equipment rated for both non-hazardous and hazardous locations is typically used in hydrogen gas production systems. However, in an attempt to lower installation costs, general-purpose equipment may be utilised. The risk of gas leaks must be minimised. However, sampling gas from high-pressure pipelines for chemical analysis increases the potential for leaks, and can pose a challenge when performing oxygen analysis. Traditionally, measuring the oxygen content in high-pressure hydrogen piping involves extracting a sample and reduction of the pressure of the sample for analysis. However, this method

has several drawbacks, including complexity and inaccuracies caused by sample conditioning and handling. As a result, many companies are turning to the in-situ installation of oxygen analysers inside high-pressure hydrogen piping, which offers real-time measurement, reduced complexity, and improved accuracy. Installation of an oxygen analyser directly into high-pressure hydrogen piping allows operators to continuously monitor the oxygen content in real-time, without the need for sample extraction or a pressure reducing sampling system. This method is not only faster and more efficient, but also much safer. It eliminates the risk of exposure of hydrogen to atmospheric oxygen and subsequently reduces the need for hazardous area classification.

Principles of in-situ oxygen analysis

In-situ analysis involves the measurement of oxygen concentration directly at the process location of interest. Several measuring techniques exist for in-situ oxygen analysis: yy Paramagnetic analysis: this method uses the magnetic properties of oxygen to attract oxygen molecules to a paramagnetic material. The oxygen concentration is determined by comparing the influence of the magnetic field in an oxygen containing sample. yy Zirconia analysis: zirconia sensors utilise the ionic conductivity of zirconium dioxide. At high temperatures, zirconia exhibits different electrical conductivities as a result of the oxygen concentration at the sensor, enabling accurate measurement. yy Electrochemical analysis: electrochemical sensors employ the principle of oxygen reduction in an electrogalvanic cell electrode to determine oxygen concentration. They are widely used due to their simplicity, low cost, and accuracy. yy Optical analysis: this technique utilises optical principles to measure the concentration of oxygen directly in the process, without the need for physically extracting a sample or altering its properties. This method relies on the influence of oxygen on the absorption/transmission of light at a certain wavelength. One commonly used optical method for in-situ determination of the oxygen concentration is based on the principle of fluorescence quenching. It exploits the fact that oxygen molecules quench the fluorescence emitted by certain fluorescent dyes. The intensity of the fluorescence emitted by the dye is inversely proportional to the concentration of oxygen. A probe is inserted at the spot

where oxygen concentration needs to be measured. Light of a specific wavelength is directed onto the probe, exciting the dye molecules and causing them to emit fluorescence. The intensity of emitted fluorescence is measured by a photodetector, and converted into an electrical signal, which is proportional to the oxygen concentration. A relationship can be established between the fluorescence intensity and oxygen concentration. This allows the measurement of oxygen concentration in an unknown sample based on the fluorescence intensity detected. One advantage of the optical methods for in-situ oxygen analysis is their non-invasive and non-destructive nature. They do not require physical contact with the sample or sample extraction, making them suitable for continuous monitoring in various applications, such as industrial processes, environmental monitoring, and medical diagnostics.

Key advantages of optical methods Wide measurement range Optical methods have a wider measurement range compared to paramagnetic analysis. Zirconia-based sensors are typically more suited for measuring oxygen concentrations at the higher range (above a few percent). Electrochemical sensors may have limitations in measuring very low or very high oxygen concentrations. Optical methods can accurately measure oxygen concentrations from low to high levels, making them suitable for a broad variety of different applications.

Fast response time Electrochemical sensors often have a slower response, which is caused by the velocity of the chemical reactions involved in the measurement. Optical methods provide rapid measurements, often with response times in the milliseconds range. This enables real time monitoring and rapid detection of oxygen fluctuations. This is critical in applications where timely data is crucial.

High accuracy and precision Optical techniques offer high accuracy and precision in oxygen measurement. They are capable of providing reliable and repeatable results, ensuring confidence in the data that is obtained.

Low maintenance Electrochemical sensors often require periodic replacement of electrolytes or membranes, which can be time-consuming and costly. Optical sensors used in oxygen analysis typically require minimal maintenance as compared to paramagnetic analysers. They are often more robust and more resistant to environmental factors, which reduces the need for frequent calibration or sensor replacements.

Versatility Figure 1. Schematic drawing of measuring principle of oxygen by fluorescence.

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Optical methods can be used in various environments and sample types. They can be applied in gases, liquids, and even solids. This versatility allows for broader applications across industries such as healthcare, environmental monitoring, and industrial processes.

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Reduced interference Optical methods are less prone to interference from other gases or contaminants compared to paramagnetic analysis. This enhances the accuracy and reliability of oxygen measurements, even in complex or challenging sample matrices.

Figure 2. Oxygen measurement compensation.

Figure 3. Low detection limit of the MOD-1040 analyser at ambient conditions.

Pressure dependance and low detection limit

The pressure dependence on optical measurement of oxygen refers to how the measured optical properties of oxygen can vary with changes in pressure. In optical measurements, various techniques are used to determine the concentration or partial pressure of oxygen based on its interaction with light. One common optical technique for oxygen measurement is based on the phenomenon of luminescence quenching. Oxygen molecules can interact with certain luminescent materials, such as phosphors or dyes, causing a decrease in their luminescence intensity. The extent of this quenching is directly related to the oxygen concentration. In terms of pressure dependence, the luminescent quenching method can be affected by changes in pressure due to the following reasons: yy Collisional quenching: at higher pressures, there is an increased probability that oxygen molecules will collide with the luminescent material. These collisions can lead to more efficient quenching of the luminescence, resulting in a stronger pressure dependence of the measured signal. The relationship between pressure and quenching efficiency is typically described by the Stern-Volmer equation. yy Partial pressure changes: as the total pressure increases, the partial pressure of oxygen also increases proportionally. This can affect the oxygen measurement, particularly if the measurement technique is sensitive to the partial pressure rather than the concentration. It is important to ensure that the measurement setup accounts for changes in the gas composition and pressure accurately. To mitigate the pressure dependence in optical measurements of oxygen, several approaches can be employed: yy Compensation algorithms: by taking into consideration the known pressure dependence of the measurement technique, by means of compensation algorithms to the measured signal can be corrected to suppress pressure fluctuations. These algorithms typically involve additional sensors to monitor and account for pressure variations. yy Pressure regulation: maintaining a constant pressure during the measurement can help reduce the impact of pressure changes. This can be achieved using pressure regulators or controlled gas flow systems.

Enhancing safety and efficiency in hydrogen facilities

Figure 4. High pressure, in-situ analysis: sensing element of an optical analyser based on photoluminescence technology.

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Hydrogen requires stringent safety conditions to prevent leaks or accidents. To ensure the safety of personnel and equipment, it is crucial to keep hydrogen facilities and piping fully isolated. Complete isolation minimises the risk of hydrogen escaping into the environment, where it can pose a significant hazard. The classification of an area as hazardous is an essential consideration in the design and operation of hydrogen plants. When multiple sample extraction points are present, there is an increased risk of gas leakage, which necessitates the classification of the area as Zone 2 of medium risk for the presence of potentially explosive gas. In the case of sample

extraction methods, where samples are vented to the atmosphere, the locations where the extraction occurs are often classified as Zone 1 areas where flammable gases may be present in normal operating conditions. This classification requires the implementation of stringent safety measures, including the use of certified equipment and controls designed for hazardous environments. By reclassifying the area as general purpose, the plant can benefit from the use of standard, non-hazardous area equipment, which is often more readily available and less expensive compared to specialised hazardous area-certified solutions. This provides greater flexibility in equipment selection and reduces the overall project cost. Furthermore, reclassifying the area as general purpose simplifies the design and construction of the hydrogen plant facility. It eliminates the need for complicated hazardous area wiring, instrumentation, and explosion-proof enclosures, streamlining the installation process and reducing associated costs. The simplified design also facilitates future modifications or expansions, allowing for more agile and cost-effective operations. Ensuring safety, efficiency, and quality assurance is vital in the context of hydrogen production and distribution. By keeping hydrogen facilities and piping fully isolated and employing in-situ analysers suitable for high-pressure installations, these objectives can be effectively achieved. In-situ analysers offer numerous benefits, including enhanced safety, improved efficiency, cost savings, and accurate data.

Embracing this advanced technology is a significant step towards optimising hydrogen operations and paving the way for a sustainable and reliable hydrogen economy.

Conclusion

The optical oxygen analyser offers a high level of accuracy in oxygen measurement, making it ideal for applications where precise monitoring under harsh environments is critical. Moreover, the oxygen analyser demonstrates excellent suitability for harsh environment operations. In environments with extreme temperatures, corrosive gases, or particulate matter, traditional measurement methods may face challenges or limitations. In contrast, the optical method, being non-intrusive, remains unaffected by these harsh conditions and offers robust and stable performance over time. The oxygen analyser also excels in selectivity, distinguishing oxygen from other gases without significant cross-sensitivity. This characteristic ensures accurate oxygen measurements in complex gas mixtures or environments with multiple gases present. To conclude, the oxygen analyser stands out as a highly accurate and suitable option for high-pressure and harsh environment operations. Its non-intrusive nature, fast response time, wide dynamic range, selectivity, stability, and lower maintenance requirements make it a preferred choice in various industrial applications, including hydrogen production, where precise control of oxygen levels is essential.

s growing numbers of industries embrace the use of hydrogen, it is important that the hazards of working with this fuel are understood, and the right safety measures and systems are put in place. While hydrogen is safer to handle than some other commonly used fuels (in that it disperses quickly in air and is not toxic), it is still highly combustible and is an asphyxiant gas. Its unique properties also pose special challenges, which is why, in addition to general fuel safety regulations, there are specific regulatory requirements for those working with hydrogen.

Considerations to make when working with hydrogen Hydrogen’s chemical properties pose unique challenges, specifically: � The gas is not visible to the eye and is odourless, making it undetectable by human senses. � Hydrogen is lighter than air. It is commonly understood that in confined areas it will rise upwards to ceiling level, displacing oxygen, making it difficult to detect in spaces where accumulations cannot occur. However, pressurised

Andrzej Janowski, MSA Safety, examines workplace safety risks and challenges posed when producing, handling, transporting and storing hydrogen. hydrogen gas leaks can be hard to detect as the gas jet direction can be unpredictable, making detector positioning difficult. � When mixed with air, hydrogen is highly combustible. However, a pure hydrogen flame is very pale and almost invisible in daylight and fails to register with traditional heat detectors. Fire, explosion, and asphyxiation are the main safety considerations associated with handling hydrogen, especially

considering its wide flammability range of 4% to 77% of volume in air. The main areas of risk can be categorised as shown below: � Propensity to leak: small molecular size and permeation properties, extremely high diffusivity. � Propensity to ignite: very low ignition energy, fast detonation and wide flammability range. � Fire consequences: invisible flame with low thermal radiation and high flame temperature. � Human related: colourless, odourless and tasteless gas which can cause potential injury or loss of life.

Standards, strategies and solutions for sites handling hydrogen

The need for layered fire and gas protection

Both standards also specify requirements for risk mitigation with a gas detection system as one of the methods to prevent accumulation of ignitable gas mixtures.

Ultrasonic detection of hydrogen leaks

Explosion protection is currently governed internationally by the IEC 60079 and IEC 80079 standards, with many regions adopting almost identical standards locally. Additionally, specific standards for hydrogen facilities are also available, for example: yy ISO 22734 – hydrogen generators using water electrolysis – industrial, commercial, and residential applications: manufacturers of electrolysers are required to perform a risk assessment. However, depending on the final placement location of the equipment, plant owners/operators may need to perform their own additional assessment on the hydrogen generator, applying zone classification using IEC 60079-10-1 or an appropriate national standard. yy ISO 19880 – gaseous hydrogen – fuelling stations: sites must be inspected in accordance with the IEC 60079-10-1 standard or sufficient national regulations. This includes zone classification and ignition protection methods to IEC 60079 and IEC 80079.

Hydrogen’s minimum ignition energy in air at atmospheric pressure is approximately 0.02 mJ. In the case of a hydrogen gas leak, especially in a confined space, a static electric discharge from a worker’s clothing or equipment could result in an explosion or fire. Coupled with the physical properties highlighted earlier, a robust and layered strategy for fire and gas detection is required, supported by plume modelling and gas mapping to demonstrate the effectiveness of a hydrogen detection system. Key challenges for any site handling or storing hydrogen, such as an electrolytic hydrogen production plant or hydrogen fuelling station, include detecting leaks outside, where the gas cannot accumulate, and installing detectors appropriately within different risk zones. To detect any loss of hydrogen containment therefore requires the application of several distinct, yet complementary, technologies spanning across ultrasonic leak detection, conventional gas detection, and flame detection.

When pressurised hydrogen gas leaks, it generates an ultrasonic sound at the exit point. Ultrasonic monitors detect airborne ultrasound produced by turbulent flow above a predefined sound pressure level. Depending upon the level of background ultrasound, a single detector can respond to even a small hydrogen leak some distance from the source. Since ultrasonic detection does not rely on a presence or concentration of hydrogen gas, and is unaffected by wind or plume direction, it is ideal for monitoring pressurised pipes and vessels (e.g. well-ventilated, open areas of storage facilities ranging from large production sites to smaller fuelling stations). Instruments can alarm rapidly as the time it takes for ultrasonic noise to travel from the leak source to the detector is typically measured in milliseconds.

Low and combustible hydrogen levels: point gas detection Figure 1. MSA point gas detector ULTIMA® X5000.

Figure 2. MSA Safety ULTIMA-X5000.

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Point gas detectors for hydrogen use either catalytic or electrochemical sensors. In catalytic gas detection, gas enters the sensor through a sintered disc (flash-back arrestor), comes into contact with pellistors (beads) and is oxidised. A sensor uses a Wheatstone Bridge which converts the resulting change in resistance into a corresponding sensor signal, proportional to the amount of gas present. Results are read either locally via a display on the device or remotely at a control unit located in a safe area. The operational range of these sensors is in the range of 0 - 100% lower explosive level (LEL). Electrochemical sensors use an electrochemical reaction to generate a current proportional to the gas concentration. The sensor is a chamber containing a gel or electrolyte and electrodes. The gas sample enters the casing through a membrane; oxidation occurs at the working electrode and reduction takes place at the counter electrode, resulting in flowing ions which create a current. Measurement of this current is converted into a displayed gas reading. The operational range of electrochemical cells for the detection of hydrogen is more sensitive than catalytic sensors – typically 0 - 1000 ppm. This makes electrochemical gas

detectors well-suited to areas where hydrogen gas would be contained within an enclosure e.g., within a compressor housing where the very earliest detection of a release with small gas concentrations is usually required or sought.

Hydrogen flame detection

In the event of a fire resulting from an undetected gas leak due to, for example, incorrect gas detector placement, selection, or sensor failure, hydrogen-specific flame detectors provide a warning to deploy fire suppression and other safety actions. Detectors simultaneously monitor infrared (IR) and ultraviolet (UV) radiation at different wavelengths. When hydrogen burns, radiation is emitted in the infrared spectrum by hot water molecules or steam created by combustion. An algorithm that processes IR radiation modulation reduces false signals caused by hot objects and solar reflection. The UV detector is typically a photo discharge tube that detects deep UV radiation. The key benefit of using current UV and IR sensors within a single instrument is the only alarm source shared between the two sensing technologies is a real fire. Due to absorption by the atmosphere, solar radiation at certain wavelengths does not reach the earth’s surface, eliminating alarms from solar radiation when appropriate range is monitored. This combination of IR and UV detection improves speed of response and false alarm immunity, while producing detectors that can detect even small hydrogen fires.

Detectors: zones, placement and fire and gas mapping

Correct placement and utilisation of multiple detector technologies increases the likelihood of identifying hydrogen gas dispersal or fire early. Suggested locations may include but are not limited to: yy Areas where leaks are possible, and gas can accumulate. yy Connections that are frequently separated (i.e., hydrogen refuelling connections). yy Building air intake and exhaust ducts drawing possible leaks into or outside the building. Ultrasonic detectors ‘listening’ for leaks can be placed wherever background noise or large structures will not impede detection of the ultrasonic sound. Presently, hydrogen detection schemes are mainly based on point gas detectors, either with catalytic-bead or electrochemical-cell type sensors. Users should be aware that the likelihood of hydrogen gas detection by point gas detectors can be quite poor for applications in unconfined areas. This is as hydrogen gas in processes or storage is usually under elevated pressures, and the direction of the leaked hydrogen plume is not necessarily upwards. When under pressure, hydrogen gas leaks are likely to be in the form of gas jets. The shape of these jets is typically long but narrow in width, and the momentum of release can maintain this shape for a considerable time. This increases the likelihood of the gas jet bypassing point gas detectors for a lengthy period. And, since it is difficult to know where a leak would occur, the direction of such gas jets is typically random. This further increases the likelihood of delayed detection or, in the worst case, the likelihood of no detection. Positioning point gas

detectors for rapid hydrogen gas detection in unconfined areas is difficult. Consequently, the likelihood of hydrogen gas detection can be much lower than realised. Plume modelling and gas mapping software tools can be used to demonstrate the limitations of point gas detectors in hydrogen gas applications. They can also help bring new detection techniques into urgent consideration, such as ultrasonic gas leak detection for more effective hydrogen gas risk mitigation.

Worker protection: portable gas monitors

Workers may need to access areas of a site where sensors are not installed. In an enclosed space, the risk of a potential hydrogen leak causing worker asphyxiation is generally outweighed by the danger of combustion caused by static from clothing, footwear, or equipment causing an explosion or fire. Therefore, the focus is on personal atmospheric monitoring using portable gas detectors.

Choosing a vendor for hydrogen detection and safety

As previously mentioned, hydrogen gas detection and monitoring can pose several unique challenges. Organisations engaged in or entering the hydrogen supply chain should seek guidance from a safety partner with a proven track record backed by sector-specific insight and expertise. As an experienced supplier of gas and flame detection equipment, MSA Safety has pioneered the detection of combustible gases such as methane and propane. With an in-house R&D team, MSA develops, tests, and manufactures its own fully certified portfolio of products and safety solutions, including hydrogen gas and flame detection technologies.

Best practice fire and gas mapping

In summary, hydrogen gas presents exciting commercial and sustainability opportunities – and several new and distinctive challenges across the production and distribution chain. Design, installation, and planning of a layered gas and flame detection system for process industry facilities usually begins with choosing correct instrumentation for the specific potential hazards, as well as determining sensor detection range, mounting, and positioning, field of view, knowledge of lines of sight, and blind spots. Quantifying flame and gas risks to correctly position fixed gas and flame detectors for the highest detection coverage benefits from careful analysis and a systematic approach. Plume modelling and gas mapping can provide valuable insights into the effectiveness of an applied hydrogen detection scheme. Through its fire and gas mapping solution, MSA offers a technical assessment of a facility coupled with mapping software to provide metrics calculation based on the technical report’s findings. The software informs optimal sensor placement and determines the location and scope of gaps in coverage targets. Coverage calculations provide a quantitative measure of gas detection needs that complement conventional methods. A mapping report includes graphical maps of residual risks, recommended detector placements, and numerical estimates of detection coverage. The approach used is based on recommendations outlined in ISA’s TR84.00.07 technical report.

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Dinesh Pattabiraman and Manish Verma, TMEIC Corp. Americas, USA, address the impact that power supply can have on the cost and efficiency of electrolytic hydrogen production.

ne of the biggest challenges with the hydrogen economy is replacing fossil-derived hydrogen with clean hydrogen, a product that has zero impact on the environment. Among the various pathways to produce clean hydrogen, electrolysis is a powerful catalyst for achieving a low-to-no-carbon hydrogen supply. The prevailing idea is that by harnessing excess renewable electricity and transforming it into hydrogen, we have the potential to decarbonise stalwart industries like steel, refining, and fertilizers, and unlock new use applications for hydrogen; replacing traditional energy sources with a clean one. While electrolysers receive much attention as a crucial component in electrolysis, the technology selection for the power supply unit is equally vital. This power supply unit (PSU) is critical in converting alternating current (AC) power to direct current (DC) power, ensuring optimal performance. Its significance lies in its impact on the project’s overall capital cost and operating expenses, which has a material effect on the levelised cost of hydrogen (LCOH). This article will outline the importance of the PSU, as well as factors which drive the cost of the PSU, and finally, what types of PSU technologies are available, along with crucial advantages and disadvantages. Ultimately, understanding the PSU and its nuances will help the cost, performance, and scalability of electrolytic hydrogen as one of the most cost-effective vectors for energy transition paths for hydrogen.

Regulatory background

The US government has sent a clear signal to develop the nascent hydrogen industry by passing two pieces of legislation: � The Infrastructure and Investment Jobs Act (IIJA) of 2021 pledges US$8 billion in funding to de-risk and develop promising hydrogen hubs nationwide, regardless of the hydrogen production technology used. The overarching goal is to demonstrate that for every 1 kg of hydrogen produced, no more than 2 kg of carbon dioxide equivalent (CO2e) are emitted on-site. � The Inflation Reduction Act (IRA) of 2022, under Section 26 USC 45V of the tax code, provides a production tax credit (PTC) based on the lifecycle carbon emissions, on a well-to-gate basis, for every kilogram of hydrogen. Table 1 summarises the amount of PTC.

In perspective, current methods of producing hydrogen through the conventional steam methane reforming (SMR) process emit around 8 - 12 kg of CO2e / kg of hydrogen. Therefore, to qualify for the statutory allowable maximum tax credit of US$3/kg of hydrogen, the carbon intensity should be between 0 – 0.45 kg of CO2e / kg of hydrogen. These two pieces of legislation are helping with investment decisions in the hydrogen industry and will accelerate the development of related technologies.

Producing electrolytic hydrogen

Over the past year, hydrogen’s role in the energy transition has been widely discussed. Regarding electrolytic hydrogen, the talk has been exclusively focused on the electrolyser itself, focusing on novel materials. There is indeed lots to talk about when it comes to novel materials, coatings, costs, and overall project economics. However, the discussion has not detailed the upstream DC power supply unit, the PSU. This is understandable, as most professionals in this industry are chemical or electrochemical engineers. DC power supplies are viewed as a mature technology relative to electrolysers. However, this is not so. Megawatt (MW) scale DC supplies

can vary significantly in cost and performance depending on the technology and topology. A wholistic approach is therefore required to safely, cost-effectively and reliably deploy electrolytic hydrogen. Figure 1 shows the typical cost structure of an electrolyser system and the component disaggregation for the balance of plant services. The PSU constitutes approximately one-third of the total cost of the electrolyser system, and it should not be overlooked. Figure 2 provides an illustration of a typical electrolysis process. Three major factors affect the cost structure of the PSU: yy Step-down transformer. yy Grid-side and electrolyser-side performance requirements of the rectifier. yy Electrolyser DC current rating.

The step-down transformer reduces the voltage level available from the utility service (typically 34.5 kV) to a voltage level used by the rectifier itself. In power electronics, the basic building blocks of a circuit form what is known as a topology. The power conversion topology determines the grid-side and load-side (electrolyser) performance. The DC current rating determines the size and number of PSUs necessary to satisfy the current rating at the electrolyser’s beginning and end of Table 1. 45V tax credit structure for hydrogen life. production It is critical to note that rectifiers are primarily sized and PTC value Life cycle emissions priced based on their DC current rating rather than the power (US$/kg of hydrogen) (kg of CO2e/kg of hydrogen) rating, which is a product of voltage and current. A higher 4 – 2.5 0.60 current requires more semiconductor devices, more copper 2.5 – 1.5 0.75 and more thermal cooling, which drives up cost. Rectifier cost 1.5 – 0.45 1.00 strongly, positively, and directly correlates with the current they have to deliver. While there is some correlation of cost 0.45 – 0 3.00 with operating voltage due to the choice of semiconductor devices, the impact is much stronger with current. Transformer cost is also affected by the stack current rating, since the low voltage winding would require more copper to deliver a higher current, therefore increasing its cost. Figure 3 shows how DC amps vary as a function of DC volts for a 20 MW, 10 MW and 5 MW electrolyser stack Figure 1. Cost structure of typical electrolyser system and balance of plant (BOP) size. Holding DC volts constant, the component disaggregation.¹ electrolyser watts directly determine the amps that are required from the rectifier. In addition, as the electrolyser stack voltage is increased, the DC amps are lower in order to hold the stack power constant. This can be leveraged in the electrolyser design to reduce the PSU cost, by lowering the current (amps) that a particular stack requires. A rectifier that needs to deliver 25 MW at 500 V is a quite different rectifier (in terms of size, cost, and configuration) than one that needs to deliver 25 MW at 1500 V. The number of amps necessary is reduced by Figure 2. Electrical illustration of an electrolyser. almost 66%.

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Major topologies available for PSUs

Historically, thyristor devices such as the silicon-controlled rectifier (SCR) have been used for AC to DC power conversion. Power-intensive processes such as chlor-alkali, electrowinning, and aluminium smelting use these devices. SCRs continue to serve the industry with their robustness and low cost. However, they have application considerations that need to be accounted for in project design. The advent of fast switching transistor devices known as insulated gate bipolar junction transistors (IGBTs), and continuous improvements in their performance, have led to their widespread adoption in many applications such as electric motor adjustable speed drives, traction systems and, more recently, in solar and energy storage inverters. Due to the economies of scale and the nature of their voltage and current characteristics, IGBT-based rectifiers present a unique value proposition for their applicability in electrolytic hydrogen production. These characteristics are summarised in Figure 4. Two crucial application considerations are highlighted here: harmonics and power factor. AC to DC power conversion inherently introduces non-linearities, generating electrical harmonics on the grid. This can be likened to ‘electrical pollution’ in simple terms and utility standards necessitate these harmonic levels to be within acceptable limits. In the case of thyristor-based technology, additional harmonic filters are required at the electrical substation. These passive filters introduce extra costs, occupy physical space, have power losses, and control flexibility comes at a high cost. These filters are hard to design to accommodate the variable electrolyser load which may fluctuate based on available renewable power. Additionally, thyristor-based

rectifiers exhibit a low power factor load to the utility, as the line-side power factor is dependent on the electrolyser load. Many utilities worldwide are imposing mandates on their customers, requiring a minimum power factor of 0.95 or even higher. Failure to meet this requirement may result in penalties. Transistor-based rectification technology such as IGBTs mitigate these two issues, providing greater certainty in electrical performance. Furthermore, due to their widespread adoption in the renewables industry, these systems have become cost-effective in terms of manufacturing and installation. By transitioning to transistor-based rectifiers, the harmonic pollution and power factor challenges can be significantly reduced or eliminated. This alternative technology offers improved electrical performance, cost-effectiveness, and operational flexibility, making it an attractive choice for electrolysis systems seeking optimal efficiency and compliance with utility requirements.

Comparing IGBT-based power conversion topologies

IGBT-based conversion topologies can utilise a single stage or a multi-stage conversion with each topology possessing its own application considerations. A single-stage AC-DC power conversion is typically achieved through a 3-phase converter, which is widely applied in solar photovoltaic inverters, energy storage inverters, etc. This topology offers acceptable harmonic pollution and allows for active control of reactive power, which eliminates the need for any additional harmonic filter or power factor compensation equipment in the plant. The operating principle of this topology is a voltage boost

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which delivers a higher DC voltage than the AC voltage and therefore necessitates a minimum DC voltage for operation based on a fixed AC voltage. Since the minimum stack voltage is affected by the beginning of life operation at the lowest possible current, the AC voltage must be lowered to match this voltage. A lower AC voltage increases the current capability required and would drive up the cost. In addition, the minimum DC voltage required can complicate pre-charging requirements for the electrolyser. A two-stage conversion utilises a front-end to rectify the AC voltage to DC as well as a separate DC-DC stage to match the electrolyser demand and overcome the minimum DC voltage requirement. The front-end can be diode-based in order to reduce cost and increase conversion efficiency. Even though active reactive power control is not possible, the topology can deliver at least 0.95 power factor. Harmonic pollution

can be lowered to acceptable levels by using a multi-pulse, phase-shift transformer. Using an active front-end instead helps achieve unity power factor and compliance with harmonic limits without using phase-shifted transformers. The active front-end and DC-DC stages can be coordinated to achieve good overall efficiency. Further, the active front-end can boost the DC voltage above the nominal voltage produced by a diode rectifier, which enables operation at higher DC voltages. Overall, the topology offers a broad control range from 0 V – rated DC voltage, which increases its flexibility to match the electrolyser performance.

Conclusion

Hydrogen is poised to revolutionise decarbonisation efforts across major sectors of the economy, and electrolytic hydrogen production stands out as a promising method. While improving electrolyser stack performance and reducing costs remain critical, disregarding the significance of the DC power supply would be a costly mistake. The current flow through the system directly impacts rectifier costs, making it an essential factor to consider. One effective approach to minimise current is by increasing stack voltage. While the average stack voltage hovers around 700 V, the industry is witnessing a trend toward stack voltages in the 1000 - 1500 V range. Standardising the volts and amps within the electrolyser industry would unlock economies of scale and lead to cost reduction, mirroring the success achieved in the solar industry in the last Figure 3. DC current (amps) as a function of DC volts (V) for 20 MW, 10 MW and 5 MW decade. Regarding CAPEX in hydrogen electrolyser stack. production facilities, the rectifier’s cost, performance, and scalability play a crucial role. Conversely, OPEX is driven by safety, efficiency, and reliability considerations. In the short-term, aligning stack volts and amps with the PSU capability proves to be the most effective means of reducing CAPEX. However, eventually, the OPEX truly matters. The industry must actively engage with both balance of plant (BOP) scope suppliers and, more importantly, DC power supply unit manufacturers at the preliminary stages of design. Collaboration between these stakeholders will enable mutual support and pave the way for widespread adoption of hydrogen, driving the industry toward a cleaner and more sustainable future.

Reference Figure 4. Summary of major rectification topologies for electrolytic hydrogen.

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1. ‘Harnessing green Hydrogen in India,’ adapted for IRENA report 2020, https://www.niti.gov.in/sites/default/ files/2022-06/Harnessing_Green_ Hydrogen_V21_DIGITAL_29062022.pdf.

Nora Han, ABB System Drives, Switzerland, outlines the importance of efficient power supply in green hydrogen production.

oday, over 99.6% of hydrogen processing involves petroleum and natural gas. This is unsustainable and does not make net zero goals any more achievable. As the hydrogen industry shifts to focus on producing green hydrogen, there is one major obstacle to overcome: the cost. Assuming that water is relatively affordable, electricity is an electrolysis facility’s greatest OPEX. In an average green hydrogen plant, electricity accounts for approximately 80% of OPEX. Therefore, improving the energy

efficiency of a facility is the best way to lower the unit cost of green hydrogen. Fortunately, technological advances in power supplies mean that greater efficiency is now possible. These developments, in combination with other economic factors, will earn green hydrogen its place as the fuel of the future.

A clear way to improve energy efficiency A green hydrogen processing system involves many components, and

each introduces the possibility for inefficiency. There are losses in the electrolysers, protection equipment, cooling systems, auxiliary equipment, and every other component. Upgrading these to more energy-efficient versions – without compromising their performance – produces a more productive system. The greatest potential efficiency improvements come from the power supply. A power supply system converts alternating current (AC) from the grid into direct current (DC) used by the electrolyser. The right choice of power supply can achieve system efficiency of over 98%. Power supplies typically account for up to 30% of the cost of an electrolysis system. Fortunately, savings are possible. As an International Renewable Energy Agency (IRENA) report states, the use of “standard utility scale power supply systems” for green hydrogen production “can significantly reduce cost and increase the performance of the power supply for electrolysers.”1

What does a power supply do?

Today, green hydrogen is produced using alkaline, proton exchange membrane (PEM), and solid oxide electrolyser cell (SOEC) systems. Each has advantages and disadvantages and places different demands on the power supply. However, all three approaches are low-voltage (LV) DC systems. This means that electricity must be stepped down from the grid’s medium-voltage (MV) AC to LV DC before it can be used. Here, there are a variety of approaches. One option is to use transformers to reduce the voltage and then rectifiers to convert it to DC. Alternatively, the current can be changed first and then the voltage can be adjusted using a DC-DC converter. This approach achieves greater performance. If a facility already has a supply of DC power, no current conversion is necessary, and a DC-DC converter can simply lower the voltage to the required level.

Choosing a power supply

Figure 1. A hybrid solution combines both thyristor and IGBT building blocks.

There is no single ‘best’ power supply – operators must select a solution that suits the facility’s requirements. However, there are some general points to consider. First, the energy supplied for green hydrogen must come from renewable sources such as wind and solar. Renewable energy sources can be intermittent and dynamic, so power supplies must be able to respond rapidly to input and output signals. Designs with specialised power electronics are suitable for use with uninterruptible power supplies (UPS), maximising plant uptime. Whichever approach operators select, they should consider investing in a modular solution. This ensures that scaling up production in the future – which is a likely outcome as demand for green hydrogen grows – is as straightforward as possible. Finally, operators must understand that the industry has yet to settle upon standards, so every system will be unique. To ensure that the system is cost-effective and performs as efficiently as possible, they must work with expert partners. As IRENA states: “optimisation can be achieved by careful system integration of different components in the electrolyser facility, optimising the entire facility rather than individual components.”

Optimising power factor

Figure 2. A hybrid solution minimises electrical system life cycle costs.

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A significant contributor to a system’s efficiency is the power factor (PF). This metric measures the ratio of apparent power, supplied by the network, to active power, the power used to perform work. An ideal PF is unity, meaning that the system uses all of the electricity provided. However, this is rarely achieved in reality. A more realistic target is a PF of 0.95. However, facilities often have a PF far below this. This means that the network contains a significant amount of reactive power – power that

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flows back to the grid without doing any work, wasting system capacity. Some grid operators impose significant penalties for excess reactive power. Power factor correction equipment, such as capacitors, STATCOMs and synchronous condensers, can increase a facility’s PF. The right choice of equipment also ensures that a facility can achieve a near-unity PF, another reason why it is essential to consult with experts during the design phase.

Reducing harmonics

Harmonic distortion is another significant contributor to a system’s efficiency. Harmonic distortion, or ‘electrical pollution’, is noise introduced to the electrical network resulting from equipment drawing power. If the noise occurs at a multiple of the fundamental frequency, it produces a harmonic wave, and this can cause several issues for a hydrogen production facility. Harmonic content on the network results in voltage distortion, which reduces the system’s energy efficiency. Losses from harmonics can be significant – a percent total harmonic distortion in the current (THDi), a level that many industrial facilities experience, results in a 16% increase in energy losses. In addition to lowering the system’s energy efficiency, harmonics also increase total energy consumption and can damage equipment. Harmonics often cause overheating of components such as transformers, motors and cables. This could be a safety hazard when dealing with hydrogen. Minimising harmonics must therefore be a priority for facilities. To limit the impact of harmonics, many facilities over-specify electrical components. However, this approach increases CAPEX and further lowers efficiency.

Overcoming challenges from harmonics

Several technologies are available to address harmonics. Operators can specify multi-pulse technology to cancel out harmonics using phase shift, which typically lowers THDi to between 6 and 10%. Another option is to use a choke and capacitors to passively filter harmonics to a THDi of under 10%. Alternatively, facilities can apply active filtering to generate the same harmonic in the opposite phase, cancelling it out and reducing THDi to less than 5%. These solutions are constructed from the building blocks of diodes, thyristors, and insulated-gate bipolar transistors (IGBTs). Diodes let current move in one direction and thyristors act as diodes which can be turned on and off. IGBTs are more complex, and therefore more expensive, but they are controllable, bidirectional and can be used to ensure the whole converter counteracts harmonics. Solutions built using different combinations of these technologies and approaches have unique strengths and weaknesses. For example, a 6-pulse thyristor rectifier is an affordable, simple solution, but it may introduce harmonic content on the grid side. A 12-pulse model counters harmonics more effectively, but requires a more advanced transformer, and is more costly and bulky.

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Two- and three-level active rectifiers are effective at reducing harmonic content but are less energy efficient than other solutions and experience higher current stress. Two-stage power supplies – such as a 12-pulse diode rectifier paired with an interleaved DC/DC converter – are also less efficient.

The benefits of hybrid solutions

As a general rule, more expensive options achieve lower THDi. Fortunately, by combining these technologies, operators can benefit from the best of each at a price that strikes a balance between CAPEX and OPEX. A hybrid solution that combines IGBT and thyristor technology, for example, achieves outstanding performance while eliminating the need for compensation equipment like capacitor banks and active filters. The advantages of a hybrid approach become even clearer as the system scales up. According to an internal study, a hybrid solution is the most affordable way to power a 200 MW system while achieving a power factor over 0.97 and harmonic content and DC ripple of lower than 5%. This solution achieves overall efficiency of over 98%. This hybrid design is cheaper than an equivalent thyristor or IGBT system, meaning that it requires lower CAPEX. It also uses less power, providing lower OPEX. Experts can conduct a simulation to estimate the potential savings from installing a hybrid system. Modern power supply systems also offer advantages in terms of reliability, maintenance, and safety. This helps hydrogen facilities to maximise uptime. Manufacturers with expertise in hazardous environments, such as ABB, design equipment with safety as a priority. For example, equipment may have a minimised number of components, use materials with a high comparative tracking index (CTI), and come with a suitable ingress protection (IP) rating.

Efficiency drives affordability

Green hydrogen is essential to reaching net zero and decarbonising the economy, but it must come down in price. Efficiency is essential to this, as it is the top OPEX for facilities. To improve energy efficiency, facilities can invest in power supplies and other equipment that maximises power factor and minimises harmonics. In addition to energy efficiency, other factors will contribute to lowering the price of green hydrogen. The IRENA report finds that, as designers gain real-world experience with large-scale green hydrogen production, they will be able to lengthen electrolyser lifetimes from 10 to 20 years. Economies of scale, meanwhile, are forecast to reduce the cost of new electrolysers by as much as 80%. The technological steps that will lead to the market success of green hydrogen are clear – now it is up to operators to take them.

Reference 1. ‘Green hydrogen cost reduction: scaling up electrolysers to meet the 1.5˚C climate goal’, IRENA, (2020).

n response to greenhouse gas (GHG) reduction targets instituted by international regulators, the maritime industry has shown increased interest in the use of LNG, methanol, ethane, LPG, hydrogen, ammonia and other gases and low-flashpoint fuels, including e-fuels. Of the alternative fuels being considered in the clean energy transition, hydrogen is one of the potential zero-emission fuel sources due to its ability to be produced from renewable and sustainable sources and its lack of carbon emissions in use. In recent years, industry has recognised hydrogen’s potential to generate electricity through fuel cells and combustion technologies. In a hydrogen fuel cell consuming a pure hydrogen fuel supply, GHGs are not emitted, while in combustion engines or gas turbines, hydrogen can be used to significantly reduce GHG emissions.

Challenges and opportunities

While hydrogen appears to be an ideal fuel for power generation, it carries various challenges including storage

requirements and fire hazard mitigation. To become a competitive alternative marine fuel, hydrogen also faces the challenges of availability and high costs to scale production and transportation infrastructure. Its low density causes any hydrogen to dissipate relatively quickly when released in an open environment; hydrogen in the atmosphere cannot be contained by earth’s gravity and eventually escapes into space. Hydrogen leaks are considered non-toxic, although the wide flammability range and potential for combustion can raise concerns regarding hydrogen safety and risk management. Hydrogen has the potential to be a zero-carbon marine fuel when it is consumed in a fuel cell or a mono-fuel internal combustion engine. When consumed in a dual fuel combustion engine, hydrogen can significantly reduce carbon emissions. Hydrogen is characterised by having a very low tank-to-wake (TTW) emissions impact, which considers the emissions produced by an energy source. However, the lifecycle of hydrogen production must be considered

to evaluate the overall emissions of GHGs from hydrogen. Well-to-tank (WTT) emissions consider all pollutants generated during fuel production, storage and transportation to the end consumer. These can include the emissions generated when coal or natural gas is processed to generate hydrogen, or the fossil fuels combusted to generate grid electricity used to generate hydrogen through electrolysis. To fully eliminate hydrogen emissions prior to fuel delivery, it is critical to focus on carbon-free production, storage and transportation methods. Hydrogen can be produced in renewable or ‘green’ forms that can eliminate upstream carbon and GHG emissions and result in very low WTT emissions. When both WTT and TTW emissions are eliminated from the fuel life cycle, a zero-carbon well-to-wake (WTW) fuel option is created. Sustainability verification schemes or guarantees of origin certificates such as the EU CertifHy project can be used, which may be implemented in the hydrogen market to track and quantify the emissions footprint of generated hydrogen. Such schemes may be implemented regionally or nationally but are not yet mandated by the International Maritime Organization (IMO).

Potential as a marine fuel

Compared to other marine fuels, hydrogen is characterised by having the highest energy content per mass of all chemical fuels at 120.2 MJ/kg, as shown in Table 1. In terms of mass energy, it exceeds MGO by 2.8 times, and alcohols by five to six times. Therefore, hydrogen fuel can increase the effective efficiency of an engine and help reduce specific fuel consumption. However, due to its lower volumetric energy density, liquid hydrogen may require four times more space than MGO, or about two times more space than LNG for an equivalent amount of carried energy. Also important to consider when comparing fuel energy and required volumes are the energy efficiencies of the consumer, or electrical energy losses in fuel cells.

Additional volumes of fuel may be required to account for efficiency losses between the tank to the output shaft power. Hydrogen requires low temperatures below -253°C (-423.4°F) to liquefy. Due to this very low temperature, the required volume to store liquid hydrogen could be even greater when considering the necessary layers of materials or vacuum insulation for cryogenic storage and other structural arrangements Hydrogen can also be stored within other materials, such as metal hydrides. This storage method binds hydrogen to metal alloys in porous and loose form by applying moderate pressure and heat. Subsequently, hydrogen is extracted by removing the pressure and heat. While technologically feasible and safe, metal hydride and other hydrogen storage methods within solid materials may not be a weight-effective solution for hydrogen storage on board ships. Due to the challenges related to low temperature or high-pressure storage, hydrogen can alternatively be carried within other substances such as ammonia or methanol. These fuels may require less energy than that needed to refrigerate liquefied hydrogen or to compress gaseous hydrogen. Some fuel cells can consume ammonia, methanol or other hydrogen carrier fuels by reforming and extracting hydrogen from the fuel using internal reformers. However, these technologies may require higher energy input to hydrogenate and reform the fuel and therefore may result in less efficient electrical production than pure hydrogen containment and consumption in fuel cells. Figure 1 shows how ammonia as an energy carrier can play a role in the life cycle of hydrogen fuel, leading to either consumption in a fuel cell or combustion engine.

Regulatory backdrop

Although hydrogen has yet to be adopted as a fuel in the maritime industry beyond a few pilot projects, it has already been implemented in land-based uses. Some of the information, rules and regulations from land-based resources are referenced in MSC.420(97). These include safety

Table 1. Properties of hydrogen compared to other marine fuels

Hydrogen MGO Boiling point (˚C)

-253

Heavy fuel oil

Methane Ethane

Propane Butane

Dimethylether (DME)

Methanol

Ethanol

Ammonia

180 - 360 180 - 360 -161

-89

-43

-1

-25

-33

Density (kg/m³) 70.8

900

991

430

570

500

600

670

790

696

Lower heating value (MJ/kg)

120.2

42.7

40.2

47.8

46.3

45.7

28.7

19.9

26.8

22.5

Auto ignition temperature (˚C)

585

250

537

515

470

365

350

450

420

630

Flashpoint (˚C) -

> 60

-188

-135

-104

-60

-41

132

Energy density liquid (H2 gas at 700 bar) MJ/L

8.51 (4.8)

38.4

39.8

20.6

27.2

23.2

27.4

19.2

15.7

21.2

15.7

Compared volume to MGO (H2 gas at 700 bar)

4.51 (7.98)

1.00

0.96

1.86

1.41

1.66

1.40

2.00

2.45

1.81

2.45

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measures, methods of transportation and standard hydrogen production procedures. Various referenced codes and regulations exist for hydrogen component standards and equipment design, fire codes and other hydrogen-specific safety codes, and general safety codes or standards that include hydrogen. The IMO has initiated the ‘MSC CCC 8-W.3 Draft Interim Guidelines for the Safety of Ships using Hydrogen as Fuel’, which is yet to be finalised. This document focuses on systems and arrangements provided for the use of hydrogen for propulsion and auxiliary systems. In addition, the MSC.1/Circ. Figure 1. ABS diagram showing how ammonia as an energy carrier can play a role in 1647 for IMO’s ‘Interim Guidelines the life cycle of hydrogen fuel, leading to either consumption in a fuel cell or combustion for the Safety of Ships Using Fuel engine. Cell Power Installations’ was also published for promoting the use of hydrogen-based fuel cells. The International Organization for Standardization (ISO), ‘Technical Report ISO/TR 15916 Basic Considerations for the Safety of Hydrogen Systems’ focuses on providing technical information that forms the basis of understanding hydrogen safety issues. The report addresses the recent interest in using hydrogen as a fuel and aims to address the unique hydrogen-related safety properties and phenomena and best engineering practices to minimise risks and hazards from hydrogen. The future possible development and adoption of IMO Figure 2. Rendering of the ABS-classed, Glosten-designed regulations for hydrogen as marine fuel and fuel cell guidelines hydrogen-fuelled research vessel for the University of California may help accelerate adoption and spur development of San Diego’s Scripps Institution of Oceanography (image the associated infrastructure for hydrogen generation and courtesy of Glosten). distribution.

Supporting adoption

ABS is working with organisations to support the safe development and use of hydrogen as a marine fuel. Current projects include the ABS-classed, Glosten-designed hydrogen-fuelled research vessel for the University of California San Diego’s Scripps Institution of Oceanography. Designed by Glosten, the vessel will feature a new hydrogen-hybrid propulsion system that integrates hydrogen fuel cells alongside a conventional diesel-electric power plant, enabling zero-emission operations. The design is scaled so that the ship will be able to operate 75% of its missions entirely using hydrogen. For longer missions, extra power will be provided by diesel generators. The 150 ft vessel will be equipped with advanced instruments and sensing systems, along with laboratories, enabling multidisciplinary research and advancing understanding of the physical and biological processes active in California’s coastal oceans. ABS has also supported vessels such as Veer Voyage, a wind-powered containership with auxiliary fuel cell propulsion that utilises green hydrogen as fuel, by leveraging the risk assessment defined in the new ‘ABS Requirements for Hydrogen Fuelled Vessels’.

ABS recognises the potential that hydrogen also shows in supporting a sustainable, lower carbon future. Safe and efficient storage and transportation of hydrogen at sea will be critical to the development and viability of the global hydrogen value chain. To this end, ABS has presented Provaris Energy with an approval in principle (AIP) for its gaseous hydrogen floating storage concept. The solution, dubbed H2Leo, has a design capacity range of 300 to 600 t of hydrogen, expandable to up to 2000 t. The unit is designed for various hydrogen supply chains and applications, including bunkering for the maritime sector, intermittent/buffer storage for green hydrogen production, and long-duration storage for excess renewable energy. The AIP is the latest example of ABS assessing novel approaches that support the development of the hydrogen value chain. Provaris’ H2Neo design for a compressed hydrogen carrier marks an industry first for a bulk hydrogen gas carrier. The development of H2Leo will run parallel to the remaining engineering and approvals for the H2Neo carrier, targeting prototype testing and final class approval later this year, with the unit available for construction in 2025.

Winter 2023

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Hydrogen innovation reaches high point with record patent filings for production

EC launches first European Hydrogen Bank auction

TÜV SÜD introduces new standard for low-carbon hydrogen

ADNOC opens high-speed green hydrogen refuelling pilot station

nnovation in hydrogen production technologies has reached a record high, according to the latest patent data reported by Appleyard Lees. The intellectual property firm’s third annual edition of the ‘Inside Green Innovation: Progress Report’, reveals that patent filings for innovations related to hydrogen production reached 555 in 2021 (the latest reported data) – an increase of 224 (almost 68%) since the previous 15-year peak in 2018. In geographic terms, Japan leads innovation in this area, followed by South Korea, the US, Europe and China. Patent applications for green hydrogen innovations have seen an unprecedented rise in the five years to 2021, reflecting the need for energy suppliers to produce more green hydrogen to support the transition to net zero by 2050. Innovation trends in this energy area suggest that the technologies aimed at both production and storage of hydrogen are each advancing at pace. Companies including Mitsubishi, Air Liquide, Toyota and Tokyo Gas, are among the top global patent filers in hydrogen production.

ÜV SÜD has developed the TÜV SÜD CMS 77 standard for the certification of low-carbon hydrogen or blue hydrogen and their derivatives (currently ammonia). The new standard will be continuously adapted to current and future developments and legal and normative requirements. The standard is applicable to all companies seeking to demonstrate their compliance with criteria set in the regulatory frameworks of various countries and regions, and to show their commitment to a sustainable energy supply. The standard sets a maximum threshold for greenhouse gas (GHG) emissions reduction potential allowed in the production process for hydrogen and its derivatives to be considered as ‘low-carbon products’. According to the standard, the GHG reduction of low-carbon hydrogen and low-carbon ammonia must be at least 70% compared to the global benchmark of 94 gCO2eq/MJLHV. This corresponds to a GHG value of not more than 28.2 gCO2eq/MJLHV. The standard additionally requires the construction and use of facilities for carbon capture and geological storage with robust proof of permanency of geological storage.

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Winter 2023

he European Commission (EC) has launched the first auction under the European Hydrogen Bank to support the production of renewable hydrogen in Europe, with an initial €800 million of emissions trading revenues, channelled through the Innovation Fund. Producers of renewable hydrogen can bid for support in the form of a fixed premium per kg of hydrogen produced. The premium is intended to bridge the gap between the price of production and the price consumers are currently willing to pay, in a market where non-renewable hydrogen is still cheaper to produce. The Hydrogen Bank complements other policy tools to build a market for renewable hydrogen, stimulate investments in the production capacity, and bring production to scale. Under the pilot auction, producers of renewable hydrogen, as defined in the Renewable Energy Directive and its Delegated Acts, can submit bids for EU support for a certain volume of hydrogen production. The bids should be based on a proposed price premium per kg of renewable hydrogen produced, up to a ceiling of €4.5/kg.

DNOC has announced that it has opened ‘H2GO’, the region’s first high-speed green hydrogen pilot refuelling station, to test a fleet of zero-emission hydrogen-powered vehicles. The station, which is located on land provided by Masdar City and operated by ADNOC Distribution, will create green hydrogen from water using an electrolyser powered by clean grid electricity. Musabbeh Al Kaabi, ADNOC Executive Director, Low Carbon Solutions and International Growth, said: “We are pleased to launch this unique high-speed green hydrogen refuelling station which supports the UAE’s National Hydrogen Strategy. ADNOC continues to collaborate with local and international companies on innovative technologies and low-carbon solutions that can accelerate decarbonisation and support a responsible energy transition.” The hydrogen supplied at the pilot station will be certified as ‘green’ from solar sources by the International REC Standard, an internationally recognised certification organisation.

UK government agrees £2 billion funding for green hydrogen projects

he UK government has announced £2 billion in funding to support green hydrogen projects over the next 15 years. Energy Security Secretary Claire Coutinho has announced backing for 11 major projects, and confirmed suppliers will receive a guaranteed price from the government for the clean energy they supply. This represents the largest number of commercial scale green hydrogen production projects announced at once anywhere in Europe. In return for this government support, the successful projects will invest over £400 million in the next three years, generating more than 700 jobs in local communities across the UK and delivering 125 MW of new hydrogen for businesses. The funding represents the most significant step in scaling up the UK’s hydrogen economy to date – speeding up progress towards the government’s ambition to deploy up to 10 GW low-carbon production capacity by 2030.

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