Global Hydrogen Review Summer 2023

Summer 2023

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04

Moving the needle

Jamie Maule, Cornwall Insight, UK, provides an overview of hydrogen development across Europe.

10

Building a strategy

Conrad Purcell and Shu Shu Wong, Haynes and Boone LLP, discuss hydrogen’s role in energy security and the decarbonisation of the UK’s energy sector.

15

Hydrogen: a springboard for the energy transition

Nuno Antunes, Association of International Energy Negotiators (AIEN), talks about the challenges of creating a green and low-carbon hydrogen economy, and how the AIEN member network is attempting to take steps to support this.

17

Continuing the green journey

Jon Constable and Stephen Peng, Protium, speak about their experience of using electrolyser technology in green hydrogen projects as end-to-end project developers, outlining the pitfalls and lessons learned.

21

Decentralised hydrogen – the key to decarbonising transport and logistics?

Richard Yu, IMI Critical Engineering, explains why decentralisation is key to the energy transition, and how applied knowledge of flow control systems is helping to accelerate the hydrogen economy in key industries such as transport and logistics.

24 Boosting electrolysis efficiency

Michael Immel, Holzapfel Group, Germany, explores how plating solutions can help to improve the efficiency of electrolysis in hydrogen production.

28 Mitigating risk

Cory Marcon, Endress+Hauser, USA, discusses how hydrogen permeation can pose risks to plants, and how this can be managed with the right instrumentation.

32 Creating confidence in hydrogen measurement

Mahdi Sadri, TÜV SÜD National Engineering Laboratory, UK, considers a range of measurement challenges for the hydrogen economy, and how these can be overcome.

36 Developed infrastructure for widespread distribution

For the hydrogen economy to grow, decisive action on investment and infrastructure is needed. Manish Patel, Air Products, explains.

40 Meeting new demands

Louis Mann and Daniel Patrick, Atlas Copco Gas & Process, USA, and Mazdak Shokrian, Plug Power, USA, discuss how turboexpander cooling technology can support hydrogen liquefaction expansion.

46 Going far beyond

Marion Erdelen-Peppler, ROSEN Group, Germany, considers the issues surrounding the use of hydrogen in exisiting pipelines, and explains why ROSEN has decided to build a hydrogen test laboratory.

50 Preparing for the maritime transition

Dr. Gunnar Stiesch, MAN Energy Solutions, Germany, assesses the key role that hydrogen will have to play in the maritime energy transition.

55 Pipe dream?

Sundus Cordelia Ramli, Topsoe, Denmark, explains why green hydrogen could help to decarbonise the steel sector.

This month's front cover

Building a low-carbon future together! The unique combination of Chart and Howden’s expertise and technology provides a range of solutions to support your energy transition, through the provision of hydrogen and LNG as clean burning fuel alternatives for power and transportation; and decarbonisation through the companies’ carbon capture processes.

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“ I’m told that people listen to celebrities more than experts, which is ridiculous. But if that’s the case, I want to tell you something…”

That’s Cara Delevingne, the British model and actress, talking to us via her TikTok channel. And what does she want to tell us? “Hmmm. Industrial emissions,” she whispers, while spraying her face with a new beauty product. “That’s what this face mist from Vattenfall is made with.”

Ms Delevingne then clarifies – in both this TikTok video and an accompanying glitzy advertising campaign for Swedish multinational power company, Vattenfall – that her new face mist is made with “emissions from fossil-free hydrogen; a fuel that emits water instead of carbon dioxide (CO2).” She goes on to explain, in layman terms, the process behind green hydrogen production, and why it has the potential to do much more than produce emissions so clean that they could be sprayed on your face. Green hydrogen has the potential to revolutionise how we power entire industries.

In a separate press release, Vattenfall explains that the face mist in question is made from actual wastewater from the HYBRIT factory, a pilot plant that the company owns together with Swedish steel manufacturer, SSAB, and mining company, LKAB, that uses fossil-free hydrogen in the value chain to produce fossil-free steel.

At first glance, it is easy to dismiss this advertising campaign as a spoof. Cara Delevingne certainly seems to be in on the joke, knowingly poking fun at her roots in the high-fashion industry (she is seen strutting around a mock energy plant in a slinky dress before jumping into a pool of industrial wastewater). And that’s because the campaign is a spoof. Of sorts. A spoof with a serious message. “We’re not getting into the beauty industry”, Vattenfall reassures us. You can’t buy a bottle of this face mist. “It’s a 50 ml bottle of systemic change.”

The message behind the campaign is that green hydrogen has the potential to decarbonise entire industries, and thereby reduce carbon emissions significantly. Ultimately, it can help to bring us closer to fossil-free living within one generation. And if people really do listen to celebrities more than experts, then this campaign is an ingenious way of spreading the word to a wider audience. “I think the tongue-in-cheek way that we’ve tried to make people aware of the subject is really smart”, Delevingne told Harper’s Bazaar. “People approach conversations about the environment and climate change with a lot of fear, and there are so many people who just won’t engage for that reason.”1

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Green hydrogen is, of course, a key theme throughout this issue of Global Hydrogen Review. And while we may not have an A-list celebrity onboard to tell you more, we do have a range of articles from experts in the field on topics including green hydrogen project development, PEM electrolysis, how plating solutions can improve the efficiency of electrolysis, and the role of green hydrogen in decarbonising the steel sector. This issue also covers a range of other interesting themes, including infrastructure development, pipeline transportation, hydrogen’s role in the maritime energy transition, and much more.

1. STRUNCK, C., ‘“Being a model was taxing on my value system”: Cara Delevingne on eco-activism and fast fashion’, Harper’s Bazaar, (10 May 2023).

Callum O'Reilly Senior Editor

Jamie Maule, Cornwall Insight, UK, provides an overview of hydrogen development across Europe.

As net zero targets loom closer, there is an ever-increasing need to accelerate decarbonisation efforts across Europe, and move away from dependence on fossil fuels. In the midst of the energy crisis, brought on by Russia’s invasion of Ukraine, this need has become more apparent – as has the necessity to further protect energy security.

Low-carbon hydrogen is an effective means of combining these two objectives. Not only can hydrogen – if created electrolytically or with the use of carbon capture, utilisation and storage (CCUS) technologies – act as a replacement for gas in many industrial processes, it can do so while contributing little to no carbon emissions. With such credentials, it is perhaps unsurprising that, increasingly, hydrogen is being pursued as a decarbonisation solution across Europe and the world at large.

Differing approaches

Owing to its nascency, wide range of production methods, and debate surrounding its most cost- and time-effective applications, there is no singular consensus on how hydrogen should contribute towards net zero. However, it is understood to be part of the solution. Recent policy developments at both the supranational (EU) and national level have, while allowing for differences, fostered some greater alignment across Europe, as focus is increasingly being placed on the development of renewable hydrogen. This becomes clear when looking at recent developments within the EU and the UK.

Close to consensus

At an EU level, the Hydrogen Strategy for a climate-neutral Europe, as well as the REPower EU Plan, outline common objectives for member states in their collective net zero transition. If implemented correctly, this should facilitate the production (10 million t) and import (10 million t) of 20 million t of renewable hydrogen within the EU by 2030.

In order to reach this ambitious target, 2020’s Hydrogen Strategy previously outlined two phases of hydrogen development that have since been expanded with the introduction of the REPower EU Plan in May 2022. While the initial phase one targets aimed for 6 GW of electrolysers by 2024, Russia’s invasion of Ukraine has accelerated the need for hydrogen across Europe (see Figure 1), with the EU now aiming to deploy 17.5 GW of electrolysers through the ‘Hydrogen Accelerator’ programme by 2025. While targets have changed, the fundamentals of EU-wide hydrogen development remain largely the same, as production will primarily be sited around demand centres, with transport and storage still in the planning stages until the latter half of the decade. During the second phase, hydrogen transportation will expand through the development of a pan-European grid, allowing for intercontinental and international trade. To meet growing demand, electrolyser capacity will scale up to 40 GW by 2030 – with an additional 40 GW across eastern and southern neighbourhood countries – while hydrogen will become more cost-competitive with natural gas through

demand-side support policies. Alongside this, hydrogen will be increasingly pursued for long-term energy storage.

Funding this transition will prove to be one of the major barriers to renewable hydrogen development in the EU, as current estimates suggest that between €335 – 471 billion will need to be raised from 2020 to 2030.1 The bulk of this investment (€200 – 300 billion), however, is not needed for hydrogen infrastructure itself, but rather for the further development of 80 – 120 GW of solar and wind generation, to be connected to electrolysers. While much of this must be financed through private investment, the EU and member states have a key role to play in providing the incentives to unlock private capital.

To bolster investment in both domestic EU production and third country import of renewable hydrogen, the European Commission introduced the European Hydrogen Bank (EHB) on 16 March 2023. Through competitive auction rounds, the bank’s central role is to lower the cost gap between fossil-based and renewable hydrogen until it reaches a “level that private offtakers are willing and able to cover.” While auction design has not yet been finalised, the first round for domestic production will have a budget of €800 million and will aim to connect EU domestic supply and demand for renewable hydrogen, supporting producers by providing a fixed payment per kg of hydrogen for up to 10 years. Similarly, a separate

auction has been proposed to set a fixed price between international producers and EU consumers.

To further link supply and demand of hydrogen throughout the EU while developing business models and furthering research and innovation, the European Commission has called for the doubling of Hydrogen Valleys – industrial clusters –from 23 in 2023 to 46 by 2025. This will not only increase both supply of and demand for hydrogen, but will also allow for the development of best practices within the industry, create a wealth of new jobs, and make hydrogen more investable in both the short- and long-term – while also increasing public perception of the uses of hydrogen. Assuming this doubling is met, hydrogen production, transportation and industrial applications will undergo significant development, allowing them to become more investable and commercially-viable.

Moreover, final decisions on the Renewable Energy Directive’s Additionality Delegated Act (which sets the definition for renewable hydrogen, among other things, and affirms the principle of additionality) and the Methodology Delegated Act (which concerns greenhouse gas emissions savings calculations) have brought further clarity to the European hydrogen market. With the principle of ‘additionality’ now firmly set, and nuclear added as a renewable source of hydrogen production, investors and generators now have the necessary legal certainty to begin developing projects and contributing to the growing hydrogen economy. While not exhaustive, these developments will allow the EU to expand their hydrogen capabilities, and are vital steps towards the attainment of 2030 targets. Of course, success can only be assured if individual member states also work towards achievement of their individual hydrogen strategies. According to research conducted by Cornwall Insight’s Low-Carbon Hydrogen Index, significant progress has been made by many EU member states over the past year.²

Zoom in on the UK

The UK further cemented its hydrogen ambition in 2022, as April’s British Energy Security Strategy saw capacity targets double from 5 to 10 GW – of which half should be electrolytic – by 2030. In application, the fuel will be used primarily to cover industrial demand (see Figure 2) and provide flexibility through storage. To facilitate this increase, the government has been working to provide investors with more clarity on the future role of hydrogen within the UK, while also dedicating more funding to hydrogen projects throughout the country.

Providing a more consistent flow of communication between the government and the UK’s emerging hydrogen sector, the now Department for Energy Security and Net Zero has released several key documents over the past year to ensure that the market is kept in the regulatory loop.

Principally, April 2023’s Hydrogen Net Zero Investment Roadmap, an update to the previous year’s Hydrogen Investor Roadmap, provides a clear outline of past and future developments within the sector. Among other things, the roadmap provides dates for several key milestones such as the development of hydrogen business models, trials and final decisions on hydrogen’s

Figure 1. Hydrogen use by sector in the EU by 2030 (source: European Commission Staff Working Document Implementing the REPower EU Action Plan).

Figure 2. Projected hydrogen demand in the UK, 2030 – 2050 (source: DESNZ Hydrogen Net Zero Investment Roadmap).

use in domestic heating, and the viability of blending hydrogen into gas networks. While some of these decisions will not be made until 2026, it is nonetheless beneficial for the sector to know its future direction of travel in order to inform investment decisions in the short and longer term.

As the roadmap also provides estimates for hydrogen demand within the UK towards 2050 (see Figures 2 and 3), developers and investors are provided with further clarity on the expected size, scale and opportunity presented by a growing UK hydrogen sector. Coming alongside regular Hydrogen Strategy updates to the market – an overview of government activity in the hydrogen space over the preceding six months – investor confidence in the UK’s hydrogen sector is certainly improving.

The UK has also been backing targets with funding over the past year, as the ‘Powering Up Britain’ announcements in March 2023 confirmed the first 15 successful applicants from the £240 million Net Zero Hydrogen Fund. In this first round, £37.9 million will be made available for development (Strand 1) or capital (Strand 2) expenditure to help de-risk investments and lower lifetime costs, allowing projects to progress with a greater degree of certainty.

The second round accepted applications until May (Strand 1) and June (Strand 2) 2023, with a total of £45 million in the potential funding pot. Meanwhile, progress continues to be made on the development of the Hydrogen Production Business Model – which seeks to provide revenue support to low-carbon hydrogen projects – as the design has been finalised and the first 20 projects, of which many are electrolytic, have been selected. While the outcome of the round remains to be seen, with £58 million of revenue support allocated and with project applications totalling 408 MW – of which only 250 MW can proceed – it is clear that hydrogen projects are receiving significant support in the UK. In order to further advance the target of 2 GW hydrogen capacity by 2025, an additional allocation round will award contracts for up to 750 MW of capacity in 4Q23.

Despite such strong progress, the UK still has some work to do to develop its nascent hydrogen sector and deliver targets on time. On the one hand, it is necessary that the government further outlines plans for hydrogen transport and storage (T&S) as it is currently unclear how investment will be unlocked, what T&S infrastructure will look like, and who will build it. It is also key that the government acknowledges that with increasing competition for surplus electricity – through further electrification of industry and the growing presence of electric vehicles – the UK’s hydrogen sector will require dedicated sources of electricity to balance supply and demand (see Figure 4).

Conclusion and outlook

The European hydrogen economy continues to show promise for the future, as both the EU and national governments have been furthering their capacity ambitions while working to make hydrogen more viable at scale. This is no time for complacency, however, as the global hydrogen economy continues to become more competitive, with the US, India, China and Saudi Arabia – among others – all increasing both their appetite and funding for hydrogen development. As such, it is imperative that while hydrogen ambition continues to grow across Europe, it is met by concrete action to meet targets. In order to do this, European countries must work to secure supply chains, upskill labour forces, and incentivise investment in the still-nascent hydrogen economy.

References

1. ‘Communication from the commission to the European Parliament, the Council, the European Economic and Social Committee and the Committee of the Regions’, European Commission, (16 March 2023), https://eur-lex. europa.eu/legal-content/EN/TXT/?u ri=CELEX%3A52023DC0156&qid=16 82349760946

2. MAULE, J., ‘Furthering clarity and capacity: The UK increase low-carbon hydrogen commitments’, Cornwall Insight, (20 April 2023), https://www. cornwall-insight.com/our-thinking/ chart-of-the-week/furtheringclarity-and-capacity-the-ukincrease-low-carbon-hydrogencommitments/

Figure 4. Monthly renewable energy sources and nuclear generation and demand (source: Cornwall Insight).

Figure 3. Hydrogen demand range for industry in the UK, 2030 – 2050 (source: DESNZ Hydrogen Strategy Analytical Annex).

Conrad Purcell and Shu Shu Wong, Haynes and Boone LLP, discuss hydrogen’s role in energy security and the decarbonisation of the UK’s energy sector.

Against the backdrop of the UK’s Hydrogen Strategy, which was announced in 2021 and was hailed as a ‘green industrial revolution’, hydrogen has played an increasingly critical role in the decarbonisation of the UK’s energy system.

Pilot projects

Across the UK, a number of pilot projects have used hydrogen. For instance, last year Centrica Business Solutions announced that it will commence a 12-month trial to inject hydrogen into its existing 49 MW gas peaking plant in Brigg, Lincolnshire, England, with the use of HiiROC’s technology that produces so-called ‘emerald hydrogen’ – a type of hydrogen created using a process called Thermal Plasma Electrolysis.

This is the first time that hydrogen will be used within a grid-connected, gas-fired power plant. Blending hydrogen with natural gas will reduce the

overall carbon intensity of the plant. Additionally, the byproduct of emerald hydrogen is a form of solid carbon called carbon black, which can be captured easily and has commercial value, as it is used in the production of tyres, rubbers and toners, and also in building materials and soil enhancers.

The outcome of this trial will be important in informing future use cases of this technology and its wider deployment across gas-fired peaking plants.

Hydrogen is also being trialled in the quest to develop a cleaner and more efficient transportation sector in the UK. The first phase of a pilot project kickstarted at Teesside Airport in Darlington, England, with the use of vehicles fitted with 100% hydrogen, zero-emission engines.

The UK’s Hydrogen Strategy

The raft of pilot projects in the hydrogen sector has been propelled by the UK’s commitment to work with industry to meet its ambition to develop the country’s low-carbon hydrogen production capacity. The UK announced a £105 million funding package through its Net Zero Innovation Portfolio as a first step towards building the UK’s low-carbon hydrogen economy. The funding package takes the form of various grants to businesses and developers to support the development and trials of solutions to switch industry from high- to low -carbon fuels such as natural gas to clean hydrogen, for instance.

Additionally, in April 2022 the British Energy Security Strategy was published, outlining the government’s plan to double its hydrogen production target from 5 GW to 10 GW by 2030. In order to meet this target, the Net Zero Hydrogen Fund (NZHF) was announced, whereby £240 million of available funding will be distributed to eligible low-carbon hydrogen projects across four strands. Which strand a project can apply for depends on its maturity and the level of support required:

y Strand 1: DEVEX support for early projects to cover FEED studies and post-FEED studies.

y Strand 2: CAPEX for projects that do not need a hydrogen business model (HBM). A project applying for this strand must exist on its own merit and solely require CAPEX support.

y Strand 3: CAPEX for projects requiring an HBM.

y Strand 4: CAPEX for carbon capture, utilisation and storage (CCUS) projects requiring an HBM.

The HBM is a financial support mechanism incorporated into strands 3 and 4, and is designed to subsidise operational costs to encourage and support the hydrogen market. It is provided together with funds granted through the NZHF, as a long-term revenue support contract.

The HBM has many similarities with the Standard Contracts for Difference Terms and Conditions for Allocation Round 4 for low-carbon electricity, as well as the Heads of Terms for the Dispatchable Power Agreement and the Heads of Terms for the Industrial Carbon Capture Contract for the CCUS programme. Based on the government’s published indicative heads of terms for the HBM (Indicative HBM Terms), it is clear that the intention is to proceed with a contractual, producer-focused

business model that is applicable to a range of hydrogen production pathways. Some of the key elements include:

y A variable premium price support model where the subsidy is the difference between a ‘strike price’ reflecting the cost of producing hydrogen and a ‘reference price’ reflecting the market value of hydrogen.

y Setting a reference price based on the producer’s achieved sales price, with a floor at the natural gas price, and a contractual mechanism to incentivise the producer to increase the sales price and thereby reduce the subsidy.

y Providing volume support via a sliding scale in which the strike price (and therefore subsidy) is higher on a per unit basis if hydrogen offtake falls.

y Allowing small-scale hydrogen transport and storage costs to be supported through the business model where necessary, taking into account affordability and value for money.

y Introducing a levy to fund the business model from 2025 at the latest, subject to consultation and legislation, with the first electrolytic projects being funded through general taxation if they are operational before the levy is in force.

Allocation of risk, and potential legal issues

Different stakeholders of low-carbon hydrogen projects, whether it be the investors or developers, will have to consider a number of issues when allocating and managing potential risks, as set out in the following sections:

Investability

In order to apply for a particular strand under the NZHF, the project will need to meet certain eligibility criteria. For instance, in terms of strands 1 and 2, the business must be registered in the UK, the project must be completed in the UK, it must use technology tested in a commercial environment at a Technology Readiness Level 7 or above, and the business must intend to exploit results from or in the UK.

Projects that are successful in applying for strands 1 or 2, for instance, will receive grants that are paid quarterly, and only after quarterly audits are completed (which would include a visit from the appointed monitoring officer).

In addition to the lack of certainty in receiving each quarterly grant, due to the dependence on the successful satisfaction of an audit, another ongoing – and perhaps bigger – concern may be whether there would be a change in policy and thereby the framework of the aforementioned low-carbon hydrogen business model, if and when there is a change in government.

These are issues that would need to be taken into account when calculating the project metrics and determining the risk allocation when negotiating relevant agreements for the project.

Structure of hydrogen projects

As demonstrated through pilot projects using hydrogen (such as the collaboration between Centrica Business Solutions and HiiROC to inject hydrogen into a gas peaking plant), the development of hydrogen may require the

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collaboration of investors and developers/technology providers.

A point worth noting is that the Indicative HBM Terms provide for a term of between 10 – 15 years which reflects, amongst other things, a balance between providing price support certainty for producers for a proportionate and reasonable period, whilst not locking in production pathways for the long-term. It also serves as an indication as to the possible or potential duration of a joint venture (JV), if it is entered into.

Some of the usual list of issues for investors to consider when entering into a JV include the obligation to contribute funds to the JV company, the ownership of intellectual property rights, the mechanics of funding (whether by way of shareholder loans or the issue of preferred shares), voting rights, tag and drag along provisions, and deadlock resolution mechanisms.

Adaptability of existing plants

The use of hydrogen by power generators will raise a number of issues that need to be addressed and considered in advance. The first and main concern will be to ensure that the technology being used to generate power, such as a gas-fired turbine, can be adapted to run on blended fuel. This is important to ensure that the owner of the plant does not invalidate the performance and defect warranties that the technology provider offers with its equipment, for instance.

The owner of the plant will also need to ensure that the reliability and performance of the plant are not affected in a way that negatively impacts any obligations it has to provide power under the terms of any existing power sales contracts.

If the plant’s performance is negatively affected by the use of blended fuel, the owner of the plant may be penalised for under-performance of its plant and failure to meet its generation obligations.

Looking forward

The aim will be for hydrogen to replace fossil fuels, with green hydrogen (a type of hydrogen that produces no harmful greenhouse gas emissions) being the sole produced type. However, green hydrogen is still in its infancy, and hydrogen has so far not been used at scale due to the costs associated with its production and the maturity of the various technologies already in existence for other forms of energy.

Fortunately, with the UK government’s commitment to and backing of the hydrogen industry, in the form of various grants and subsidies, the development of low-carbon hydrogen projects across the UK has witnessed strong growth. Low-carbon hydrogen will no doubt play a very important part in the UK’s energy security and the country’s aim to create a diverse and secure decarbonised energy system – ultimately helping the UK to meet its commitment to achieve net zero by 2050.

Global Hydrogen Review Online

Nuno Antunes, Association of International Energy Negotiators (AIEN), talks about the challenges of creating a green and low-carbon hydrogen economy, and how the AIEN member network is attempting to take steps to support this.

In order to deal with the issues of climate change, society is working towards an energy transition that is eliciting a change in industry segmentation. There is recognition that different forms of energy make up the sector, and that they need to work together if we are to meet decarbonisation targets. There will be no net zero without a contribution from green and low-carbon hydrogen.

However, what does this mean for the oil and gas industry? At surface level, the diversification of energy companies to meet the needs of the energy transition can be seen in brand changes. Statoil has become Equinor, Total has changed to TotalEnergies, Qatar Petroleum is now QatarEnergy, and the Association of International Petroleum Negotiators (AIPN) has become the Association of International Energy Negotiators (AIEN) to reflect the needs of members. However, these are more than just name changes. The new names reflect substantive changes that underline the evolution of the oil and gas industry in the context of the energy transition.

We have relied on petroleum products for a long time. First, it was liquids. This was then followed by a greater demand for gas. Of course, petroleum will remain in focus for many years yet, but a number of other energy sources are now entering the mix, and there is a broader focus on what is needed in order to meet energy demands for the future. When factoring in more expensive energy, a number of hurdles lie ahead.

At the 2022 International Energy Summit (IES), Gunther Newcombe OBE, Project Coordinator, Orion Clean Energy Project (Shetlands), explained: “Hydrogen is part of an integrated energy solution but, whereas electricity is simple, hydrogen is more complicated. A hydrogen economy is a balance between equity, environment, and energy security. Whereas focus has been on the environment, geopolitical events have put greater emphasis on security and affordability.”

AIEN, which is a member voluntary organisation, supports the energy transition in a number of different ways. The launch of three taskforces earlier this year – hydrogen;

carbon capture, utilisation and storage (CCUS); and the broader subject of environmental, social and governance (ESG) –endeavours to respond rapidly to emerging issues in the wider energy realm.

Hydrogen: all the colours of the rainbow

Hydrogen has been produced from methane for many years, and has become one of the key focuses of the energy transition. Production from methane does not combat the issue of carbon emissions, and so companies are looking for ways to increase the volume of hydrogen that is produced from renewables or other low-carbon emission sources. There is a whole rainbow of colours associated with hydrogen, reflecting its technology and feedstock, as well as its associated carbon footprint – from black hydrogen produced from coal with carbon emissions; grey (carbon emissions) and blue (carbon captured using steam reforming from natural gas); through to green hydrogen produced via electrolysis powered by renewable electricity.

Other colours remain underexplored, such as turquoise hydrogen (methane split into hydrogen and solid carbon through pyrolysis), and white hydrogen (which already exists in natural form, and whose potential is yet to be uncovered).

As the hydrogen economy develops, and more colours are effectively added to the hydrogen rainbow, localised production methods will vary depending on regional resources and circumstances, as well as applicable legislation.

The hydrogen taskforce

Generally speaking, one of the biggest challenges associated with creating a green or low-carbon hydrogen economy is overcoming the inertia required to get the ball rolling. Legislation and regulations are still developing, and contracts and clauses will vary from archetypical oil and gas contracts. How projects are financed is one major hurdle.

At the IES, Manuel Manrique, Hydrogen International Business Development Manager, Repsol, said: “The question is how we create a global hydrogen market and commoditise it. We require solutions for transportation and projects need to be bankable. This requires offtakers to give certainty.”

For oil and gas projects, joint ventures (JVs) typically constitute entities that are similar. For hydrogen, however, there may be varied stakeholders, including traditional oil and gas companies (majors included) and utility companies, who are not typically used to working with each other on energy projects. Although some parallels may be drawn with traditional oil and gas, there is still a lot of work to be done with regards to how contracts will reflect the differences in the types of projects and contributions of various stakeholders.

Currently, not many green hydrogen projects have commenced production. The first full-scale industrial plants will probably not be online until late next year. As such, AIEN’s Hydrogen Taskforce has started up to try to help members to fill knowledge gaps when it comes to the hydrogen sector. Defining the deliverables, such as model contracts and clauses, will help to accelerate the development of hydrogen projects.

In order to develop green and low-carbon hydrogen such that it becomes a key actor in the decarbonisation journey, all those involved in the industry need to help one another by pooling knowledge and experience. Alongside the creation of materials

to help facilitate projects, forums for knowledge sharing and discussing how to overcome challenges are critical to the creation of a viable hydrogen economy. Hydrogen production requires input from legislation, as well as financial/economic and technical standpoints to understand difficulties, overcome hurdles, and ultimately make projects bankable. Only then will significant green and low-carbon hydrogen production be realistic. Ultimately, the more voices that join the choir, the faster hydrogen resources and deliverables will be developed.

The hydrogen value chain

While oil and gas is quite neatly apportioned through upstream, midstream and downstream production, hydrogen requires a slightly distinct approach. Upstream, there are several ways of producing all of the different colours of hydrogen, with specificities in each value chain. Downstream, how hydrogen is utilised will also vary. The best option is using it in applications where electrification is technically or economically unfeasible. It is in the harder-to -abate sectors, such as refining, steelmaking, fertilizers (ammonia), or even in aviation (through synfuels) that green or low-carbon hydrogen can have the most impact in terms of decarbonisation.

Midstream, how one ships, stores and transports hydrogen, or combines hydrogen with carbon capture technology (e.g., synfuels), are all areas to be further investigated. The offtaker (and how it uses hydrogen) may have to be considered in order to define technical aspects of a project. Where transportation is necessary, perhaps not all clients will want to receive hydrogen in the form of ammonia. How to transport hydrogen when production is not onsite will be a critical consideration when designing hydrogen projects.

The cost of hydrogen

How much users will be willing to pay for hydrogen will impact project viability. Different regions are looking at supporting the creation of hydrogen economies in different ways. Globally, the cost of green hydrogen production is expected to drop. The most optimistic forecasts are eyeing up a target of US$1.5/kg by 2030. At present, however, it is difficult to place green hydrogen on an equal footing with grey hydrogen in terms of production costs, and how these will be equalised through government support could become critical for the emergent hydrogen market.

At the IES, Emily Sykes, Vice President, Energy Transition Fund, Copenhagen Infrastructure Partners, explained: “Scale is a bigger issue than price. As hydrogen technology scales, prices will come down. The challenge is how to get offtakers to start buying hydrogen. Certainty in this area will make projects viable.”

Conclusion

We are on an energy transition journey, and this will not happen overnight. While there are many hurdles to overcome, hydrogen offers a promising means for decarbonising certain hard-to-abate sectors. The sharing of knowledge and experience can provide a springboard for the acceleration of hydrogen market development, and the AIEN Hydrogen Taskforce is focused on bringing AIEN members together and collaborating with other organisations to achieve common goals and facilitate value creation in the hydrogen sphere.

Hydrogen, in particular green hydrogen produced via electrolysis, is seen as key to the global energy transition and meeting ambitious net zero targets by 2050. As the technology progresses, end users in industry increasingly see it as an answer to decarbonisation and ultimately removing carbon dioxide (CO2) emissions from their operations altogether.

In February 2023, Protium announced a partnership with the University of South Wales (USW) to deploy its first 100 kW electrolyser in Baglan, South Wales. This is the UK’s largest anion exchange membrane (AEM) integrated electrolyser, sourced from Enapter.

This partnership highlights the critical role that green hydrogen can play in reducing greenhouse gas emissions from industry. Commissioning of the Pioneer project also marks a significant milestone in building a network of hydrogen-generating facilities for the UK’s green hydrogen infrastructure.

How the technology works in practice

AEM electrolysers feature a semipermeable membrane that conducts negatively-charged ions to carry out water electrolysis, using renewable energy to split water molecules into hydrogen and oxygen. This combines the affordability of alkaline electrolysers with the flexibility, fast response, compact size, and high hydrogen purity of proton exchange membrane (PEM) technology.

AEM technology is also highly scalable, with small-to-medium production needs met by stacking as many units as necessary in cabinets. The particular product variant selected for the Pioneer project was the AEM Electrolyser EL 4.0 Liquid Cooled (LC). This was chosen because the limited space available in the 20 ft shipping container meant that an external water-cooling system was essential.

When operating at full capacity, the electrolyser will generate around 40 kg/d of hydrogen at a pressure of 35 barg. The hydrogen

Jon Constable and Stephen Peng, Protium, speak about their experience of using electrolyser technology in green hydrogen projects as end-to-end project developers, outlining the pitfalls and lessons learned.

will then be compressed up to 450 barg using a compressor, which enables the hydrogen to be transferred into a series of manifold cylindrical pallets (MCPs) that are used for transportation and storage of the finished hydrogen product at a pressure of 300 barg. This is suitable for use in a variety of applications, such as fuel for vehicles, stationary power systems, or heat.

The integration was achieved very quickly, as the devices have hybrid hardware-software capabilities that streamline and speed up commissioning (and unlock remote monitoring and control). A toolkit was also used to create energy management systems.

Tools such as Enapter’s Energy Management System Toolkit make it possible to cut the deployment time for such projects even further. It is possible to use premade blueprints to integrate third-party energy devices, or control entire energy systems from one place, regardless of the individual components and what software languages they communicate with. Such software will not only increase the speed at which green hydrogen projects can be rolled out, but also unlock further value by tying energy production to wider data sources and automated decision making; integrating AEM electrolysers within industrial systems via the OPC UA Industry 4.0 protocol; and giving developers/integrators of energy solutions open-source tools to innovate.

Green hydrogen: project development

The process of developing a green hydrogen project is not dissimilar to developing any other type of energy project. The facility must be designed to the relevant standards, correct permits must be in place, and planning consent must be granted prior to construction. However, there are no specific design standards or regulations for green hydrogen projects. Therefore, developers need to use existing standards and regulations, some of which are not fit for purpose. For example, the permitting process treats green hydrogen as it would a large chemicals facility. As these projects are new and not yet on a significant scale in the UK, planning authorities are not as familiar with them, and the framework needs to be developed to facilitate the introduction of hydrogen into the country’s infrastructure. It is worth noting that this is very common for the introduction of new technologies.

A typical development begins with finding a location for the project, followed by design, procurement of equipment, and finally construction and commissioning. Where the Pioneer development differed from a typical project is that Protium procured the electrolysers first.

The electrolysers are unable to generate hydrogen on their own without additional balance of plant items, such as water treatment and drying. To achieve this, Protium approached Fuel Cell Systems, one of Enapter’s UK integration partners, to combine the electrolysers and balance of plant items into a single 20 ft shipping container to achieve modularity for the system.

The site

During the electrolyser integration step, Protium evaluated several sites for deployment. An ideal green hydrogen site typically includes:

y Availability of electrical power – both grid and behind the meter renewables.

y Availability of water – mains water for small- and medium-scale projects; seawater for large-scale projects.

y Familiarity of hydrogen and other high-pressure gases.

y Access to technical expertise and subject matter experts in hydrogen.

y Proximity to key offtakers.

Protium has partnered with the University of South Wales’ Hydrogen Centre to deploy this first electrolyser, as both parties see this initial project as a catalyst for additional hydrogen production in South Wales. Through commercial operations, the team will also create knowledge of how to operate the technology.

Planning and permitting

Protium concluded that the development fitted within the developmental boundary provisions for the University site. Working alongside a planning specialist, the company applied for standard rules low impact installation part A. With typical permitting processing times reaching six months or more, Protium worked with Natural Resources Wales (NRW) to develop a new permitting process specific to green hydrogen. This will reduce the permitting process to around two months, and is due to be rolled out later in 2023.

Technical design and safety case

Hydrogen is at the forefront of discussions surrounding decarbonisation and net zero, but in fact it has been used safely by industry for many years. The first hydrogen fuel cell was developed in the 1800s, and hydrogen has been used in oil refining, petrochemical, steel, and fertilizer production for over half a century. Years of research and development and practical experience have made it possible to develop rigorous engineering controls and guidelines to mitigate the risks of producing, transporting and using hydrogen.

Established production methods such as electrolysis are now being scaled up and deployed at larger centralised and smaller localised production hubs, each covering a few acres, creating the need to review and update regulations so that the right processes are in place to help developers deliver and operate safe facilities.

Green hydrogen builds on − and draws knowledge from − other industries in order to maintain inherently-safe design standards. When it comes to designing, constructing and maintaining a

Figure 1. The University of South Wales’ Hydrogen Centre.

green hydrogen production facility, developers also draw on learnings from the smaller bank of facilities that have been developed. As of January 2022, there were around 25 similar facilities in operation internationally, with the largest being the 3 MW system operated by ITM Power in Tyseley Energy Park in England.

While there are many engineering, procurement and construction (EPC) companies looking to develop skills within the hydrogen industry, the size of the Protium electrolyser meant that a partner with experience of deploying small-scale electrolyser facilities in the UK was required. Fuel Cell Systems also had experience in this end of the UK market, and was selected to integrate the Pioneer system.

The design for the Pioneer system was completed in December 2022, and installation commenced in January 2023.

Commissioning and looking to the future

Protium started the construction phase of the project in January 2023, with commercial operation in March 2023. With up to 65% of the levelised cost of hydrogen coming from electricity, the company is working with Siemens to develop a digital twin to optimise the production of hydrogen, with the aim of utilising electricity when the price is low and halting production when the price is high. With the digital twin, Protium aims to deliver the lowest levelised cost of hydrogen to its clients, enabling a feasible and cost-effective energy transition.

Lessons learned

Reading about the deliverability and cost of developing a hydrogen production facility in a consulting report is one thing, but delivering and scaling up projects is another issue altogether. When it comes to getting a small-scale electrolyser system online, some of the key learnings from the Pioneer project are outlined in the next section.

Managing inherent safety

A key aspect of any project is ensuring that inherent safety is achieved within the design. By its nature, hydrogen is more flammable than natural gas. However, being a much lighter

molecule, it also disperses faster. Therefore, achieving adequate ventilation for a hydrogen system is a key challenge to prevent hydrogen from reaching its flammability limit (4% v/v in air).

In order to achieve an inherently-safe site, many key pieces of equipment were deployed outside of containers to ensure maximum natural ventilation and to prevent hydrogen build-up.

Additionally, the hydrogen container was fitted with forced ventilation, which ensures that hydrogen can never reach its flammability limit. Explosion-proof equipment is also used where needed.

Supply chain disruptions

The ongoing war in Ukraine, coupled with a surge in demand for green hydrogen products, has put a squeeze on the supply chain in nearly every area of the mechanical manufacturing of products. It is not typical to see costs increase by over 30% and lead times increase by over 100% in the space of a few weeks. From a developer perspective, this puts pressure on placing orders early and managing contracts to prevent cost overruns.

Stakeholder management

An often overlooked aspect of projects is stakeholder management. Green hydrogen is a nascent industry and many key stakeholders are unfamiliar with hydrogen compared to other fuel sources. The key lesson here is that a developer’s job extends to educating all stakeholders about green hydrogen, including the benefits and drawbacks of utilising hydrogen in their processes.

The future

Project Pioneer demonstrates the ongoing development of the UK hydrogen market. One of the key takeaways from the project has been to demonstrate the importance of scaling up in the market, proving the technology and processes, and leveraging the lessons learned. This has meant that Protium has been able to deliver outcomes more quickly, which is important for the wider market. The project has brought different parts of the market together on the green hydrogen journey – supply chain, transportation, safety parties, electrolyser manufacturer, university partner and employees – giving everyone the chance to grow, analyse, learn, and scale up for the future.

Figure 2. Pioneer One project timeline.

Hydrogen has long been recognised for its potential to decarbonise industry, not least in transport and logistics. The 2015 Paris Agreement highlighted the key role that it is expected to play in the race to reduce emissions, making up a significant portion of fuels used by the middle of the century.1

Despite high hopes, however, uptake of hydrogen has lagged in comparison to the ambitious targets set by the scientific community. At the current rate, it will only constitute 5% of the energy mix by 2050 – well below the agreement’s stated goal.

Adoption in transport and logistics has been slow for several reasons, although the continuing availability of cheaper fossil fuels is arguably the biggest obstacle. In the UK, the rollout of infrastructure required for widespread adoption has also raised concerns. The UK’s Petroleum Industry Association, for example, recently criticised the government for delaying publication of key business models for future hydrogen storage and transport.²

The worldwide market for hydrogen-fuelled vehicles, including heavy goods vehicles (HGVs) and forklifts, is expected to grow exponentially – from US$1.19 billion in 2021 to US$36.9 billion by 2030 according to one forecast³ – yet this hinges on the ability to refuel fleets remotely. This is a huge challenge, especially in the early stages, but there are positive signs. Centrica recently announced that it would inject hydrogen into one of its peaking plants for the first time.⁴ If successful, this trial will pave the way for low-carbon power using some of the UK’s existing infrastructure, and the transport and logistics sector will have further evidence of the benefits that it needs to expand its own use of hydrogen.

PEM’s promise

Centrica’s trial will also pose questions about accessibility. If hydrogen is proven to be effective at larger power facilities, then it will be more important than ever to increase its availability

Richard Yu, IMI Critical Engineering, explains why decentralisation is key to the energy transition, and how applied knowledge of flow control systems is helping to accelerate the hydrogen economy in key industries such as transport and logistics.

across businesses and warehouses with easily accessible onsite fuel cells. One effective way to do this is by using electrolyser technology – more specifically, polymer electrolyte membrane (PEM) electrolysis.

PEM promises to deliver large volumes of pure hydrogen more sustainably than other production methods, which typically involve the use of fossil fuels. These types of hydrogen – otherwise known as blue, grey, black or brown – come with a carbon penalty, and still account for a large percentage of the hydrogen used by industry today. So-called green hydrogen, however, avoids the use of fossil fuels by relying on electricity generated using renewables. This opportunity is now being spearheaded by newer, more efficient technologies based on PEM, offering businesses a commercially-viable option for the first time.

Still, low-carbon hydrogen will remain difficult in the short- to medium-term, given that most facilities continue to be powered by a grid that is dependent on fossil fuels. When factoring in this, alongside the rising costs that punctuate today’s business landscape, it is understandable why some organisations might view the fuel as a longer term prospect. Consequently, this situation has increased interest in decentralised electrolyser technology as a more affordable means to create hydrogen onsite.

For transport and logistics organisations, this distinction is vital. Given the ongoing boom of fuel cell vehicles and the expansion of ultra-low emissions zones, upgrading existing fleets will soon be necessary. Yet with further delays to nationwide hydrogen

infrastructure, there is a risk that only those with large financial reserves will be able to consider it as an option.

Turnkey solutions

So-called turnkey solutions are important because they lower the CAPEX that is necessary to begin making green hydrogen. While many analysts believe that the ‘cost curve’ is now flattening, the CAPEX needed for production still remains prohibitive for smaller businesses. According to the International Renewable Energy Agency (IRENA)’s report, green hydrogen currently costs between two and three times more per kg when compared to blue hydrogen.⁵ Even if businesses were working against the lower end of that scale, green hydrogen would still struggle to make a case in terms of cost-competitiveness.

It is this thinking that has led companies, such as IMI plc, to apply pre-existing knowledge of process systems to the hydrogen sector, creating energy-efficient packages for smaller scale facilities. Unlike other electrolyser designs, integrated skid solutions can be housed in standard shipping containers and deployed with minimal disruption at a much lower cost. Some of these containers can also be fitted with fuel cells and storage systems, eliminating the complications that can arise once the hydrogen itself has been extracted – a common stumbling block for organisations without the ability to capture CO2 when reforming the steam from natural gas. Digital twin analysis can also be used to improve the efficiency of the electrolyser stack, balance supply and demand, and optimise surrounding equipment, giving smaller organisations access to advanced electrochemical processes and instrumentation without having to gamble on a large or untested investment.

The future

It is important to point out that this technology already exists and is in operation at larger plants. However, the size of the available solutions – operating at 10 MW up to 1 GW – means that they are only suitable for the biggest names in the industry. Taking this into account, modularity, scalability and affordability will be key to ensuring that clean hydrogen can be fully harnessed in the transport and logistics sector.

In order to make fuel-celled fleets a reality, applied knowledge of existing systems will be required. This is why PEM electrolysis, made possible in decentralised turnkey solutions, is critical. Improving access to green hydrogen should be a cornerstone to any decarbonisation efforts, but the sector cannot wait for infrastructure to catch up with ambition. Decisive action is required now.

References

1. ‘Hydrogen at risk of being the great missed opportunity of the energy transition’, DNV, (14 June 2022), https://www.dnv.com/news/ hydrogen-at-risk-of-being-the-great-missed-opportunity-of-theenergy-transition-226628

2. ‘UKPIA calls on Government to speed up publication of its hydrogen transport and storage business model or risk Net Zero targets’, UKPIA, (22 November 2022), https://www.ukpia.com/media-centre/ news/2022/hydrogen-transport-and-storage/

3. ‘Fuel Cell Vehicle Market Size, Growth, Demand, Opportunities & Forecast To 2030’, altenergmag.com, (11 February 2022), https:// www.altenergymag.com/news/2022/11/01/fuel-cell-vehicle-marketsize-growth-demand-opportunities-forecast-to-2030/38484/

4. LAWSON, A., ‘Peak power: hydrogen to be injected into UK station for first time’, The Guardian, (23 October 2022), https://www. theguardian.com/environment/2022/oct/23/peak-power-hydrogeninjected-uk-station-centrica

5. ‘Green hydrogen cost reduction’, IRENA, (December 2020), https:// www.irena.org/publications/2020/Dec/Green-hydrogen-costreduction

Figure 1. Turnkey solutions support hydrogen use for power-to-mobility.

Figure 2. IMI VIVO applies engineering knowledge to increase hydrogen accessibility.

Michael Immel, Holzapfel Group, Germany, explores how plating solutions can help to improve the efficiency of electrolysis in hydrogen production.

High-quality plating solutions for production equipment components can significantly help to boost the efficiency of electrolysis, and are a key step towards transforming energy generation and upscaling hydrogen production to an industrial level.

It is common knowledge that hydrogen is set to play a key role in solving the problem of how to store renewably-generated energy and thus make a major contribution to achieving carbon-neutrality in the energy, industrial and mobility sectors. The production of climate-friendly green hydrogen in particular can help supply part of the current demand for energy from renewable, carbon-free sources. As hydrogen is a flexible source of energy in terms of storage and transportation, it also makes using energy generated from renewable sources possible in other sectors.

However, this development greatly depends on achieving large-scale production of hydrogen as a transportable and storable source of energy in the near future. The electrolysis process to produce hydrogen needs to be optimised in order to ensure that it can be

efficiently and sustainably produced on a major scale in the long-term.

The role of surface technology

Optimising alkaline electrolysis can be a helpful way of achieving this aim. Surface technology is also playing a vital role in making hydrogen technologies fit for the future. As a result of developing the corresponding functional layers, surface technology can offer new properties to the components that are used in alkaline electrolysis, by way of adding protective features that make them more durable, effective and efficient, for example.

Electrolyser components that require plating

Within the overall system of alkaline electrolysis, the electrolysis block is the essential component that enables water to be broken down into its two components: hydrogen and oxygen.

An electrolysis block consists of various electrolysis cells. An alkaline pressure electrolysis cell, on the other

hand, consists of the following functional components: working electrodes, a bipolar plate, a membrane with a pressure ring, a cell frame (with collectors for removing the gas and supplying the electrolyte), and a three-layer electrode package. This package is made up of the bipolar plate, also called a separator plate, a cathode, and an anode (cathode for generating hydrogen, anode for generating oxygen) and arranged in so-called cell stacks or electrolysis stacks. The composition of these individual parts in the electrolysis cell can have a direct impact on the efficiency of hydrogen production.

First and foremost, it is necessary to plate the individual components in order to improve the durability and service life of the entire system. Moreover, applying a corrosion protection layer can make the parts considerably more resilient.

Energy efficiency can also be improved. From a mechanical point of view, this treatment ensures that the electrode packages deliver optimal performance. Electroplating, for example, enables the process to be upscaled to industrial level. The process of electroplating can rule out any mechanical damage and deformation of the electrodes that can occur when coating with atmospheric plasma spraying (APS) or vacuum plasma spraying (VPS) at high temperatures.

Plating options for electrolysis components

Electroplating has long been established as a production technology that is suitable for large series, such as for applications in the automotive industry. Electrode package components, such as anodes, cathodes, separator plates and end plates, as well as cell frames and water-bearing components installed in the electrolysis block, can be plated with a functional anti-corrosion layer. There are a number of different tried-and-tested electroplating processes available for this purpose, such as electroless nickel, nickel sulfamate, electroplated nickel, silver, tin, zinc-nickel, or combinations of these processes.

Plating to improve efficiency

Aside from protecting against corrosion, electroplating technologies are also key for optimising electrolyser production. The Holzapfel Group has developed a special nickel-based process in which the anode, the cathode and the separator plate are plated to improve long-term stability. To boost efficiency and prevent degradation, the cathode is plated with an additional layer that works as a catalyst. One of the effects of this special layer is that the electrolyser’s active surface area is increased, which leads to a higher performance density, making it possible to produce a large amount of hydrogen within a small installation space. This in turn reduces the volume of investment.

Compared to nickel plating, these specific coating processes ensure significantly greater efficiency and therefore a more economical mode of operation due to lower energy consumption, as the electrochemically active platings reduce the amount of energy consumed for gas production.

Upscaling to industrial level

Specialists in the field of surface technology are collaborating with various institutes on research and development projects to improve electroplating methods and, above all, to make them available for industrial series production. For instance, alkaline electrolysis technologies are being developed to enable electroplating methods for electrodes on an industrial-scale, with the aim of making them ready for the market. The goal is to take successfully validated materials and plating processes from the technical prototype stage and develop them for deployment on an industrial-scale. The main focus is on validating selected materials and processes that will drive the transition from small series to processes that are suitable for large-series production, combined with low material and production costs as well as the potential to exclude the use of precious metals. One of the main challenges over the next few years will be the ability to develop these technologies for use in the large-scale electrolysis industry, based on suitable materials and processes with the potential to cut costs.

Developments

Companies within the surface technology sector, such as Holzapfel Group, currently offer, and are constantly improving, plating technologies for hydrogen production

Figure 1. Core electrolysis block component – structural elements of an alkaline pressure electrolyser/diagram of a cell stack.

Figure 2. Functional principle of a single alkaline electrolysis cell.

plants and electrolysers. A range of services are available to customers, including electroplating processes that make the catalytic effect more efficient (thus boosting overall effectiveness by saving energy), as well as solutions for scalable processes and options for assembling and testing stacks. The Holzapfel Group develops, produces and assembles complete customised electrode packages with gas-tight, materially-bonded connections. The Group’s solutions for ensuring efficient, sustainable electroplating have been successfully tested in various projects and are currently being further developed in collaboration with partners and institutes.

With alkaline water electrolysis, plating can also be carried out on a large-scale: components up to the size of 2300 x 2100 mm can be effectively plated with functional layers.

Specialised nickel process

One of the company’s most significant developments to date is electroplated Raney nickel coatings, which offer distortion-free deposition. Studies have shown that flat electrodes and those made with Raney nickel coatings currently have excellent results when it comes to the electrical efficiency of alkaline electrolysers. The advantage of flat, electroplated anodes and cathodes is that they can be positioned in the cell with the smallest possible distance to the membrane (zero gap). As a result, the development of the electroplated Raney nickel coating helps to improve

the energy balance in the stack of the electrolysis block and therefore in the electrolyser system as a whole. Electroplated surfaces also make it possible to plate a significantly larger area of the electrode. According to current estimates, this will enable the industrial-scale production of electrodes from one piece, for most electrolyser sizes. The key factor here is to develop production line technologies that ensure that the plating thickness and metal distribution on the electrode surfaces is consistent and distortion-free. The Holzapfel Group is collaborating with partners to achieve this aim.

WE ARE READY FOR THE GREEN FUTURE

Figure 3. A 3D sketch of an alkaline electrolysis block.

The hydrogen economy is now gaining renewed attention as leaders in both the public and private sector feel a growing sense of urgency to decarbonise the industrial economy. Hydrogen is a clean-burning molecule that can be produced without emitting harmful pollutants. This can be achieved through various methods, including traditional steam methane reformation (SMR), gasification processes with carbon capture, or electrolysis that utilises low-cost or excess renewable energy in the electric grid.

In the transition towards a net zero economy, hydrogen has emerged as a promising solution for reducing emissions in difficult-to-electrify thermal loads, as well as in the ‘greening’ of refineries and chemical processes. There is an active, rigorous debate on how to prioritise the use of this molecule, as it is still expensive to produce in comparison to traditional or alternative fuels and energy carriers. However, its use is unavoidable in the context of a carbon-neutral society. By 2050, hydrogen production is expected to make up 12% of the world’s energy supply with a wide range of novel applications such as blending hydrogen in natural gas, or utility-scale electrolysers.1

It is important that highly-reliable measurement instrumentation is used throughout the hydrogen value chain – from production to end user. Due to its challenging nature, it is essential to seek expert consultation on hydrogen processes and specific advice on the evolving instrumentation challenges in this emerging market. One critical measurement, pressure, poses a particular risk: the permeation of hydrogen through the process membrane.

What is hydrogen permeation?

In direct hydrogen gas service, hydrogen molecules dissociate on the diaphragm surface of the pressure transmitter. Next, hydrogen atoms lose electrons and the subsequent hydrogen ions diffuse through standard 316L or Alloy C diaphragms. Once on the other side of the metal diaphragm, the hydrogen ions capture electrons and recombine into hydrogen molecules (see Figure 1). The permeated hydrogen finds its way into the fill fluid of the pressure cell.

The speed and degree at which permeation occurs is impacted by the process pressure and temperature.

Why is hydrogen permeation detrimental to pressure transmitters?

The dangers resulting from hydrogen permeation are not immediate. So long as sufficient process pressure

is maintained on the diaphragm, the hydrogen molecules will remain in solution. It is only when the process pressure drops to near or below atmospheric pressure that damage occurs (see Figure 2). With reduced process pressure, hydrogen molecules in the fill fluid leave the solution and form gas bubbles. This happens very quickly, increasing the fluid volume and internal pressure. As the pressure cell or diaphragm seal is a closed environment, this additional volume has no means of escape. Consequently, the thin 316L/Alloy C membrane becomes distended, resulting in irreparable damage.

Hydrogen production

There are three emerging technologies for large-scale electrolysis, which is the process of splitting water with high DC currents into its constituents: hydrogen and oxygen. These technologies are proton exchange membrane electrolysis cell (PEMEC), alkaline electrolysis cell (AEC), and solid oxide electrolysis cell (SOEC).

Pressure is an important parameter, as many of these technologies operate based on differential pressures across the membrane. After the water is converted, the hydrogen gas is treated/dried for the eventual end use. Outlet pressure or differential pressures across critical components are important indicators of a healthy process, and are used for Safety Instrumented Systems (SIS) or functional safety requirements in some cases.

As such, the risk of hydrogen permeation in pressure transmitters is ever-present when using these new production techniques, as various process conditions are present that can directly impact the risk of hydrogen permeation through pressure transmitter diaphragms.

Hydrogen blending

There are more complicated matters at hand, deviating from the typical hydrogen applications of the past such as methanol production, hydrogenation in refineries, or petrochemical facilities. As seen in recent power plant demonstrations, such as Long Ridge Energy’s hydrogen-ready power plant in Hannibal, Ohio, US, there is growing interest in blending hydrogen into natural gas to reduce the carbon content in gas pipelines or fuel systems.

Figure 3 illustrates the use of pipelines in the hydrogen sector. Compressors are used to inject blended gas back into the pipeline. It is critical to keep the injection pressure higher than the pipeline pressure to ensure that the blended gas will be

Cory Marcon, Endress+Hauser, USA, discusses how hydrogen permeation can pose risks to plants, and how this can be managed with the right instrumentation.

pushed into the pipeline. Any pressure transmitters on the blended gas line and downstream of this injection site would be subject to some increased percentage of hydrogen by volume. Failures in pressure measurements could cause a potential trip in the control loop if the supply pressure faults. Negative effects on plant uptime and the supply chain, as well as high maintenance costs, must of course be avoided at all times.

The risks of permeation are different at various blends of hydrogen, offering further complexity to end users or engineering firms that are designing new systems or validating the existing infrastructure’s capabilities relative to the potential percentage of hydrogen by volume.

What can be done to mitigate the risk of hydrogen permeation?

The most common approach is to apply a gold coating to the external face of the diaphragm. This gold layer increases the density of the diaphragm, thus creating a diffusion barrier to impede hydrogen permeation. When properly utilised, gold coating will decrease hydrogen permeation up to 106 times, due to its very low diffusion coefficient.

A wide variety of gold coatings are available, but not all are suitable for hydrogen permeation prevention. A nominal coating thickness of 25 µm strikes a good balance between protection and cost. A thinner coating is more difficult to apply evenly and risks the development of pinholes and reduced protection.

Hydrogen permeation in conjunction with metal diaphragms is relentless. Consequently, no coating will prevent this phenomenon from occurring. However, a properly employed gold coating is a cost-effective method to significantly reduce hydrogen permeation and extend the life of pressure transmitters.

If hydrogen is blended with natural gas, the volume of hydrogen present is reduced. This results in a reduction of the risk of hydrogen permeation – but it does not eliminate it. As such, the most conservative design approach, even with blended applications, is to utilise gold coated membranes. If hydrogen blending is temporary or < 10% by volume, traditional 316L stainless steel membranes could also be employed.

Extending the portfolio

Hydrogen is considered the most economical and energy-efficient way to store green energy. As a result, governments are pushing to increase its availability by enhancing the capacity of electrolysers. There is also a current shift away from centralised energy production and storage towards smaller scale local production and use. Thanks to the introduction of the PMP21, with optional gold-coated diaphragm, a lower cost option is now available for electrolyser original equipment manufacturers (OEMs) making smaller, modular designs.

For high-pressure applications, pressure transmitters with gold-coated diaphragms are the industry standard. For example, the PMP21 with its pressure limit of 400 bar is suitable for compressor stations and tube trailing filling applications. With ingress protection ratings of up to IP 68, and high-quality materials such as 316L, the Cerabar PMP21 is designed for the harsh conditions in the process industry.

Conclusion

As the process industry moves towards net zero, the demand for decarbonisation continues to grow. This increased focus on the production, storage and use of hydrogen as a clean energy carrier and direct or blended fuel has resulted in the emergence of new applications and measurement challenges: when not treated right, hydrogen can cause safety issues and create a potential weakness in the system. It is therefore crucial to partner with knowledgeable instrumentation providers to mitigate risks.

Reference

1. ‘Global hydrogen trade to meet the 1.5˚C climate goal: Trade outlook for 2050 and way forward’, IRENA, (2022), https://www.irena.org/-/ media/Files/IRENA/Agency/Publication/2022/Jul/IRENA_Global_ hydrogen_trade_part_1_2022_.pdf

Figure 1. Hydrogen ions diffuse through a diaphragm.

Figure 2. Hydrogen embrittlement on pressure transmitter diaphragm.

Figure 3. Renewable hydrogen blending in the natural gas network (source: Australian Energy Council).

As the leading innovator, we continue to supply our customers with the technology, methods, and consultancy to make the best integrity management decisions for their assets. No matter what the future holds, renewable hydrogen as a flexible energy carrier plays a vital role in moving the industry further; we want to make sure you are ready.

Fit for the Future. Ready for Hydrogen.

The shift towards a clean energy economy has brought new measurement challenges, particularly in the area of hydrogen fuel. Accurate traceability − the ability to trace a measurement to a national standard − is essential to ensure impartial verification of measurement accuracy and customer confidence. With the increasing focus on hydrogen as a clean fuel, it is vital that these challenges are addressed to ensure a reliable and trustworthy hydrogen economy. The unique properties of hydrogen create uncertainties about whether common measurement technologies (normally used for other types of fluid) can be used for hydrogen measurements. There are challenges related to flow measurement or measurement of impurities that arise from these distinct properties. Issues are also caused by complications in the required technologies for production, storage, transportation and consumption of hydrogen.

Ensuring accuracy

In this article, some of the main measurement challenges faced by the hydrogen industry will be discussed. One of the current challenges is ensuring accurate flow metering of hydrogen. Although a number of mature technologies for high accuracy flow measurement are available, these have generally been optimised for use with natural gas. The fluid properties of hydrogen are drastically different from natural gas and from air, which is sometimes used as a cost-effective calibration fluid. There are many ways in which this can impact measurement accuracy.

For example, ultrasonic flow meters are commonly used for the highest accuracy flow measurement applications. Hydrogen is the lightest element, with density that is eight times lower than natural gas, leading to a lower acoustic impedance and ultimately poorer signal quality for the

Mahdi Sadri, TÜV SÜD National Engineering Laboratory, UK, considers a range of measurement challenges for the hydrogen economy, and how these can be overcome.

flow meter. This results in increased errors and, in the worst case, the meter may fail to provide a measurement for this gas. Since the speed of sound in hydrogen is three times greater than natural gas, this also causes increased errors in the transit time measured for the ultrasound signal.

Another challenging property of hydrogen is its tendency to leak at a higher rate than other gases, due to its small molecule size and low viscosity. This is a concern for positive displacement meters, including diaphragm and rotary types. Even if the meter remains externally leak-tight, there is a possibility of internal leakage or flow that goes undetected by the counting mechanism.

These problems are not insurmountable. Manufacturers can adapt the design of their flow meter hardware and software to compensate for the properties of hydrogen or apply corrections to the measured value, but a sufficient amount of experimental data is required for such a purpose. This brings us to another challenge: the lack of testing and calibration facilities that can work with pure hydrogen.

Although interest in hydrogen as a clean fuel for the future is rapidly increasing, pure hydrogen has not been widely used in many industries in the past. This has limited the demand for testing and calibration facilities that are equipped to work with hydrogen. New facilities have been developed recently, or are planned to be developed, now that demand is increasing. However, it will take some time before these types of facilities are easily accessible as several challenges, such as dealing with health and safety regulations for a flammable and explosive gas that can easily leak or embrittle materials, can slow down the process.

Metering technologies

While there are still many challenges facing the accurate measurement of hydrogen flow in certain applications (such as large-scale transport pipelines for pure hydrogen), specific metering technologies have been proven to be effective for use in other hydrogen applications. An example of a metering technology that has been used successfully in hydrogen refuelling stations (HRS) for fuel cell electric vehicles (FCEV) is the Coriolis flow meter. This type of meter measures the mass flow rate of a fluid directly, rather than relying on volume or other indirect measures, making it well-suited for use in HRSs where hydrogen is sold based on its mass (unlike gasoline).

Not all flow measurement errors originate from the meter itself. HRSs fill FCEVs at pressures of up to 350 or 700 bar (depending on the type of vehicle), and normally pre-cool hydrogen to -40°C to prevent overheating of the hydrogen tank during the filling process. The dispenser hose (located downstream of the meter) must be vented after each use for safety reasons. This means that some of the pressurised hydrogen that is measured by the flow meter is not delivered to the customer. Therefore, a correction must be made for this vented hydrogen to avoid additional measurement errors.

Moreover, even after the hose is vented, some pressurised hydrogen may still be left in the piping between the hose and the meter, especially if the flow meter is located upstream of the pre-cooler. This is basically a ‘dead volume’ after the meter in the dispensing system. The trapped gas in this space that has been measured by the meter is not vented at the end of the refuelling process, but delivered to the next customer. Although each customer receives the hydrogen in the dead volume from the previous customer and leaves hydrogen in the same space for the next customer, these two amounts are not necessarily equal (i.e., customers may fill their vehicles to different pressures). This is another source of flow measurement error that does not originate from the meter itself. Therefore, corrections must be made to ensure that accurate billing is achieved.

In such cases where there are additional factors that are contributing to the measurement errors, other than the accuracy of the meter, the total measurement error of the entire system needs to be determined rather than that of the meter alone. Several field test standards have been developed globally for this purpose. TÜV SÜD National Engineering Laboratory has developed the only primary HRS field test standards in the UK at present. These standards can be taken to an HRS to test the facility’s dispensers.

Domestic meters

Another flow measurement challenge that must be addressed is hydrogen metering for heating houses. Several countries aim to decarbonise their gas grids by replacing natural gas with hydrogen or hydrogen-enriched natural gas. Accurate billing for the new fuel, however, remains crucial. A standard diaphragm gas flow meter (the most common type of domestic gas meter) may have accuracy problems with hydrogen since it can leak through materials and connections. Moreover, the energy content of natural gas is three times greater than hydrogen, requiring a physically larger meter. In many cases, this is not practical, as meters will have to fit into existing installations. Ultrasonic meters (another type of domestic gas meter) are also sensitive to various physical properties and potentially need to be modified for hydrogen applications, but they can accommodate higher flow rates without a need for larger physical dimensions. TÜV SÜD has developed a hydrogen testing facility to examine the performance of domestic meters. Without such facilities to confirm the accuracy of flow meters used for hydrogen, there may be a lack of market confidence in the use of hydrogen, slowing its integration into the gas grid. Accurate billing is critical for successful decarbonisation of the gas grid by using hydrogen.

Figure 1. Fuelling a hydrogen-powered car.

Tackling challenges

TÜV SÜD is also contributing to several research projects that are aiming to tackle challenges of hydrogen flow metering at national and international levels, along with other national measurement or designated institutes from around Europe, and leading companies in the hydrogen industry. These projects will answer many questions covering a range of metering applications for the entire supply chain of hydrogen.

Hydrogen measurement challenges are not limited to flow metering; there are also several difficulties associated with hydrogen purity measurements. Purity requirements of hydrogen as a fuel have been specified in a few standards such as ISO 14687 and SAE J2719. Accurate analysis of hydrogen purity is crucial for fuel cells as they are highly sensitive to impurities. As an example, impurities such as sulfur-containing compounds can act as catalyst poisons and severely affect fuel cell performance – even at low concentrations. A concentration at the scale of a few parts per billion (ppb) of hydrogen sulfide is capable of damaging the fuel cell of an FCEV. ISO 14687 specifies very small fraction specifications for some impurities in order to meet very high accuracy requirements. This creates analysis challenges, as there are a large number of impurity components – and some of them are unstable or reactive. The high number of components prevents analysis with a single method, while the reactivity of some of them increases the possibility of component adsorption to sample lines and equipment. These can create extra errors

in measurements or make them challenging and expensive to perform. There are only a limited number of laboratories that are capable of measuring all of the components specified in ISO 14687.

Standards and regulations

The lack of regulations and standards for hydrogen measurement (in some areas) is another challenge for the hydrogen economy. Development of relevant regulations will take some time, as several aspects – including technical capabilities of hydrogen measurement systems – should be considered. Currently, there is a patchwork of different standards and regulations in different countries, which can make it difficult to compare and verify measurements from different locations. National regulations on hydrogen measurements are vital for securing fair trade in a national market. In addition to that, international harmonised regulations can remove barriers to the development of a global hydrogen market. Without harmonised regulations and standards, it can be difficult for companies to navigate different national requirements and to ensure that their products and services are compliant. To address these challenges, there is a need for the development of internationally-recognised standards and regulations for hydrogen measurement, which can be adopted by governments, industry, and other stakeholders. This will help to promote consistency, transparency and confidence in hydrogen measurement, and support the growth of the hydrogen economy.

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For the hydrogen economy to grow, decisive action on investment and infrastructure is needed. Manish Patel, Air Products, explains.

Governments across the globe are united in a desire to manage the global energy crisis and decarbonise hard-to-abate sectors. To help solve this, hydrogen has become a major focus. We should all take comfort from the fact that the conversation has grown from how we make hydrogen to include how we move that hydrogen to sectors that need it. This article will primarily address how hydrogen is, and will in future be, moved.

PricewaterhouseCoopers has released analysis that forecasts significant hydrogen demand of between 150 – 500 million tpy by 2050, with the figure depending on factors such as global climate ambitions, direct electrification and the use of carbon capture technologies.1 If we are to meet our ambitious climate objectives, an important contribution must come from stimulating demand for clean transportation fuels.

There is universal recognition that we are facing an energy shortage, and that is especially true for renewable energy that is needed to meet climate objectives. The EU is addressing these shortages with plans including REPowerEU,

the European Green Deal, and the European Green Hydrogen Strategy, which are all setting targets for renewable hydrogen. In the UK, there is a commitment of up to 10 GW (5 GW each of blue and green) of renewable and low-carbon hydrogen production capacity by 2030. Meeting these targets means ensuring a reliable supply of green hydrogen when local renewables are unavailable; the challenge of sourcing is particularly felt in the transport sector because it is here where policies to encourage uptake of green hydrogen are furthest advanced. Transport is also a sector in which Air Products is playing a particularly prominent role, in its support of decarbonising heavy-duty fleets. The company recognises that, to create and maintain security of supply, it takes technology, capital, infrastructure, expertise and ambition.

Air Products’ joint venture (JV) project in Saudi Arabia with NEOM and ACWA Power is particularly exciting in this regard. It is based on 4 GW of renewable electricity capacity, from solar and wind sources. The energy generated will be stored in the form of renewable ammonia that will be transported

to terminals around the world – terminals which may include Immingham in the UK (in partnership with Associated British Ports) and Rotterdam in the Netherlands (in conjunction with Gunvor Petroleum). This is truly a step change: companies will be creating a new, global, renewable energy supply chain, moving renewable energy from where it is abundant and in excess to where it is needed.

These terminals will store the renewable ammonia that will be used as feedstock to produce hydrogen: domestic renewable hydrogen. This will complement and encourage production based on domestic renewable energy.

Hydrogen hubs are developing across the globe, in response 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, and the company’s plans to build the first large-scale, renewable energy import terminal in the UK, Germany and the Netherlands are such examples. Their locations offer strategic access to renewable ammonia from facilities such as NEOM, and could provide hydrogen to Germany, the UK and the Netherlands by 2026.

However, focusing on hydrogen production will not be enough. A key issue is how the refuelling infrastructure can be brought forward. Liquid hydrogen technology offers significant advantages in terms of reliability, footprint and scalability in contrast to gaseous technology which is currently more commonly offered. It is worth taking some time to address these points individually:

y The reliability needed to allow end users to invest with confidence can only be achieved by considering the entire supply chain. Renewable hydrogen production is hostage to the weather and to intermittency of offtake; this can be mitigated by investment in storage (either of hydrogen or the energy required for its production) and by casting the net wide to pull in sources of renewable energy from locations where the availability of renewable electricity, for example, is itself more dependable.

y Storage is not something that matters only at the point of production. At every step along the supply chain, there is an opportunity for – and a degree of requirement for – storage. To use the word again, experience tells us that operators of vehicle fleets may have limited space for storage of gaseous hydrogen; liquid hydrogen is much more space efficient.

y With scalability, it is not merely a matter of having more space for more storage; the advantages of liquid hydrogen over gaseous hydrogen have already been addressed. The practicalities of scale in supply of electricity to distributed vehicle filling/charging locations must also be considered. Whether that electricity will supply battery electric vehicles or distributed electrolysers, running the cables is a challenge that should not be underestimated.

Returning to the question of supply of sustainable energy to vehicle fleets, there has been significant progress in the hydrogen bus market. Air Products’ hydrogen bus refuelling stations in the municipality of Hürth in Germany, and for the Go-Ahead Group near Gatwick in the UK, are good examples. The latter represents the largest renewable bus deployment in the UK to date, and both use liquid hydrogen technology. There is a lot of pressure on transport operators to play their part in the transition. The risk is that haste could drive the adoption of quick-access, short-term solutions without adequate consideration of how those decisions will play out in the long-term as the market develops. This is why it is crucial to speak to experienced hydrogen specialists as early as possible – before vehicles are purchased, and before planning permission is sought. They can offer additional strategic

Figure 1. Computer-generated imagery (CGI) of Air Products’ renewable hydrogen production plant in Immingham – for illustrative purposes only.

Figure 2. Air Products is planning to build a renewable ammonia import terminal and associated green hydrogen production plant in Rotterdam.

Figure 3. Air Products' mobile hydrogen refuelling supporting a hydrogen bus trial in the Peak District National Park, England.

thinking about how best to decarbonise a fleet or build a refuelling station for the long-term.

In the transport sector, the measures that governments have taken to drive uptake have depended on demand-side interventions, in large part. To date, these interventions have largely arisen from government mandates for renewable hydrogen penetration in the transport sector, and are based around the EU’s Renewable Energy Directive and the UK’s Renewable Transport Fuels Obligation. Supply-side incentives are also under development in many European jurisdictions, and could make hydrogen a reality in new applications in many other sectors other than transport. Depending on jurisdiction, such incentives may be built on contracts for difference, variable premium models, fixed premium models, or similar. The challenge for policymakers is to create a portfolio of interventions and support that achieves the required objectives in a timely manner, but minimises market distortions.

Supply-side support is often associated with sectors other than transport, including industry in particular. The quantities of hydrogen required in such sectors far outstrip anything that can be provided by the downstream distribution infrastructure that is appropriate for transport – pipelines. Much thought is being given to the creation of extensive networks of large-diameter, open-access hydrogen pipelines, in part based on repurposed natural gas pipelines. These developments are inevitable, and will play an important role in bringing hydrogen to the market, but they cannot serve the entire market. There is a role for unregulated pipeline networks, generally of smaller capacities and carrying

hydrogen of purity that may differ from that expected in the open-access system. It is important that policy is developed to allow for the continued operation and growth of unregulated networks.

With the caveat that unregulated hydrogen pipelines may operate at purities that are customised to meet specific end users’ needs, the general principle is correct that, whatever the jurisdiction and the incentive mechanism, agreed and enforced standards for the hydrogen produced or delivered will be needed. It is also important that a level playing field is established to ensure that all sources of hydrogen, serving any market or seeking any form of government support, can benefit from the same levels of policy support. This should be the case whether the hydrogen is imported, produced domestically from imported energy (as is the case in Air Products’ renewable ammonia terminals), or produced from domestic energy.

Producing and distributing renewable and low-carbon hydrogen solutions for use in heavy-duty fuel cell vehicles, industrial applications and energy storage will help drive the energy transition. By minimising carbon emissions, reducing reliance on finite resources and allowing diversification of energy sources, the journey to hydrogen is underway. Across the globe, industries and governments are working together to build the production and distribution assets of the future.

Reference

1. ‘ The green hydrogen economy – predicted development of tomorrow’, PwC, https://www.pwc.com/gx/en/industries/energyutilities-resources/future-energy/green-hydrogen-cost.html

Louis Mann and Daniel Patrick, Atlas Copco Gas & Process, USA, and Mazdak Shokrian, Plug Power, USA, discuss how turboexpander cooling technology can support hydrogen liquefaction expansion.

With its low-carbon potential, demand for hydrogen is expected to grow substantially in the coming years. Concurrent to this, the demand for its efficient transportation will drive larger and more efficient hydrogen liquefiers and associated cryogenic machinery.

As this article will go on to discuss, there are many challenges associated with designing large-scale liquefiers, including the availability of pure hydrogen turboexpanders. Turboexpanders provide the cooling used for cryogenic processes such as liquefaction. Process design optimisation

may require several iterations to reduce the number of turboexpander stages while maintaining high machinery performance and low specific energy consumption.

Additionally, innovative aerodynamic and mechanical design features are required for pure hydrogen turboexpanders. Liquefier cycle design considerations also include turndown capability, ease of start-up, operation and reliability.

Demand and transportation

On the one hand, the environmental impact of fossil fuels is accelerating growth in the hydrogen market. On the other

hand, constraints in hydrogen supply are limiting the growth of the existing material handling markets as well as the adoption of hydrogen for new market applications.

There are various options for transporting hydrogen, including compressed gas tube trailers, liquefaction, gas pipelines, or chemical carriers. The economics behind how hydrogen is transported depend on the application and location. Compressing hydrogen in tube trailers, for example, is the most simple transportation method. However, this is only suitable for short distances and relatively small volume applications because of the limited energy density per load.

In contrast, liquefying hydrogen significantly increases its density (it is 800 times denser than gaseous hydrogen at atmospheric pressure), which allows for more hydrogen to be transported in a single trip and makes its cost per kilogram more economical for further distances.

Plug Power is building a network of hydrogen liquefaction plants across North America to provide 500 tpd of green liquid hydrogen by 2025, alleviating near-term hydrogen supply constraints and accelerating hydrogen technology adoption. The company’s existing and near-term hydrogen markets consist of material handling, light commercial vehicles,

heavy-duty vehicles, and stationary power. The 2025 target of 500 tpd of liquid hydrogen demand represents 5000 class 7 and 8 trucks, and less than 300 MW of stationary back-up power. By 2025, 500 tpd of liquefaction capacity will nearly double the total existing liquid hydrogen capacity in North America.

Hydrogen liquefaction process

An industrial-scale hydrogen liquefier cools a hydrogen feed gas stream in two main stages, precooling and liquefaction, producing saturated liquid hydrogen at -250˚C (-418˚F) at approximately 0.7 barg (10 psig).

The hydrogen feed gas stream is fed to the liquefier at 15 − 30 bar (217 – 435 psi), typically, and cooled with a purity of approximately 99.998 mole percent (less than 20 ppm of total impurities).

In the precooling step, the feed gas is cooled to an intermediate temperature using one or more refrigerants. Precooling allows for the use of less energy-intensive cycles with higher boiling point refrigerants, before introducing the more energy-intensive cryogenic refrigerants, such as helium or hydrogen, in the liquefaction step. Once the temperature is cold enough from precooling, the gas is sent to a cryogenic adsorption system to polish remaining impurities that could freeze up in liquefaction. The purity of feed gas flowing through the liquefaction heat exchangers is typically above 99.99999 mole percent.

The hydrogen gas is catalytically converted from normal hydrogen with 25% of para-hydrogen to a higher final fraction of around 95 – 98% as it is cooled to a final liquefaction temperature. Catalytic conversion is an exothermic process that can be conducted inside the heat exchangers, or in separate catalyst beds.

Hydrogen liquefaction processes are very energy-intensive. As such, a variety of process configurations for large-scale applications have been built or conceptually proposed, using different refrigerants and refrigeration cycles. Commercially-available technologies use liquid nitrogen,

gaseous nitrogen, helium or hydrogen as the refrigerants in both steps. Only a limited number of cryogenic refrigerants (such as helium, hydrogen, or their mixtures with neon) can be used in the final liquefaction cycle, because freezing will occur otherwise.

Industrial-scale liquefaction

In general, hydrogen liquefaction processes can be categorised by the type of precooling and by the type of cryogenic refrigeration cycle used. Brayton and Claude cycles use turbines or a combination of turbines and Joule-Thomson (JT) valves in their cycle for expanding the cold refrigerant.

Brayton and Claude cycles improve the overall energy efficiency of the process by using turboexpanders, as the near isentropic expansion provides lower temperature than the JT isenthalpic process alone. Additionally, if the turboexpander is paired with a compressor or generator, the expansion energy can be recovered. Turboexpanders are the heart of hydrogen liquefaction because their application significantly minimises the energy loss.

Energy efficiency and capital costs are the main key factors for commercially-viable hydrogen liquefiers at industrial-scales. While cycle improvement using a cryogenic refrigerant with a higher compression ratio instead of pure hydrogen has the highest potential for efficiency improvement, it is more of a long-term solution, as it requires investigation and pilot-scale experiments. For short-term and mid-term applications, improving Claude cycles using pure hydrogen is the most promising option for reducing Specific Energy Consumption (SEC) and Specific Liquefaction Cost (SLC) of industrial-scale liquefiers.

Currently, most liquefier designs are centred around smaller turbines, which limit the capacity and efficiency of these plants. The scale-up of liquefaction processes utilising hydrogen refrigerants necessitates turboexpander technology improvement. Fortunately, large-scale turboexpanders have been used extensively in hydrogen-rich cryogenic services for nearly half a century. These large machines can be modified for the deep cryogenic service that hydrogen liquefaction requires, and offer machinery economics that improve with scale.

Turboexpander design

Turboexpander design for hydrogen liquefiers is challenging due to the high isentropic enthalpy drop, low discharge volume, and deep cryogenic temperatures that are required. Liquefier process requirements produce unique aerodynamic and mechanical designs, including low flow turboexpander wheels, high peripheral speeds, and robust thermal management.

Practical challenges arise from hydrogen’s flammability and resistance to being contained by seals. Hermetic designs with no external shaft seals are often preferred in order to eliminate process loss and contain hazardous gas. Hermetic solutions require the submergence of rotor-bearing systems in the process fluid, making material compatibility and bearing lubrication a challenge. Oil-free solutions, such as active magnetic (see Figure 1) or gas bearings, ensure that no lubrication oil can enter the process.

Figure 1. Oil-free solutions, such as active magnetic or gas bearings, ensure that no lubrication oil can enter the process.

Historically, small turboexpanders in hydrogen liquefaction service have utilised energy dissipating technologies, where any power absorbed by the turboexpander is rejected in the form of heat, and not recovered. As liquefiers scale up in size, energy recovery-based turboexpander configurations become economically-viable and improve plant-specific energy consumption by adding free compression to the cycle, or by generating electricity.

Integrally-geared expander-generator arrangements (see Figure 2) allow for one or more turboexpander stages on a single train. This configuration is especially attractive when the cycle designs require several turboexpander stages. Compressor stages may also be added to the integrally-geared arrangement (referred to as a compander) where a motor drives the compressor stage(s) at reduced load due to the turboexpander energy recovery. Integral gearing demands external shaft sealing, which requires some loss of the refrigerant.

Benefits of scale

Machinery duty can scale up either by adding stages or by increasing machinery size. Configuring multiple units in series or parallel is a viable option that promotes

modularisation, while increasing the size of machinery offers many benefits as it pertains to plant SEC and SLC.

The turboexpander stands to benefit significantly from scalability, in terms of both cost and performance. Among the improvements are greater flexibility in energy recovery and rotor bearing configuration, enhanced thermal management and aerodynamics, and a more favourable cost structure due to economies of scale. Improvements in these areas have the potential to further optimise the turboexpander’s operation, increasing its overall reliability and efficiency, and contributing to improved plant SEC and SLC.

Liquefiers

Plug Process Systems has designed and is building several liquefier units using a proprietary technology with one of the market’s lowest SECs, lowest SLCs, and highest reliabilities. The company’s liquefaction utilises a gaseous nitrogen precooling cycle and gaseous hydrogen liquefaction cycle (see Figure 3). Utilising gaseous nitrogen for precooling instead of liquid nitrogen offers efficiency benefits and greater operational flexibility. Core precooling cycle components include a centrifugal nitrogen compressor, a perlite cold box with integrated brazed aluminium heat exchangers (BAHX), and two turboexpanders. The liquefaction refrigeration cycle includes a hydrogen reciprocating compressor, a vacuum cold box with integrated BAHX and flash vessel, and two turboexpanders.

The installation of larger-capacity hydrogen liquefiers not only lowers the specific capital cost, but also helps with the specific energy cost due to benefits of scale of state-of-the-art turbomachinery. These benefits of scale are currently being realised on Plug’s standard 15 tpd and 30 tpd hydrogen liquefiers, with further improvement expected on larger liquefier products that are in the engineering phase.

Conclusion

The demand for hydrogen will continue to grow as the world cuts carbon emissions. Liquid hydrogen remains an attractive solution for the transportation and storage of hydrogen at various scales.

The hydrogen liquefaction process has many opportunities for improvement as it grows in scale. A number of the quick advancements can be made in machinery optimisation, where larger machinery can leverage features and experience that are proven in other industries.

The liquefier cost analysis shows that optimisation of key machinery and equipment will improve both capital costs and specific energy consumption with increased plant scale.

While this article has suggested improvements for plants greater than 15 tpd, optimum hydrogen liquefier capacity remains a balance between CAPEX, OPEX, supply, demand, technology readiness, and tolerance for risk. Continued improvements in these areas will only further the economic viability of liquid hydrogen.

Figure 2. Integrally-geared expander-generator arrangements allow for one or more turboexpander stages on a single train.

Figure 3. Gaseous nitrogen precooling cycle, and gaseous hydrogen liquefaction cycle.

Marion Erdelen-Peppler, ROSEN Group, Germany, considers the issues surrounding the use of hydrogen in exisiting pipelines, and explains why ROSEN has decided to build a hydrogen test laboratory.

There are currently more than 4500 km of pipelines transporting hydrogen, and almost 1600 km of these are located in Europe. Most of these pipelines are dedicated hydrogen product lines that were designed and built to bring process gas hydrogen from gas producers to industrial users, such as chemical plants and refineries.

The plans for the European Hydrogen Backbone have a different focus; they are established around the vision of hydrogen as a source of energy. In this scenario, the quantities of hydrogen that are needed will be significantly larger than

they are today; the network will eventually be able to deliver the gas across the continent. This can be achieved by making use of the existing natural gas grid, adding dedicated new lines only where needed. However, because of the differences between hydrogen and natural gas, these plans for the future pose significantly different challenges to the system, mainly related to volume, pressure and, with this, maintaining pipeline integrity and safety.

For both new and repurposed pipelines, it is necessary to assess the relevant threats and define a strategy for integrity management. This understanding and assessment

encompasses a robust knowledge of material properties to form the basis of a ‘Fitness for Hydrogen’ assessment. Currently, the main standard that is used is ASME B31.121 , which provides a strategy for both new pipelines and the repurposing of existing lines to transport hydrogen.

Difficult hydrogen issues associated with steel pipelines

While hydrogen, being a gas, has many similarities with natural gas when it comes to transportation via pipelines, there is one notable effect that differentiates it from other

gases. This fundamental feature, which drives much of the integrity concerns and challenges associated with gaseous hydrogen pipelines, is the absorption of atomic hydrogen within the steel microstructure. Under certain conditions, it can diffuse into the steel and interact with the microstructure, leading to a change of the properties that are determined in air. There is a consensus that such interactions lead to a major degradation of ductility and fracture toughness, and an acceleration of fatigue crack growth. However, the material strength remains largely unaffected in the presence of hydrogen. These effects are

commonly referred to as hydrogen embrittlement. While the existing codes relate these effects to the steel grade, there are indications suggesting that the effects are in fact dominated by the steel microstructure and chemistry.2,3

If this is the case, it could be the source of an increased degree of scatter in the existing data when assessed only against the steel grade. In addition, the factor that describes the relationship between properties in air and in hydrogen could be different for vintage and modern material, as they tend to exhibit a different microstructure. These correlations need to be understood in order to deliver both practical and safe requirements to the industry.

As the need to fully understand steel performance in hydrogen grows, and the design requirements extend, it will become increasingly important to understand the influence of hydrogen on the integrity of new and existing pipelines in the context of mechanical properties as well as chemical composition and microstructure.

Hydrogen test laboratory

Consequently, ROSEN decided to build a hydrogen test lab to support the industry in its efforts to foster the energy transition. The lab is capable of delivering the full suite of fracture mechanics tests in a high-pressure hydrogen atmosphere. Standard fracture mechanic testing, such as J-R curves and fatigue crack growth rate (FCGR) testing in air

and under hydrogen gas load, can be performed to enable a comparison of the well-known effects and results in air with the ones from hydrogen testing.

Autoclaves are designed to perform standard KIH and exposure testing in a temperature range of between -20 and +200°C – a range which covers the main operational envelope for pipelines. The autoclaves are equipped with an automated gas mixing unit for the gases hydrogen (H2), methane (CH4), carbon dioxide (CO2), carbon monoxide (CO) and oxygen (O2) to enable flexible test gas mixture. There are plans to equip the tensile testing machine with a comparable device in the near future.

Additionally, standard mechanical testing in air (such as tensile, crack tip opening displacement [CTOD] and hardness), as well as metallographic examination, can be performed to complement fracture mechanical testing in hydrogen. This service portfolio not only enables ROSEN to deliver the results that are required by the dedicated standards to the customer, but also reaches beyond to generate more knowledge and understanding of the effects associated with hydrogen.

The competencies that ROSEN seeks to build include those related to the effect of the testing variables such as gas composition, hold times, test frequency and specimen geometry. Currently, there is a general understanding in the industry that, on the one hand, there is a lack of guidance in the testing standards – specifically in those details that are unique to the hydrogen test, e.g., load rate and frequency. On the other hand, some existing requirements are unrealistic to achieve in the usual test set-up, such as criteria on plastic deformation.

Collaboration within the industry is vital to develop the standards further, making results even more reliable while maintaining the practicality of the execution. Working beyond these necessary limits and promoting the understanding of the material performance and how it is linked to parameters such as age and microstructure will benefit the wider industry.

International collaborations and close exchange with the standardisation committees will help to ensure that any progress achieved is made available to all stakeholders in the industry.

With this new service, ROSEN will progress beyond today’s requirements, and will help to ensure a safe and reliable energy supply in the future.

References

1. ASME B31.12-2019 Hydrogen Piping and Pipelines, ASME Code for Pressure and Piping.

2. KOYAMA, M., ROHWERDER, M., CEM TASAN, C., BASHIR, A., AKIYAMA, E., TAKAI, K., RAABE, D., and TSUZAKI, K., 'Recent Progress in Microstructural Hydrogen Mapping in Steels, Quantification, Kinetic Analysis, and Multi-Scale Characterisation', Materials Science and Technology , Vol. 33, (2017), pp. 1481 - 1496.

3. HAYDEN, L.E. and STALHEIM, D., ‘ASME B31.12 Hydrogen Piping and Pipeline Code Design Rules and Their Interaction with Pipeline Materials Concerns’, ASME 2009 Pressure Vessels and Piping Conference.

Bibliography

• ASME BPVC.VXIII-3-2019 ASME Boiler and Pressure Vessel Code, Section VIII, Division 3-Alternative Rules for Construction of High Pressure Vessels.

• ISO 12135:2021: Metallic materials - Unified method of test for the determination of quasistatic fracture toughness.

Figure 1. The ROSEN Group has recently invested in building a dedicated hydrogen testing lab in Lingen, Germany.

Figure 2. Various material specimens can be tested at ROSEN’s hydrogen lab.

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Dr. Gunnar Stiesch, MAN Energy Solutions, Germany, assesses the key role that hydrogen will have to play in the maritime energy transition.

Climate change due to greenhouse gas (GHG) emissions is the greatest challenge that the global economy has to face. By replacing fossil fuels with renewable energy sources, electrical and mechanical power can be produced without contributing to global warming. Commitments and timetables to this end already exist, of which the most prominent is the Paris Agreement of 2015, forged at the COP21 Summit in Paris, France.

Transitions at sea

The shipping sector is a major source of GHG emissions. Ship owners and operators, as well as ship builders and marine equipment manufacturers, have embarked on their own very demanding programme of countermeasures, led by the International Maritime Organization (IMO). In early 2018, the IMO formulated its ‘Initial Strategy’ on decarbonisation, calling for total annual GHG emissions from international shipping to peak at the earliest date, and subsequently decrease to 50% of 2008 levels by 2050.

The exacting measures needed to attain the IMO goals are already under implementation and represent the first steps in a ‘maritime energy transition’ – a term coined by MAN Energy Solutions in 2016, and whose case it has championed since. With as many as 50% of all ocean-going ships powered by engines developed in Augsburg, Germany; and Copenhagen, Denmark, MAN Energy Solutions is a major stakeholder in the shipping sector and has an immense contribution to make towards GHG reduction.

Scale of the undertaking

According to statistics prepared by the International Chamber of Shipping, around 11 billion t of cargo are transported by ship annually. Moreover, up until 2050, the volume of world shipping is predicted to grow by up to 250%. Hence, the industry faces a dilemma over how to reduce GHG emissions while the volume of freight grows. With a 50% share of the marine-engine market, MAN Energy Solutions recognises its obligation to take decisive action.

Feasible alternatives and proven performers

In contrast with the vehicle sector, direct electrification with batteries as energy storage systems will only become applicable within the maritime industry in certain niches, for example in coastal shipping or for short-range ferries. As such, neither batteries nor fuel cells can provide the power output nor energy density necessary to meet the range and endurance that ocean-going vessels need – not to mention the required durability and robustness. Currently, large two- and four-stroke engines are irreplaceable in the majority of traditional marine propulsion and onboard power generation applications. Therefore, as its starting point, the maritime energy transition must look at ways to reduce or eliminate GHG emissions from these traditional maritime prime movers.

Accordingly, MAN Energy Solutions sees existing lower-carbon fuels and new decarbonised fuels – not radically different forms of propulsion power – as the solution to the GHG problem at sea.

The turn to gas – and beyond

The transition to lower-carbon fuels has already begun. Currently, a rising share of MAN Energy Solutions’ new order intake is for dual-fuel engines that burn LNG and produce some 20% less CO2/kWh than traditional diesel engines. As a result, the shipping industry will be in a position to have a rapid impact on GHG emissions while developing its products and strategies and building on the initial emissions reduction due to LNG.

MAN Energy Solutions’ attention has already turned to the fuels that will continue the marine engine decarbonisation process. Its strategy for the maritime energy transition calls for progressive, stepwise reductions in GHG emissions based on gaseous and liquid fuels burnt in fuel-flexible engines. Therefore, the engine solutions of the future will be largely powered by synthetic fuels made from green hydrogen derived from the electrolysis of water by renewable, regenerative electricity (the so-called ‘power-to-X’ process).

Fuel innovation – the route to further decarbonisation

MAN Energy Solutions has undertaken an evaluation of the fuels that could gradually replace LNG in a maritime energy transition. To arrive at its findings, the company compared the candidate fuels for the decarbonisation of shipping with heavy fuel oil (HFO) and marine gas oil (MGO), based on a number of important properties and constraints. These are, essentially, the factors that will dictate the viability as well as OPEX and CAPEX of the maritime energy transition. They encompass:

� Availability – in viable quantities, both globally and regionally.

� Carbon intensity – the amount of carbon emissions during combustion.

� Energy density – the main factor that governs the fuel reservoir/tank size needed to provide enough energy for a given voyage.

� Fuel boiling temperature – a yardstick for the refrigeration necessary to transform a gaseous fuel into its liquid state, for storage and transport.

� Projected production and handling costs of the fuels – the simpler the production processes and the easier the handling, the lower the fuel’s price.

� Costs aboard the ship for adapting the engine to burn the fuel and for storing and conditioning the fuel for combustion.

The ideal fuel is thus a viable compromise between these factors. The optimal low- or zero-carbon fuel may be application-specific, depending on vessel type and its operating profile, trading scheme and region. As such, shipping may have to prepare itself to burn a variety of fuels.

Figure 3. Marine fuels towards carbon-neutrality: alternative fuel options compared to carbon intensity, tank size and boiling temperature.

Figure 2. Multiple approaches to decarbonisation: a variety of strategies along with their GHG reduction potential, including the use of synthetic fuels with a potential of 80 – 100%.

Figure 1. In 2021, the 1036 TEU vessel ElbBLUE became the first container ship worldwide to use climate-neutral synthetic natural gas (SNG) produced from green hydrogen on a commercial trip.

Enter hydrogen

As a fuel, hydrogen is highly combustible and has the advantage that its combustion produces only water vapour, with zero carbon dioxide (CO2) or other GHG emissions. However, hydrogen has a number of properties that make it difficult to use as a fuel, including its low volumetric energy density and its very high flammability.

When processed to a liquid, hydrogen has an energy density that is 4.5 times lower than HFO or MGO. In addition, it requires cooling to -253°C for liquefaction, and occupies several times the volume of LNG. Moreover, the equipment required to hold the hydrogen in its liquid state is large and complex. As a result, in practice, a total installation space factor of 6 – 7 is required for complete hydrogen fuelling systems, compared to liquid fuel equipment.

Therefore, although there are proposals to use hydrogen as a fuel in certain ships – such as coastal and ferry traffic and, of course, hydrogen carriers – it is not considered suitable as a standard fuel for direct combustion in the piston-driven

engines of larger merchant ships. On the other hand, MAN Energy Solutions expects that green hydrogen – electrolysed from water using renewable electricity – will play a crucial role as a feedstock for the production of the synthetic gaseous fuels that will sustain the decarbonisation of the shipping sector after the initial period with LNG.

Among the interesting fuels that can be produced from green hydrogen are synthetic natural gas (SNG), ammonia and methanol.

Which fuel is the future?

The maritime energy transition has already begun, but requires time and political support. This transformation will continue to be market-driven over the next 10 – 15 years through a steadily increasing share of gas-powered engines in new shipbuilding, and through the retrofitting of the existing fleet. The necessary parallel and successive development of production capacities for climate-neutral synthetic fuels, on the other hand, can only be successful with political and regulatory support.

If this support is provided, green hydrogen will undoubtedly become the future foundation of a maritime energy transition − not so much as a fuel to power internal combustion engines, but primarily as a feedstock for the production of SNG, green ammonia, and methanol.

On the two-stroke side, green ammonia and methanol are set to play an increasing role. For its part, hydrogen for direct combustion will probably not play a great role on the two-stroke side, due to its energy density and the great distances covered by large ships, such as container, bulker and tanker vessels.

MAN Energy Solutions’ four-stroke view is that the immediate GHG gains will be derived from a transition to LNG, followed by SNG with continuously increasing blending, and that the market shares of these fuels will grow accordingly. At present, the extent of methanol and ammonia’s role in four-stroke powered ships is unclear, but the company is working on facilitating these fuels in its medium-speed engines. Direct combustion with hydrogen could also become an option for shipping in near-coastal regions.

As it cannot yet be predicted which fuels will win the race, current engine technology that has the flexibility to burn more than one fuel is required, giving marine engine users the security to invest in assets with effective lifespans of as long as 25 – 30 years. Moreover, under the term ‘fuel flexibility’, MAN Energy Solutions is referring not just to the availability of new engines designed for one or more of the new fuels, but also to engines already in service that can be readily adapted to burn new fuels as they become available, by retrofitting new fuel systems.

Figure 4. At a test centre in Dessau-Rosslau, Germany, MAN Energy Solutions explores several fuels to create the four-stroke engines of the future powered by hydrogen, ammonia and methanol.

Figure 5. The variety of hydrogen-based power-to-X fuels.

The world is still hungry for steel. In 2021 alone, the US consumed just under 100 million t of the metal. Used in industry and the transport sector such as in cars, trucks, aviation, rail and shipbuilding, steel is the most important construction and engineering material in modern societies. Also used in electricity power line towers, natural gas pipelines, machine tools and military weapons, it is difficult to imagine our modern world without it.

However, the production of iron and steel also creates the single biggest industrial carbon dioxide (CO2) footprint, recorded at 2.6 Gt/yr in 2020, according to the International Energy Agency (IEA).1 This exceeds the total emissions of road freight worldwide and accounts for 7% of global CO2 emissions, stacked at approximately 37.12 billion Gt/yr. Emissions of this scale are largely due to the vast quantities of coking coal required for steel production, needed to transform iron ore to steel via a chemical reaction. Because of this, the sector obtains 75% of its energy from coal, the dirtiest fossil fuel.

Demand for steel is only going up. Steel producers will need to halve their CO2

emissions from the steel-making process by 2030, rising to a 90% cut in emissions by 2040, in order to meet the obligations outlined in the Paris Agreement. The industry requires a more sustainable alternative, and green steel could pave the way towards decarbonising the sector.

What is green steel?

Green steel is steel that is manufactured without the use of fossil fuels. Whilst this may seem implausible at present, given the magnitude of emissions at stake coupled with steel’s centrality to modern life, innovative technologies are already being developed to help the industry on its way. Substituting coal with green hydrogen is a promising decarbonisation pathway. When water is split via electrolysis, hydrogen and oxygen are produced as separate elements. If the electrolyser used is powered by electricity that is produced from renewable energy sources, such as solar or wind, the hydrogen produced can be labelled green hydrogen. This is the cleanest form of hydrogen available as its production uses renewable energy and therefore does not produce carbon emissions as a byproduct.

Sundus Cordelia Ramli, Topsoe, Denmark, explains why green hydrogen could help to decarbonise the steel sector.

Rather than using coking coal as a heat source and catalyst to convert iron ore into steel, green hydrogen can be used to convert iron ore into sponge iron, which can then be processed to create green steel.

Massive undertaking means massive opportunity

Whilst the prospect of green steel is promising, the reality of implementing green hydrogen technologies on a sufficient scale is a daunting task.

At current price levels, replacing coal with hydrogen would drive up the price of steel by about a third. This gap will likely narrow in the coming years, and could disappear completely by 2030, as carbon emission pricing is set to drive up the cost associated with the use of coal, causing the price of renewable electricity to decrease. In the longer term, large-scale production of hydrogen will also result in efficiency gains, and optimisation of hydrogen-based steel-making processes will drive down the costs of this alternative.

However, decarbonising the steel industry hinges upon the logistical feasibility of producing green hydrogen at scale –something the industry is yet to figure out. Delivering green steel to a global audience would require a 20% increase in the production of renewable electricity, calling for an even more ambitious expansion of renewable energy production, going beyond the replacement of current fossil electricity generation.

However, a significant hindrance to green steel development is the global energy crisis. Due to electrolysis-related efficiency losses, hydrogen-powered steel production requires almost

three times the volume of electricity of traditional methods. Given the current climate, this makes the transition to green steel appear less palatable to businesses and world leaders.

A caveat to this aligns with a report by McKinsey & Co. that outlines that 14% of steel companies’ potential value is at risk if they are unable to decrease their environmental impact.² Whilst this is logistically challenging, it is crucial that leaders are not blinded by short-sightedness and realise the potential of investing in green technologies now, to reap the long-term benefits. Slowly but surely, the business, societal and environmental case for green steel is becoming clearer. It is now important to figure out how to deliver at scale.

What do we need to get there?

First, political willpower and commitment is required. There is now real momentum behind government policy changes that will deliver the regulatory frameworks to support the massive investment and build-out that is required. The US Inflation Reduction Act (IRA) is hugely ambitious, and there are also promising plans in the EU and beyond.

It is important to maintain momentum whilst steadily increasing our ambitions as the industry and technology matures. Greater collaboration across value chains to facilitate large-scale technological transformation is imperative. As offshore wind continues its rampant (and long overdue) expansion, there are also renewed efforts from players across the value chain to collaborate on building the infrastructure needed, whilst ensuring that expertise is available to facilitate the green hydrogen transition.

A prerequisite for the production of green hydrogen is the establishment of a steady – and massive – supply of electrolysers. The EU has set a target of 40 GW electrolyser capacity by 2030, resulting in an annual production of 10 million t of green hydrogen. Topsoe is constructing one of the world’s largest solid oxide electrolyser cells (SOEC) manufacturing facilities, with a capacity of 500 MW/yr and with the option to expand to 5 GW. The 23 000 m² facility will employ over 150 people and will reside on a land area of 72 000 m². The building will have a light superstructure and solar cells installed on the roof, significantly lowering its power consumption to approximately 13 MWh. Production of SOEC will take place at ground level via a fully-automated process consisting of robotic arms and autonomous mobile robots (AMRs) handling materials.

Still, on a global scale, much more capacity is needed to safeguard production of green hydrogen.

Finally, and perhaps most importantly, greater appreciation for the future societal benefits associated with the transition is required, not least the incredible opportunities for driving investment, jobs, energy independence, and seeing a direct impact on the fight against climate change.

Green hydrogen is key to the transformation and decarbonisation of the global industrial sector, and green steel has the capacity to be a major driver.

References

1. ‘Iron and Steel Technology Roadmap’, International Energy Agency, (October 2020), https://www.iea.org/reports/iron-and-steeltechnology-roadmap

2. HOFFMANN, C., VAN HOEY, M., and ZEUMER, B., ‘Decarbonization challenge for steel’, McKinsey & Co., (3 June 2020), https://www.mckinsey.com/industries/metals-and-mining/ourinsights/decarbonization-challenge-for-steel#/

Figure 2. Red-hot steel in a factory.

Figure 1. Digital mock-up of Topsoe’s SOEC manufacturing facility, currently under construction.

The premier source of technical and analytical information for the fertilizer sector

IDB to boost Chile’s green hydrogen industry

The Inter-American Development Bank (IDB) has approved a loan to support the development of the green hydrogen industry and its derivatives in Chile. This operation seeks to help decarbonise the economy and generate new opportunities for the country.

The resources will be used to finance new projects in the fields of green hydrogen; domestic demand development; human capital formation; creation of intermediate goods and services that facilitate the development of industry; applied research financing; development and technological innovation; and promotion of entrepreneurship in this sector.

According to the IEA, around 300 million t of hydrogen will be produced annually by 2050 – more than four times the current demand – and nearly half is expected to be in the form of green hydrogen, which is produced from renewable energies. Given Chile’s natural advantage of being capable of producing renewable energy at low cost, the growing global demand for green hydrogen presents a great opportunity in terms of both productivity and sustainability.

SGN partners with Oxford Flow

SGN has selected Oxford Flow to help prove the hydrogen-readiness of existing gas network infrastructure. The companies will work together as part of SGN’s LTS Futures project, which is verifying the compatibility of the UK’s local transmission system (LTS) with hydrogen gas.

Oxford Flow will provide innovative hydrogen-ready gas pressure regulators (IM-S), which are smaller and lighter than natural gas equivalents. They will be used to stress test decommissioned gas pipelines with 100% hydrogen. The regulators are designed to make the retrofitting of existing gas systems easier, and reduce future maintenance. The test results will inform the next stage of the LTS Futures project.

Gemma Simpson, SGN Director of LTS Futures, said: “The LTS Futures project will enable wide-scale system transformation of the UK gas network to hydrogen, driving decarbonisation and supporting our net zero goals. We are excited to be partnering with Oxford Flow to use this latest innovation as we transition to clean energy.”

Lhyfe and Capital Energy have signed a collaboration agreement for the joint development of offshore renewable hydrogen projects in Spain and Portugal.

Under the agreement, the two companies will work together to create hydrogen production sites at some of the offshore wind farm sites currently being developed by Capital Energy. The Spanish energy company already has a development pipeline of more than 7.5 GW in both countries.

For Lhyfe and Capital Energy, the joint installation of offshore wind farms and hydrogen production sites will offer significant economic and social benefits by way of the economies of scale that would be achieved, and the industrial overlap of the projects, given that a greater number and variety of suppliers and specialists would be required.

Such initiatives will also benefit the energy system as a whole, as the wind energy produced in these wind farms would be more

controllable, avoiding curtailments. Additionally, in some cases it would be possible to send less power to the grid (e.g., in case of congestion of the grid) and more to the hydrogen production unit, to which some of the wind turbines would be directly connected.

The signed collaboration agreement could be extended to other markets in the future.

Taia Kronborg, Chief Business Officer at Lhyfe, said: “This agreement with Capital Energy is a tremendous opportunity to foster the transition to clean energy through the large-scale production of green hydrogen at sea. Producing hydrogen via electrolysis at sea will maximise the immense potential of offshore wind energy. Countries with a coastline, such as Spain and Portugal, can drastically reduce their dependence on fossil fuels and improve their national energy security, while producing net zero emissions and boosting local economies.”

Lhyfe and Capital Energy team up to produce green hydrogen at sea

JERA’s gas turbine modifications to support hydrogen

JERA Co. Inc. has completed modifications of its gas turbine at the Linden Gas Thermal Power Station Unit 6 in the US, to enable the co-firing of natural gas with hydrogen-containing off gas generated at an adjacent oil refinery.

Because this process will require the procurement of hydrogen at an economically-rational price, and the development of carrier technology, it will be some time before hydrogen can be used for power generation in Japan. By working to resolve such issues and advancing the use of hydrogen at power plants in areas where hydrogen is already available, JERA seeks to accumulate technical capabilities and experience that can be applied to future power generation projects both at home and abroad. With the completion of this work, hydrogen co-firing of up to 40% (by volume) will be possible at Linden Unit 6. The effective use of hydrogen-containing off gas sourced from the adjacent oil refinery is expected to reduce carbon dioxide (CO2) emissions at both Unit 6 and the oil refinery. Under its ‘JERA Zero CO2 Emissions 2050’ objective, JERA has been working to eliminate CO2 emissions from its domestic and overseas businesses by 2050.

Study suggests feasibility of Gulf-to-Europe pipeline

RINA, the inspection, certification and consulting engineering multinational, and AFRY, a European leader in engineering, design, and advisory services, have undertaken an initial study of how the Gulf region and Europe could be linked directly with a pipeline to transport low-carbon hydrogen. The results indicate a transformative opportunity to fully unlock the Gulf’s immense potential as a cost-effective source of low-carbon hydrogen for Europe.

Initial assessment indicates the feasibility of a hydrogen pipeline connecting Qatar, Saudi Arabia, Egypt, and traversing the Mediterranean Sea to Europe. The analysis shows that a suitable pipeline configuration could transport 100 TWh or approximately 2.5 million tpy of hydrogen. Moreover, by constructing additional pipelines of the same nature, the transport capacity could be significantly scaled up.

The cost of transporting hydrogen through this pipeline is initially seen at approximately €1.2/kg of hydrogen.

In brief

Canada

Vortex Energy Corp. and partners have completed analysis of the previously announced 2D seismic interpretation on the Robinsons River Salt Project in Newfoundland, Canada. While doing so, at least two salt structures that could be suitable for hydrogen salt dome cavern development have been located.

France

AECOM has been appointed to oversee delivery of the expansion of The Chemours Co.’s green hydrogen production facility in the Villers-Saint Paul region of France. The expansion will allow Chemours to increase capacity and advance its NafionTM ion exchange materials platform – a key component for electrolysers that are used to produce green hydrogen.

Spain

Hydro has produced one of the world’s first successful batches of aluminium using green hydrogen as an energy source. The test is another step towards carbon-free aluminium. Carbon-free green hydrogen replaced natural gas as fuel for the recycling of aluminium during the test, which was conducted and led by hydrogen experts from Hydro Havrand at a casthouse in Hydro’s extrusion plant in Navarra, Spain.

TotalEnergies and VNG to decarbonise the Leuna refinery

TotalEnergies and VNG have signed an agreement to initiate the future supply of green hydrogen to the Leuna refinery, which is operated by TotalEnergies. Under the agreement, green hydrogen will be produced from renewable electricity using a 30 MW electrolyser in Bad Lauchstädt, Germany, built and operated by VNG with its partner, Uniper.

This agreement contributes to the decarbonisation of the Leuna refinery, and will reduce the site’s annual carbon dioxide (CO2) emissions by up to 80 000 t by 2030. Furthermore, the pipeline connection to the Bad Lauchstädt Energy Park will give the refinery access to future European hydrogen infrastructure and international markets.

“This project is fully in line with TotalEnergies’ ambition to decarbonise all hydrogen used in its European refineries by 2030. Our ambition is to replace the grey hydrogen with low-carbon hydrogen, representing a reduction of 3 million tpy of CO2 by 2030,” said Jean-Marc Durand, Senior Vice President, TotalEnergies Refining Base Chemicals Europe.

Hyphen Hydrogen Energy announces MoU

with key partners

Hyphen Hydrogen Energy has signed a Memorandum of Understanding (MoU) with the Government of the Republic of Namibia (GRN), Namibian Ports Authority (NamPort), NamPower, the Port of Rotterdam (PoR), Gasunie, and Invest International to create a partnership to drive the delivery of one of Sub-Saharan Africa’s largest fully vertically-integrated green hydrogen projects.

The investment will be held through SDG Namibia One, a bespoke blended financing infrastructure fund that will look to raise money from local institutional investors from around the world to develop Namibian green hydrogen projects and related infrastructure.

Marco Raffinetti, CEO of Hyphen, said: “The MoU we [have] signed, and GRN’s commitments to the green hydrogen industry, show that Namibia is moving at pace to establish itself as a leader in the global green hydrogen race. We are now focused on working with all partners to design the infrastructure and services needed in Namibia to meet the project’s timelines and meet Namibia’s development objectives.”

HDF Energy expedites the development of hydrogen power plants in the Philippines

HDF Energy has signed two Memoranda of Understanding (MoUs) during the 10th Philippines – France Joint Economic Committee (JEC) meeting held at the French Ministry of Foreign Affairs. These collaborations aim to expedite the development of Renewstable® multi-megawatt hydrogen power plants, which will provide stable, continuous and clean power to off-grid areas, around the clock.

As an island nation that is susceptible to the impacts of climate change, the Philippines faces challenges in providing stable electricity supply, with many regions relying on isolated grids powered by diesel fuel.

Renewstable presents a green alternative to conventional diesel fuel power plants by utilising solar or wind energy and water to generate electricity, thus mitigating greenhouse gas emissions and noise pollution. Its distinctive feature lies in its ability to provide baseload power by combining an intermittent renewable energy source with substantial onsite energy storage in the form of green hydrogen.

Wood and Centrica Storage explore the feasibility of a hydrogen production hub

Wood is working with Centrica Storage to evaluate the feasibility of transforming its Easington gas processing terminal in England into a low-carbon production hub. Centrica Storage has partnered with Equinor on this project to deliver hydrogen to the Humber region.

Based in East Yorkshire, the hub will be integrated with Centrica’s Rough field redevelopment, as well as the Easington terminal’s hydrogen fuel switching project, both of which Wood is executing parallel studies for.

The development of the Easington low-carbon hub over the next 10 years supports Centrica’s goal to achieve net zero by 2045. Hydrogen is a crucial element in achieving this target, as well as contributing to the UK’s net zero ambitions.

Wood will leverage its extensive experience in the hydrogen sector to evaluate development scenarios, including both green and blue hydrogen production facilities and their associated offsites and utilities.

IEA: Oman’s renewable hydrogen potential to offer a number of net zero benefits

Anew report from the International Energy Agency (IEA), presented to an Omani Minister, has underlined how rich renewable resources and vast land expanses could make Oman a competitive low-emissions hydrogen supplier by 2030.

Oman’s high-quality renewable energy resources and vast tracts of available land make it well placed to produce large quantities of low-emissions hydrogen. The hydrogen sector could attract investment to diversify and expand the country’s export revenues while reducing its natural gas consumption and emissions, according to the report.

Oman aims to produce at least 1 million tpy of renewable hydrogen by 2030 – up to 3.75 million t by 2040, and up to 8.5 million t by 2050, which would be greater than the total hydrogen demand in Europe today. The 2040 hydrogen target would represent 80% of Oman’s current LNG exports in energy-equivalent terms, and achieving the 2050 target would almost double them.