Global Hydrogen Review - Spring 2022

Spring 2022

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Spring 2022

03 Comment 04 Realising the hydrogen ambition

42 The decarbonisation of transportation

Caroline Stancell, Air Products, Europe, asks how the transport sector can grow its use of hydrogen, and what barriers are preventing it from going to the next level?

Prof. Juergen Peterseim and Dario Galvan, PwC Germany, detail how to turn the hydrogen debate into tangible market growth.

48 Perfecting pipelines

10 The hydrogen transition

Ollie Burkinshaw, Neil Gallon and Jason Edwards, ROSEN UK, address the challenge of integrity management of hydrogen pipelines.

Matt Pitcher and Narik Basmajian, Technip Energies, explore why hydrogen can play an increasingly expansive and important role in the decarbonisation journey to 2050 and beyond, as a carbon-free source of energy.

52 Reaching new heights

Joost Meeuwissen, Calderys, the Netherlands, describes how pre-cast, pre-fired catalyst support domes are setting new standards when it comes to long-lasting durability.

19 An inside look at blue hydrogen

Using key insights from the first wave of blue hydrogen projects, Pavan Chilukuri, Shell Catalysts & Technologies, the Netherlands, discusses the current status of blue hydrogen, and its role within the ongoing energy transition.

57 Creative combustion

Gilles Theis, Ali Gueniche, Christoph Strupp and Chuck Baukal, John Zink Hamworthy Combustion, A Koch Engineered Solutions Company, detail how radiant wall burner technology can combat the issues associated with introducing hydrogen fuels into combustion systems.

26 A nexus of clean energy

Bob Oesterreich and Peter Gerstl, Chart Industries, discuss how cryogenic technology is helping to shape the energy transition.

32 Hydrogen for all

62 Tackling challenges head on

38 Embracing the simulation challenge

67 Q&A with...

Marie-Laure Gelin, Howden, the Netherlands, explores the challenges associated with scaling up the use of hydrogen in support of the energy transition, and details a number of projects in which the company’s compression technologies were used.

There is currently a shortfall of hydrogen available for traditional industrial uses. David Wolff, Nel Hydrogen, USA, explains why, and explores options for ensuring security of supply.

Bharat Naik and Phil Millette, Honeywell Process Solutions, discuss how simulation could drive value across the hydrogen market.

Global Hydrogen Review sat down with Fabrice Billard, CEO, Burckhardt Compression, to get his thoughts on a range of topics.

69 All-weather filtration

Eric M. Rud, Eaton, USA, explains why reliable lube oil filtration is an important consideration in the production of hydrogen at very low temperatures, and details a project that the company completed under sub-zero conditions.

This month's front cover “Chart is proud to work alongside others advancing hydrogen for a low carbon, sustainable energy future” – Jill Evanko, President & CEO, Chart Industries At the cornerstone of Chart Industries’ business is a broad portfolio of complementary products. The integration of these products to deliver highly engineered solutions across the liquid gas supply chain makes the company unique.

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Copyright© Palladian Publications Ltd 2022. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

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.

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Editorial/advertisment offices: Palladian Publications 15 South Street, Farnham, Surrey GU9 7QU, UK Tel: +44 (0) 1252 718 999 www.globalhydrogenreview.com

elcome to the inaugural issue of Global Hydrogen Review – our brand new publication dedicated to the entire spectrum of hydrogen production and its applications worldwide.

Hydrogen is rapidly emerging as a viable and important piece of the global energy transition strategy. In the last year, a number of governments have released their hydrogen strategies, with many more currently drafting their plans. According to the International Energy Agency (IEA), those countries that have hydrogen strategies in place have committed at least US$37 billion to the development and deployment of hydrogen technologies, and the private sector has announced additional investment of US$300 billion.

Although estimated hydrogen demand figures to 2050 vary (see our keynote article from PwC, starting on p. 4, for more on this), it’s clear that significantly more investment is required to support the anticipated growth of the sector. In its recent ‘Hydrogen strategic planning outlook’, Wood Mackenzie estimates that developers will need to invest around US$600 billion to support supply growth by 2050. And the IEA believes that US$1200 billion of investment will be required between now and 2030 in order to put the hydrogen sector on a path that is consistent with global net zero emissions by 2050.

The hydrogen sector is quickly moving into the mainstream. In a recent survey of over 1000 senior energy professionals, DNV found that 84% of respondents believe that hydrogen has the potential to be a major component of a global, low-carbon energy system. In its report, DNV concluded: “In short, the world is heading for hydrogen, but the route is uncertain and many questions remain.”

Global Hydrogen Review’s mission is to answer those questions and provide a pathway to advance the sector. Each issue will feature quality keynote articles, detailed case studies, and technical papers examining the innovative technology and solutions that will help to drive the sector forward. Knowledge sharing is at the heart of our philosophy. So, if you have a story to tell, or feedback on this inaugural issue, please get in touch using the contact information on the left of this page.

We have also launched an accompanying website, which is full of the latest industry news and technical insights (www.globalhydrogenreview.com). And we’re delighted to announce that our first virtual ‘Global Hydrogen Conference’ will take place in November. You can reserve your free seat at the show now (turn to p. 47 for more information).

Palladian Publications is lucky to have a portfolio of leading titles across the entire energy sector (from upstream to downstream, and coal to renewables), and we have been overwhelmed by the positive response that we have received from the industry since announcing the launch of Global Hydrogen Review. We’d like to thank everyone for their kind words, and extend a special thank you to all of our contributing authors and advertisers for their support. We hope you enjoy this issue of the magazine, and that you find its contents useful to your work.

If you would like to receive a regular copy of Global Hydrogen Review, please sign up for a free subscription by visiting www.globalhydrogenreview.com/magazine (or by scanning/clicking the QR code on the right).

4

Prof. Juergen Peterseim and Dario Galvan, PwC Germany, detail how to turn the hydrogen debate into tangible market growth.

T

o achieve the Paris Agreement’s goal of limiting global warming to 1.5°C, a significant global acceleration towards the decarbonisation of economic activities is clearly required. A net zero pathway can only be achieved by adopting a range of sector-specific and cross-sector technologies. In applying these technologies, energy efficiency is the overarching selection criterion in order to decarbonise each energy end use.

For some applications, the most efficient pathway to achieve net zero emissions is by direct electrification, as in the case of private and public transport. However, in hard-to-abate sectors such as the chemical, cement and steel industries, or niches such as heavy transportation vehicles, the use of low-carbon hydrogen will play a key role. It is estimated that 50% of the total energy mix for the energy transition will be provided by green hydrogen molecules. The main advantage of hydrogen is its versatility, as it can be used directly as feedstock, or transformed into green fuels, gases, or chemicals.

Hydrogen demand development

Hydrogen demand is expected to experience steady growth until 2030, and should then accelerate significantly as hydrogen transport infrastructure is made available and more ambitious climate change policies take hold, spurring greater hydrogen market development. The following three hydrogen demand trajectories can be distinguished, as illustrated in Figure 1: � A low ambition trajectory overcoming the 2.3°C global warming level. � A medium ambition trajectory resulting in global warming levels between 1.8 – 2.3°C. � A high ambition trajectory of under 1.8°C global warming, which would align with the Paris Agreement targets.

The estimated hydrogen demand figures for 2050 vary significantly, ranging from 150 to 600 million t. The wide range of hydrogen demand estimates results from the differing underlying assumptions regarding the technologies used, e.g. the continued use of natural gas, efficiency improvements, direct electrification, or carbon capture and storage (CCS). The less ambitious scenarios only see a small and almost linear growth in hydrogen demand, with the continued use of natural gas, and estimate that it will vary between 150 – 200 million t in 2050. The scenarios with medium climate ambitions identify a range between 160 – 490 million t by 2050; scenarios for higher ambition climate goals estimate demand to range between 200 – 600 million t by 2050. The latter takes into

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account higher hydrogen demand in the hard-to-abate sectors, such as steel or chemicals, substituting current grey hydrogen and new demand generated by new applications and/or products.

It is necessary to emphasise that only the ambitious hydrogen demand scenario will enable the achievement of the Paris Agreement goals. As such, efforts should be directed towards immediately providing the suitable conditions for the acceleration of the hydrogen market ramp-up. The development of a ‘hydrogen economy’ is still in its early stages. However, the number of countries publishing hydrogen strategies has increased considerably, demonstrating broadening global interest and support.

To date, 26 countries and the EU have published national hydrogen strategies, with 13 published in 2021 alone. A further 22 countries are currently drafting hydrogen strategies, a number of which should be published in 2022. This reflects a clear acceleration of government interest that is potentially backed by COP26 agreements, which act as a catalyst (see Figure 2).

Hydrogen trade development

The hydrogen market will pass through various development phases, characterised by stakeholder involvement, transportation infrastructure development, spatial expansion levels, and its international trade (see Figure 3).

During the initial ramp-up period, there will be ‘hydrogen islands’. Initially, hydrogen will be produced in local projects close to the demand site in order to facilitate technology testing and avoid extra transport costs. These projects will be the result of joint development ventures and industrial parks in which stakeholders combine their hydrogen-related business activities. These islands will have the capacity to meet annual demand of up to 110 TWh if production capacity is built up by 5 GW, targeted in the national strategy by 2030.

An example of a hydrogen island is the project ‘HYBRIT’, in which the Swedish steel producer Figure 1. Range of hydrogen demand assessment by 2050 (source: World Energy Council).

SSAB, mining company LKAB, and energy provider Vattenfall will cooperate to bring into operation a fossil-free steelmaking plant located in Lulea, Sweden. The pilot plant will produce sponge iron, a crucial ingredient for the steel-making process, while carrying out tests between 2020 – 2024 to determine which production processes are the most efficient. The project aims to introduce the first fossil-free steel to the market by 2026.

In the medium-term, a second development trade phase will continue, characterised by hydrogen production in hubs progressing in regional hydrogen markets, accelerating growth in volumes. The hydrogen island will converge towards an integrated EU-wide transportation network.

Hydrogen hubs, or clusters of Figure 2. Overview of countries’ activities towards developing a hydrogen strategy large-scale demand, are local (source: PwC). areas where various existing

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Spring 2022

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conversion process, using renewable hydrogen as feedstock. The targeted market includes customers from power generation, shipping, fertilizer, and mining explosives. Renewable electricity will be provided from photovoltaic (PV) panels backed up with a battery storage system, enabling the plant to operate without being connected to the main electrical grid. In the first phase, the project will produce up to 625 t of renewable hydrogen by using a 10 MW electrolyser to produce 3700 tpy of renewable ammonia.

In case efforts to achieve climate goals set promising conditions towards a more ambitious target, the hydrogen trade development may continue with the establishment of a liquid market, based on a physical logistic network for moving higher volumes of hydrogen. The scope of this market will depend on the structure of the transportation network and the regulatory framework.

In the long-term, from 2050 onwards, the potential for the development of an Figure 3. Development of the low-carbon hydrogen market (source: PwC). intercontinental hydrogen market will depend on the economics of hydrogen shipping. This and potential hydrogen users from differing sectors are international trade will be driven by the significant difference co-located. The co-location within hubs can render developing in hydrogen production cost in various territories around the infrastructure (such as pipelines, storage and refuelling globe. However, transportation economics need to be added stations) more cost-effective by promoting economies of scale into the equation, with significant cost differences between and synergies from the sector to help develop the value chain. pipeline and seaborne transport.

These strategies consider different approaches to identifying, locating and funding potential clusters. Key variables affecting the potential hub site choice include access With the urgency to mitigate climate change, actions to to demand; land availability; import or production potential support the energy transition must be taken immediately. via port, road, and rail infrastructure; access to existing gas As discussed in this article, hard-to-decarbonise sectors transmission network; and favourable local economic, social will require the use of low-carbon hydrogen in industrial and environmental factors (such as suitable skilled workforce). processes that cannot be directly electrified. In addition to In several countries, the industry is leading efforts to form this, its global market development is necessary to guarantee clusters for cross-sector collaboration to develop the value cost-competitive hydrogen volumes to supply an ambitious chain and enable scaling up. Beyond industry, academic and demand scenario compatible with the 1.8°C of global warming research institutes are also seeking to co-locate at potential expressed in the Paris Agreement. hub locations. Two concrete pilot projects reflecting how hubs However, the development of a hydrogen economy may operate in a regional dimension have already started their will require a timeframe in which each stage of its market construction phase, and will focus on the refinery and fertilizer development will take approximately one decade. This sector. lengthy timeframe is due to the time and capital-intensive The Refhyne project operates Europe’s largest proton establishment of hydrogen projects, as well as the necessity exchange membrane (PEM) electrolyser (10 MW) at the for the development of a suitable transport infrastructure that Shell Rhineland Refinery in Wesseling, Germany, producing will go hand-in-hand with the increased demand for hydrogen. approximately 1300 tpy of hydrogen. The plant is operated Current hydrogen projects that are under construction by the oil company, Shell. The project aims to validate the and in operation are almost exclusively at pre-commercial business model of decarbonising refinery processes by using phase and have limited electrolyser capacities. Transport low-carbon electrolytic hydrogen as a replacement for the infrastructure will enable local hydrogen projects to grow hydrogen supplied by steam methane reforming (SMR). In into hubs, expanding to regional and later global markets. addition to this, the plant will explore applications in other Nevertheless, putting in place the infrastructure for large-scale sectors including industry, power generation, heating for hydrogen use can take up to a decade to plan, permit and buildings, and transport. build. Therefore, the 2020s will be decisive in creating a A second example is a project established by the fertilizer suitable framework, in which hydrogen niches will emerge for producer Yara Pilbara, and the energy provider ENGIE. The its long-term integration into our energy system, serving for project is located in Western Australia, and by 2023 it will the decarbonisation of greenhouse gas intensive economic start producing green ammonia through the Haber-Bosch sectors.

Conclusion

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H

ydrogen is the most fundamental yet abundant material imaginable, comprising three quarters of the universe. Two of these little proton-electron pairings join to reach a stable (di)atomic state, thus the familiar ‘H2’. It fuels the stars and it may fuel a low-carbon future.

Hydrogen is essential to ‘difficult-to-decarbonise’ segments of energy, transportation and industry. It will play an increasingly expansive and important role in the decarbonisation journey to 2050 and beyond. Hydrogen is energy at its most basic, carbon-free.

Case for action

Referring to Figure 1, at present, approximately 50 billion tpy of CO2 equivalent (CO2e) is emitted globally.

Around 35 billion tpy is direct CO2 emissions, and the remainder is CO2e emissions from other greenhouse gases (GHG) such as methane (CH4).1 The good news is that compared to 2010 projections, the course has been steered away from a 4 – 5°C temperature rise scenario, and we currently sit on a 3°C trajectory per current policies. If present-day pledges and targets are met, the curve will shift down towards 2.4°C. However, there is some way to go to meet the objective of the Paris Agreement – to limit the rise to well below 2°C. As the most fundamental carbon-free energetic molecule, hydrogen has an important role to play in this journey.

Some of the most prominent environmental challenges – acid rain, particulate emissions, and ozone depletion – have been successfully confronted. Now, it is necessary to pragmatically plot the decarbonisation journey in terms of goals and milestones, budgets,

10

incentives, funding mechanisms, legislation, taxation policies, and so on.

Why hydrogen?

Hydrogen meets the need for carbon-free energy in industry, transportation, power generation and domestic use, either directly or via production of hydrogen-derived energy carriers. It is the most fundamental chemical building block, and is essential for renewable and circular fuel production. On this basis, the global hydrogen market is anticipated to grow with a strong trajectory towards 2050. While the refining and fertilizer market are the two primary hydrogen customers today, it is anticipated that hydrogen will address mainly new markets by 2050.

It is predicted that the coming decade will be dominated by projects focused on positioning low-carbon hydrogen as an impactful mechanism to decarbonise energy systems and industry. The low-carbon hydrogen market share will increase as carbon capture and storage (CCS) projects develop, electrolyser technology matures, carbon taxation has a heightened impact on investment decisions, renewable and low-carbon electricity capacity expands, and power supply costs decrease.

How ‘low-carbon’ is your hydrogen?

The carbon intensity target is often somewhat arbitrarily defined as a percentage of CO2 reduction. Today, a popular target is 95%. Often, the percentage focuses on a relative Scope 1 direct emissions reduction, and fails to consider any Scope 2 indirect emissions trade-off, especially from directly-connected outside battery limits (OSBL) energetic systems such as air separation units and compressors.

Matt Pitcher and Narik Basmajian, Technip Energies, explore why hydrogen can play an increasingly expansive and important role in the decarbonisation journey to 2050 and beyond, as a carbon-free source of energy.

11

It is certainly feasible to outsource key energetic supplies and their respective direct emissions, but moving the problem elsewhere, and shifting Scope 1 to Scope 2 emissions, can often increase overall GHG intensity.

In general, while evaluating emissions trade-offs, it is important to consider both direct and indirect carbon emissions – Scope 1 being direct carbon emissions, Scope 2 being emissions caused by all energy needed to sustain the process, and Scope 3 covering the remaining life cycle contributors, including product end use.

As relativistic definitions fail to flesh out the value of upfront carbon avoidance, other efficiency-centric parameters, and many indirect effects, there is a prevailing logic that carbon intensity targets should focus on absolute inside battery limits (ISBL) and OSBL end results.

The EU recently defined a low-carbon hydrogen ‘CertifHy’ certificate ceiling of 36 g CO2e/MJ hydrogen lower heating value (LHV). This equates to 4.37 kg CO2/kg H2 allowable emissions, inclusive of upstream CO2 emissions (well-to-gate basis).

‘Without CCS well-to-gate emissions’ is also mentioned, which is assumed to enable the exclusion of some OSBL downstream emissions from the calculation. The CO2 gate condition will need clarification, as CO2 compression is not a negligible power consumer (causing indirect CO2 emissions).

In addition to this, 72% capture is mentioned as the steam methane reforming (SMR) target for natural gas feed, however the degree of carbon avoidance is not mentioned. Nevertheless, CertifHy will set an absolute Scope 1 and 2 emissions ceiling of approximately 2.5 kg CO2/kg H2, which appears realistic for kickstarting a hydrogen economy.2

Grey hydrogen

Although SMR’s middle name is methane, hydrogen is commonly produced from a range of paraffinic/naphthenic fossil resources such as natural gas, refinery off gas, propane, butane and naphtha. For simplicity, this section of the article focuses on methane feed and the SMR process.

Alternative oxidative catalytic or non-catalytic technologies, such as autothermal reforming (ATR) and partial oxidation (POx),

Figure 1. Annual global greenhouse gas emissions.

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are less common as they are less selective to hydrogen and more selective to carbon monoxide (CO).

CH4 + H2O ↔ CO + 3H2 + CO + H2O ↔ CO2 + H2 = CH4 + 2H2O ↔ CO2 + 4H2

SMR water-gas shift combined reaction

Each molecule of methane feed produces four molecules of hydrogen product, on the basis of 100% feedstock conversion.

Converting to weight basis, the process baseline carbon intensity is then 5.5 kg CO2/kg H2.

The SMR reaction is strongly endothermic, equilibrium limited, and the reactant steam must be raised from feedwater.

Accordingly, it can then be derived that the absolute minimum carbon intensity for CH4-based hydrogen production is 7.2 kg CO2/kg H2. By comparison, the value is 8.8 kg/kg for butane-based feed.

Any incremental steam production beyond basic reactant steam demand adds incremental CO2 footprint. This increment is often ascribed to the hydrogen production itself – a debatable practice, as the steam export is at once a useful energy carrier and a variable-rate co-product. Export steam at the typical pressure level adds roughly 0.15 kg CO2/kg steam-specific carbon intensity, meaning: yy A ‘high steam’ plant, producing approximately 20 kg export steam/kg H2, then adds 3 kg CO2/kg H2 carbon intensity. yy A ‘low steam’ plant, producing around 5 kg export steam/kg H2, adds 0.75 kg CO2/kg H2 carbon intensity.

Altogether, the carbon intensity practically ranges from 9 to 12 kg CO2/kg H2 for grey hydrogen plants, and the range depends on quality of feed, export steam rate, and process efficiency.

Blue hydrogen

First, it may be advantageous in many cases to forego the option of export steam to minimise baseline carbon intensity.

Some further process optimisations are useful here, such as pre-reforming, high-conversion reforming, and deep CO shift, and a drop towards 8 kg CO2/kg H2 is typical for CH4 feed.

Next, the addition of a carbon capture unit (see the green blocks in Figure 2) on the reformed and shifted gas enables CO2 capture down to 2 – 4 kg/kg in a ‘basic blue’ scenario, and ultimately to well under 1 kg/kg. Within the realm of technical feasibility, Scope 1 direct emissions can be reduced by more than 99%, close to zero,

meaning that Scope 2 and 3 then begin to dominate the overall footprint.

It must be noted that a single point of high-pressure carbon capture may be maintained, and integrated CO2 capture from the process gas is the most technically-mature, proven and affordable strategy, yielding the lowest levelised cost of carbon capture.

This technique has been utilised in hydrogen/syngas plants for decades, and Technip Energies has over 50 references for this application.

Alternative capture technologies are developing, such as capture from CO2-rich tail gas and post-combustion capture, each with some inherent advantages and disadvantages. However, CO2 capture at the point of highest partial pressure is generally the point of lowest capital and energy burden.

Although blue hydrogen would appear to be a very new topic, there are in fact a number of blue hydrogen plants operating worldwide today. Many of these are ‘HyCO’ units, which co-produce CO as product, and are relevant examples of carbon capture and utilisation (CCU). Others produce CO2 as a chemical co-product, and a few are based on CCS, whereby CO2 is captured and diverted underground.

Some might argue that blue hydrogen plants only play an intermediate role in the energy transition as a step towards green.

However, designing for feed flexibility enables future adaptation towards renewable feedstock (e.g. biogas), which, in combination with CCU/S, yields a carbon negative footprint.

existing hydrogen/syngas plants can be retrofitted for carbon avoidance, capture and use, where the anticipated investment and permitting burdens are significantly lower than complete greenfield replacement projects.

Before pressure swing adsorption (PSA)-based hydrogen purification became the gold standard, hydrogen plants included solvent-based CO2 absorption systems, which released captured CO2 to the atmosphere. The retrofit of such units with CO2 compression and product conditioning is low-hanging fruit.

For newer, PSA-based hydrogen facilities, adding a cost and energy-efficient carbon capture unit (pre-shutdown) significantly reduces carbon intensity while fostering competitive economics for the captured CO2. Carbon tax exposure is minimised, and asset life cycle extended further into the future. Straightforward process-side capture can reduce carbon intensity down to 2 – 4 kg CO2/kg H2, i.e. carbon intensity comparable to water electrolysis from photovoltaics.

Process intensification can be so impactful as to substantially shift the carbon burden from the combustion system into the high-pressure process, and enable final Scope 1 carbon intensity well under 1 kg CO2/kg H2. Heat recuperation technologies such as the Technip Parallel Reformer (TPR®) and Enhanced Annular Reactor Tubes for Hydrogen (EARTH®) are essential to competitive blue hydrogen layouts, and are

Decarbonising existing hydrogen plants All technologies available to reduce carbon intensity are relevant to both greenfield and brownfield: the brownfield upgrade potential should not be overlooked. Many

Figure 2. Basic low-carbon ‘blue hydrogen’ block flow scheme.

Figure 3. Technologies for the recuperation of high-grade process heat.

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Figure 4. The building blocks for low cost, ultra-low-carbon hydrogen for greenfield projects and brownfield retrofits. discussed in detail in the ‘Recuperative reforming’ section of this article.

Post-combustion capture

At the time of writing, it is generally observed that post-combustion capture is more capital and energy intense than pre-combustion capture. However, for brownfield applications where suitable free area is available, post-combustion capture facilities may be constructed pre-shutdown, and only require the diversion of flue gas to the new add-on capture block. A key advantage of post-combustion capture is that it allows the existing process to remain essentially unchanged, i.e. no major change in fuel Wobbe Index/LHV, flue gas mass flow, flame characteristics, and NOx.

Recuperative reforming

Hydrogen plants can be fitted or retrofitted with innovative heat integration options such as TPR® and EARTH® (Figure 3), which reduce process energy intensity by recuperating high-grade heat back into the reforming reactions.

The TPR® is a proprietary technology that has been referenced for over two decades, with 15 references so far. It is a gas-to-gas tubular reactor, exchanging high-grade heat from a primary (or secondary) reformer effluent with inflowing reactants over the reforming catalyst.

This technique moves valuable energy from the waste heat boiler system back into the process. This also reduces primary reforming burden, both increasing hydrocarbon and energy utilisation, and reducing carbon intensity. It is also a useful tool for debottlenecking existing hydrogen units by up to +30% capacity.

In 2019, the EARTH® technology was fully realised with the help of Clariant. It is a proprietary annular, heat-exchanged reformer tube, employing a special catalyst, with a similar objective and effect to TPR®. With one facility in operation for over three years, and several projects in execution, EARTH® is rapidly gaining market traction.

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Recuperative reforming options should be carefully evaluated in conjunction with the steam balance in the complex, as a reduced steam output and carbon intensity from the hydrogen plant may knock-on to an increased steam production and carbon intensity elsewhere in the complex.

New technologies for deeply decarbonised hydrogen

‘Deep blue’ hydrogen facilities can be based on the traditional SMR process, oxygen-based technologies such as ATR, or even hybridised technologies. Via appropriate build-up of the process layout and conditions, direct Scope 1 carbon intensities far below 1 kg CO2/kg H2 are achievable.

BlueH2 by T.ENTM provides deep decarbonisation by reshaping proven and reliable hydrogen technology bricks (Figure 4), all from within a reference portfolio of around 60 years. Direct carbon intensities to 0.1 kg CO2/kg H2 and below can then be achieved, economically. At the same time, both electric power demand and Scope 2 indirect emissions are minimised. By maximising hydrocarbon utilisation, and minimising carbon content in the hydrogen product, Scope 3 indirect emissions are likewise minimised.

BlueH2 by T.ENTM is a platform of solutions optimised to each individual application. There are multiple ‘right schemes’ depending on size, application, economics, etc. The absolute guiding principles are: yy No single process can optimally serve all applications. yy To date, there has been a lot of literature steering the industry toward ATR for blue hydrogen. The arguments behind this are narrow and incomplete. yy The assumption that an SMR requires post-combustion capture is incorrect. yy The assumption that upstream (Scope 3) methane emissions negate any benefit of carbon mitigation in a blue hydrogen plant is widely refuted. yy Ultimately, the three key performance indicators (KPIs) that matter most are levelised cost of hydrogen (LCOH),

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100% green to 100% fossil), based on life cycle analysis (LCA). Carbon intensity of various forms of electric Blue H2 by T.ENTM power supply can be evaluated using the Intergovernmental Panel No on Climate Change benchmark data Yes (IPCC 2014 A.III.2). Nevertheless, where CCU/S is simply not feasible, < 0.1 green hydrogen merits priority consideration.

Production of hydrogen via 1.3 electrolysis is a good way to transform renewable power for storage, use, 1.5 or long-distance transportation. It is also good for peak shaving excess production, as an intermittency or 1.3 opportunity measure. Conversely, electrolysis based on unmitigated fossil power generation (coal, gas) should be strictly avoided, as this nets a higher carbon intensity than grey hydrogen. Both direct and indirect carbon emissions must be considered for any process trade-off, e.g. for any electrification option.

As we climb the electrolyser learning curve, and cross each hurdle to large- and wide-scale adoption of water electrolysis, Technip Energies is focused on positioning fully-renewable, clean hydrogen in the current and future energy landscape, on the basis of its extensive background in hydrogen technology, seamless project execution capabilities, and established presence in the hydrogen market. The company has delivered optimised electrolyser plant design concepts to the market, and is currently executing a bio-based hydrogen project.

Table 1. An exemplary, normalised case comparison of the main hydrogen

production options and their KPIs (CO2 emissions tax not applied) KPI

Grey (baseline)

Zero steam (TPR®/EARTH®)

Basic blue process

Steam export?

Yes

No

No

Carbon capture?

No

No

Yes

Carbon footprint

1

0.8

0.2 – 0.4

Investment burden

1

1.1

1.2

Levelised cost of hydrogen (LCOH)

1

1

1.2

Plot area

1

1

1.2

e.g. US$/kg net present value basis; levelised cost of carbon avoidance (LCOCA), e.g. US$/kg CO2 net present value basis; and overall specific carbon footprint of hydrogen production: kg CO2/kg H2, Scope 1, 2 and 3.

CAPEX, OPEX, efficiency, specific energy and other parameters are certainly of interest, but are all contained in the above KPIs. An exemplary side-by-side comparison is shown in Table 1, whereby carbon capture OPEX was calculated but carbon emissions not expressly taxed (closer to current than future framework).

Compared to grey baseline, when there is no profit nor loss from co-produced export steam, and LCOH is dominated by OPEX (large capacity, high gas price), ‘zero steam’ can be achieved without impact on LCOH. In the ‘basic blue process’, carbon capture helps to reduce carbon intensity by 70 – 80% from the original baseline, and even further when process parameters and configuration are optimised for low carbon monoxide and methane slip to the final produced syngas. The required carbon capture facility will result in increased capital investment, operational cost and plot area, all order of 20%.

Deep capture with BlueH2 by T.ENTM reduces carbon intensity by 90 – 99% from the given baseline. This comes at a small investment premium, and the LCOH is mainly impacted by the incremental CO2 capture and transportation costs.

It is anticipated that with increasing carbon taxation and lower cost for electric power, the LCOH for the various blue technologies will decrease, and deep capture will ultimately become the industry gold standard. It is likewise expected that the cost of hydrogen produced via electrolysis will drop significantly over the coming 10 – 20 years and will come closer to blue hydrogen production costs.

Green hydrogen

Green (renewable) hydrogen is delivered via water electrolysis derived from renewable power supply, or via reforming of bio-sourced feedstock. The specific energy demand of electrolysis is roughly five times higher than SMR, due to the high energy required to split water. The carbon intensity of hydrogen produced via electrolysis directly depends on the carbon intensity of the associated electric power supply, and can be anywhere from 0.6 to 45 kg CO2/kg H2 (dependent on the power source –

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Low-carbon hydrogen to decarbonise industry

In addition to cutting the carbon intensity of today’s traditional hydrogen applications, e.g. refining and ammonia, blue and green hydrogen solutions further enable the decarbonisation of a wide range of industries, such as steel, cement, power, olefins and LNG. Some examples are as follows:

Power Since the 1980s, hydrogen and syngas plants have incorporated ISBL power co-generation facilities, on the basis of both steam and gas turbine power cycles. Power integration with hydrogen exploits certain heat power synergies, and today presents the opportunity to simultaneously decarbonise both, particularly via the opportunity to add low-carbon hydrogen into the power production fuel supply. The carbon intensity of such ‘blue power production’ depends on cycle configuration and hardware constraints, however > 50% reduction in carbon intensity of power is easily achieved. This and other KPIs will continue to improve as gas turbine capabilities are adapted and optimised for high-hydrogen fuel capability and efficiency.

↔

Petrochemicals The primary source of CO2 emissions in olefins plants is cracking furnaces. Methane-containing tail gas (from the ISBL recovery section) is traditionally fired at the furnaces. For new and retrofit applications, cracker tail gas (and any make-up fuel) may easily

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be converted to hydrogen-rich fuel upstream of the cracking furnaces. In such situations, the hydrogen plant takes on the role of ‘fuel conversion unit’, or even ‘carbon trap’. Carbon intensity of such ‘blue olefins units’ is easily reduced by 80%, or more if electricity supply is also low-carbon (e.g. if power generation is clubbed into hydrogen generation as described above).

Refining Refineries are today’s major hydrogen customers, traditionally for clean fuels and bottom of the barrel upgrading. Upgrading existing infrastructure to ‘blue’ performance reduces the refinery-wide carbon footprint by approximately 30%, depending on refinery complexity. Further measures, such as positioning blue hydrogen as a centralised carbon trap in the refinery fuel systems, reduce refinery Scope 1 carbon intensity by > 50%.

Conclusion

The energy transition mandates durable long-term solutions for reducing GHG emissions by addressing future energy needs in terms of generation, storage and utilisation. Deeply decarbonised, cost-effective hydrogen production solutions are already accessible today at industrial-scale, for both newly-built plants and for retrofits of existing units. New-build blue hydrogen units easily achieve deeply-reduced carbon footprints, and KPIs that are competitive with electrolysis. Brownfield retrofit of existing hydrogen plants into blue plants is not only feasible, but is a particularly cost-effective carbon reduction measure.

Technip Energies’ BlueH2 by T.ENTM portfolio of blue hydrogen solutions reaches very-low-carbon footprint via efficiency and carbon avoidance measures, combined with efficient

carbon capture from the process. Carbon intensity down to 0.1 kg CO2/kg H2 (approximately 99% reduction) is affordably reached. Post-combustion capture, whilst generally the most capital and energy intense option, can remain attractive in certain brownfield applications.

The specific energy demand of electrolysis is much higher than blue hydrogen, and its carbon intensity directly depends on the source of electric power supply. Production of hydrogen via electrolysis remains a good way to transform green electric power for storage or use, transportation over long distances, or to peak shave renewable energy farms as an intermittency or opportunity measure.

Both direct and indirect carbon emissions must be considered for any process trade-off, particularly any electrification option.

Where possible, blue hydrogen facilities aiming at a carbon intensity of 0.1 – 4.4 kg CO2/kg H2 result in competitive LCOH, and lowest cost of CO2 emissions avoidance. As low-carbon power supply becomes more prevalent and affordable, and electrolysis progresses up its ‘learning curve’, blue and green hydrogen production are anticipated to become tandem solutions, with both significantly contributing to a low-carbon future.

Reference

1. RITCHIE, H., and ROSER, M., ‘CO2 and Greenhouse Gas Emissions’, Our World in Data, (May 2017), https://ourworldindata.org/co2-andother-greenhouse-gas-emissions 2. BARTH, F. et al, ‘Towards a Dual Hydrogen Certification System for Guarantees of Origin and for the Certification of Renewable Hydrogen in Transport and for Heating & Cooling’, CertifHy, (July 2019), https:// www.fch.europa.eu/sites/default/files/documents/280120_Final_ Report_CertifHy_publishing%20approved_publishing%20%28ID%20 7924419%29%20%28ID%207929219%29.pdf

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2021

Using key insights from the first wave of blue hydrogen projects, Pavan Chilukuri, Shell Catalysts & Technologies, the Netherlands, discusses the current status of blue hydrogen, and its role within the ongoing energy transition.

T

he International Energy Agency (IEA) has urged governments and companies to “seize the opportunity” presented by hydrogen as momentum behind this clean-burning fuel reaches unprecedented levels. More than 35 governments have, or are working towards, national hydrogen strategies, which reflects the potential for low-carbon hydrogen to significantly reduce carbon dioxide (CO2) emissions while contributing to energy security.

By 2050, low-carbon hydrogen is forecast to supply as much as 10% of all final energy consumption around the world.¹ However, most current hydrogen production processes emit large quantities of CO2. That being said, hydrogen production does not have to be carbon intensive – a fact that is growing in importance as demand for low and zero-carbon hydrogen intensifies.

In 2020, Shell launched the Shell Blue Hydrogen Process (SBHP) which enables hydrogen to be produced from a

variety of fossil fuel and renewable feedstocks with an almost 100% carbon capture rate, and offers many advantages over conventional hydrogen production and carbon capture technologies. 18 months on, the organisation has learned a great deal from the first wave of blue hydrogen projects.

This article will share what Shell has discovered to help advance this fast-moving and growing decarbonisation solution. The organisation has gleaned insights from more than 50 projects around the world to determine where the blue hydrogen market sits today, and how its technology can further advance low-carbon hydrogen production.

The hydrogen market

Demand for hydrogen is accelerating, driven by stronger national-level commitments to decarbonise energy systems, and by industrial actors seeking to align themselves with increasingly strict greenhouse gas (GHG) emission regulations.

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Today, the IEA estimates that the annual demand for hydrogen is approximately 90 million t; by 2030, this figure is forecast to reach around 200 million t, and over 500 million t by 2050.

Meeting this demand will require an unparalleled transformation of how hydrogen is produced. Currently, most hydrogen is grey, and produced by converting natural gas into hydrogen and unabated CO2 by the steam methane reforming (SMR) process. However, this process is carbon intensive and is, according to the IEA, responsible for as much as 900 million tpy of CO2 emissions.² As such, the energy industry cannot simply expand current grey hydrogen production if it is serious about achieving deep decarbonisation. Instead, it must

rapidly transition to cleaner methods of hydrogen production, such as green and blue hydrogen (or even pink, purple, red, turquoise or yellow hydrogen – a full spectrum of hydrogen technologies that warrants an article of its own).

The latest insights from the Hydrogen Council show that the number of announced hydrogen projects rose by almost 60% in 1H21 to 359 large-scale projects worldwide – a 450% increase since the end of 2019. A global investment of US$500 billion has already been committed to low-carbon (blue) and zero-carbon (green) hydrogen projects through to 2030; this figure is set to rise as demand for cleaner hydrogen grows. Although Europe accounts for 80% of new projects, China is a rapidly emerging market with more than 50 announced new projects.

With these investments, green and blue hydrogen production capacity is set to exceed 10 million tpy by 2030: 70% of the installed capacity will be green and 30% will be blue.³ This is, however, far below the demand forecast for 2030, which leaves a considerable need for further projects and investments. That said, there are still uncertainties surrounding the relative growth of green and blue hydrogen production throughout the next decade, but hydrogen production costs will clearly be a big influence.

The role of blue hydrogen

Figure 1. Hydrogen production costs in 2030.

Blue hydrogen is similar to grey hydrogen except that the CO2 is captured and either utilised or stored underground.

Although the amount of CO2 captured varies according to the project, blue hydrogen is widely regarded as low carbon. Green hydrogen is carbon free and is seen, in many situations, as the ideal solution to satisfy future hydrogen demand. So, why do we need blue hydrogen?

The reality is that most green hydrogen is currently much more expensive to produce than blue hydrogen. In fact, by 2030, forecasts indicate that green hydrogen may still be

Figure 2. The SBHP and the advantages of integration with other technologies.

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Figure 3. Comparison of the different shades of blue hydrogen technology. that blue hydrogen has a vital role to play in the energy transition.

Blue hydrogen will also play an important role in Shell becoming a net-zero-energy business by 2050 – a transition that requires reductions in both its own GHG emissions (Scope 1 and Scope 2) and those of its customers (Scope 3). Establishing a strong hydrogen market in preparation for the widespread introduction of green hydrogen will be key.

Which shade of blue hydrogen technology?

Figure 4. Location of the blue hydrogen projects studied. double the price of blue hydrogen (see Figure 1) and that cost parity will not occur until about 2040. This will not be the case everywhere; in some regions, particularly those with already-developed renewable energy infrastructure, green hydrogen may already have the advantage. Where this is not the case, blue hydrogen has a key role to play.

To meet the growing demand for hydrogen and renewable power, blue hydrogen can provide an interim solution that can help to establish the hydrogen market while still lowering carbon emissions. Some, however, have queried the impact of blue hydrogen on the environment, as demonstrated in a recent paper by Cornell and Stanford Universities.⁴ However, this report is based on global assumptions that generate general conclusions, so should be treated with caution. A project-specific, case-by-case analysis of blue hydrogen projects will generate very different results, and Shell remains confident

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Blue hydrogen comes in different ‘shades’ according to the technology used. Until recently, project developers usually had the choice of two established blue hydrogen technologies: SMR or autothermal reforming (ATR). Now, there is a third option – one with the potential to provide superior cost and CO2 capture performance.

Shell’s SBHP is a new way to produce blue hydrogen from natural gas and other fossil-based and biomass feedstocks – one that integrates proven proprietary and third-party technologies in an end-to-end line-up (see Figure 2). The process is an oxygen-based, non-catalytic system that utilises the organisation’s proven Shell Gasification Process technology, based on gas partial oxidation, to manufacture syngas, combined with Shell ADIP ULTRA pre-combustion CO2 capture technology.

When compared with conventional SMR and ATR technologies (see Figure 3), the SBHP has four key advantages.

First, for large-scale projects (200+ tpd), oxygen-based systems such as the SBHP and ATR have a significant cost advantage over SMR systems. Moreover, the SBHP provides a potential levelised cost of hydrogen advantage – 25% lower than both SMR and ATR.

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Second, the SBHP can capture as much as 99% of the CO2 from high-pressure, single-source, pre-combustion gas streams, which makes it the preferred choice for greenfield applications that require high capture rates.

Third, unlike ATR, the SBHP is non-catalytic, so does not require expensive gas pretreatment and can utilise multiple feedstocks, including natural gas, fuel gas, bottom of the barrel hydrocarbons, and renewable biomass.

Lastly, the SBHP produces high-pressure steam from waste process heat, which can be used in the carbon monoxide (CO) shift unit, or to supplement power demand, thereby increasing facility efficiency.

Blue hydrogen insights

Since launching the SBHP as an alternative to SMR and ATR in 2020, Shell has gained important insights into the status of the global blue hydrogen landscape.

Most of the projects that the organisation has been involved with have been in Europe (including the CIS) and North America,

with growing interest in Asia and the Middle East (see Figure 4).

From these projects, Shell has defined four project archetypes that describe the key, current applications for blue hydrogen (see Figure 5). The SBHP has several important advantages for these projects when compared with SMR and ATR.

Blue hydrogen and the oil, chemicals and gas industries

Conventionally, a refinery uses fuel gas or natural gas combined with post-combustion carbon capture technology to produce lower-carbon products. Post-combustion gases are, however, low pressure, must be captured from multiple locations, and typically have lower CO2 concentrations, thereby making carbon capture less efficient and more expensive.

Instead, companies are now looking to use conventional feedstocks in a centralised production facility to produce hydrogen that can be used to power furnaces and gas turbines, as well as directly in conversion processes.

The advantage of this is that CO2 can be captured from high-pressure, pre-combustion gases from a single location, which is cheaper and can help to reduce Scope 1 emissions.

The SBHP has the advantage for this strategy because it: yy Can capture CO2 from high-pressure, pre-combustion gas streams. yy Can produce medium-pressure CO2 streams for easier transportation and storage. yy Offers greater feed flexibility, including fuel gas, natural gas, biomass, and bottom of the barrel refinery products.

Blue hydrogen and the natural gas industry

Many natural gas exporters are looking to use their natural gas as a feedstock for blue ammonia, which is an ideal hydrogen carrier and provides a more efficient way of exporting hydrogen molecules to market. This strategy is particularly suited to locations where local natural gas production exceeds the local demand.

In this scenario, the SBHP has the advantage because it: yy Can leverage high-pressure natural gas feeds and deliver high-pressure hydrogen that reduces the compression costs for ammonia production. � Is an oxygen-based technology, which means that the nitrogen produced by air separation during hydrogen production can be used to produce the blue ammonia. � Can capture as much as 99% of the CO2 emitted during hydrogen production, thereby lowering the carbon intensity of the ammonia and downstream products.

Blue hydrogen and the power industry

Figure 5. Top: the four blue hydrogen projects identified. Bottom: how the SBHP integrates with the four project archetypes.

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Blue hydrogen demand from the power sector is currently relatively small.

However, Shell expects large growth in this area as utility companies continue to seek lower-carbon solutions for power production. Consequently, companies

Figure 6. Three key roles that the SBHP can play in future-proofing industrial clusters. are looking at blue hydrogen as an alternative to coal or natural gas.

The benefits of the SBHP for the power industry include: yy The ability to produce hydrogen and capture CO2 at higher pressures and at the larger scales required to result in a lower levelised cost of hydrogen and electricity compared with SMR and ATR. yy Improved power plant efficiency through the production and integration of valuable high-pressure steam into the power plant steam system.

Blue hydrogen and consortiums of industries

Industrial clusters, or hubs, are becoming an increasingly important concept as heavy industrial emitters look to develop collective, cost-effective decarbonisation pathways. For example, rather than each emitter developing its own blue hydrogen solution, clusters will develop a single, centralised hydrogen production unit that plugs into every facility.

The SBHP is well suited to this application for the following reasons: yy The partial oxidation process on which it is based is proven on a large-scale, which reduces the project risks when substantial quantities of hydrogen are needed. yy Its feed flexibility enables alternative feedstocks to be used, including waste gas generated by cluster partners. yy It can leverage high-pressure gas feeds and deliver high-pressure hydrogen and CO2, which reduces the compression costs for transportation. yy Its technology offers high process efficiency at high carbon capture rates that reduce the amount of CO2 produced per unit molecule of hydrogen. It also enables emitters to capture more CO2 at a lower cost.

Future-proofing industrial clusters

The SBHP can play three key roles in future-proofing blue hydrogen facilities (see Figure 6). First, it can help companies to remain aligned with increasingly strict carbon capture regulations. Currently, many projects require 90% carbon capture rates; however, in the near future, policymakers are expected to increase this requirement to 95%, and potentially more. Indeed, most of the new projects that Shell has been seeing are mandating capture rates of at least 95%.

Second, Shell’s technology provides the option for clusters to manufacture and export blue ammonia, thereby extending project life should the cluster switch to using green hydrogen.

And finally, the feed flexibility of the SBHP means that the natural gas feed can be replaced with a renewable feedstock such as biogas to create renewable (not green) hydrogen that is carbon negative.

Blue hydrogen and beyond

Shell is not just a technology provider and licensor; it is also a facility owner and operator with a commitment to reducing its impact on the climate. As such, it understands the challenges and concerns of plant owners and operators around the world. The hydrogen value chain is complex; however, Shell is well-positioned to play a leading role not only in supplying technology, but also in market and infrastructure development, and establishing robust supply chains and distribution networks.

The organisation is currently involved in and evaluating a number of hydrogen projects and solutions, both blue and green. A key part of this process is asking the right questions: what hydrogen capacity is needed? What is the quality of the feedstock? Does the facility need the flexibility to produce both hydrogen and ammonia to meet current and future market demands?

It may be several decades before zero-carbon, green hydrogen alone can meet demand. Nevertheless, Shell’s insights demonstrate that its blue hydrogen technology is ready to provide a cleaner and more cost-effective alternative to carbon-intensive grey hydrogen.

References

1. ‘The future of hydrogen: Seizing today’s opportunities’, IEA, (2019), https://iea.blob.core.windows.net/assets/9e3a3493-b9a6-4b7db499-7ca48e357561/The_Future_of_Hydrogen.pdf 2. ‘IEA Global Hydrogen Review 2021’, IEA, (2021), https://iea. blob.core.windows.net/assets/5bd46d7b-906a-4429-abdae9c507a62341/GlobalHydrogenReview2021.pdf 3. ‘Hydrogen Insights: A perspective on hydrogen investment, market development and cost competitiveness’, Hydrogen Council, (February 2021), https://hydrogencouncil.com/wp-content/ uploads/2021/02/Hydrogen-Insights-2021-Report.pdf 4. HOWARTH, R.W., and JACOBSON, M.Z., ‘How green is blue hydrogen?’, Energy Science & Engineering, Vol. 9, No. 10, (2021), pp. 1676 – 1687.

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Bob Oesterreich and Peter Gerstl, Chart Industries, discuss how cryogenic technology is helping to shape the energy transition.

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P

roducing more energy while accelerating efforts to reduce greenhouse gas (GHG) emissions and increasing energy independence is one of the world’s biggest challenges – technologically, politically and economically. This article will discuss how cryogenic technology is helping to shape the energy transition through a nexus of clean energy, comprising LNG, liquid hydrogen, and carbon capture.

As the cleanest burning fossil fuel, natural gas is often touted as the bridging fuel to net zero. It has increased its share of the global energy mix to almost 25%, predominantly through the displacement of coal. According to data from the International Energy Agency (IEA), natural gas emits between 45 – 55% fewer GHG emissions than coal when used to generate electricity and, between 2010 – 2018, switching from coal to natural gas-fired power generation prevented 500 million t of carbon dioxide (CO2) emissions from ending up in the atmosphere.¹ Natural gas is also proven in industrial processes; is oftentimes a ‘quick fix’ solution for reducing emissions due to existing infrastructure; and is similarly proven as a transportation fuel for heavy goods vehicles and marine vessels. Further to this, it is a stable support for renewable sources, providing supplementary power generation during peak loading, and when the sun does not shine or the wind does not blow hard enough.

Hydrogen is taking centre stage in many energy roadmaps. With advancements in fuel cell stack technologies and continued cost reductions, hydrogen can be used as an energy carrier to fulfil several roles in the energy sector. With its ability to store renewable power, produce electricity, and power light and heavy-duty vehicles with zero tailpipe emissions, hydrogen has the capacity to be a global energy source at scale.

Traditionally, carbon capture and storage (CCS) has been used as a process to capture CO2 emissions from power generation and industrial processes that burn fossil fuels, compressing the gas and transporting it to areas where it can be injected deep underground.

This method is therefore an important step in the decarbonisation of hydrogen that is produced from steam methane reforming (SMR) of natural gas, and coal gasification, which still dominate the energy mix. Blue hydrogen is the term applied to the hydrogen produced following the decarbonisation of grey and brown/black hydrogen.

Carbon capture, utilisation and storage (CCUS) is a further step change in the evolution of carbon capture where, instead of being securely stored as a waste product, CO2 is recognised as a valuable commodity and recycled for uses in many industries such as cement, brewing, and food processing.

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Natural gas liquefaction

Natural gas is liquefied through cryogenic processing, reducing its volume to 1/600th of its gaseous equivalent. This makes it easy to transport and store. Until relatively recently, natural gas was predominantly liquefied in ever-larger baseload facilities, and transported across oceans in huge tankers before being landed and regasified for pipeline transmission at similarly large-scale import terminals. The only real exception to this rule are the much smaller peak shavers, which, as the name suggests, were deployed during periods of high load.

However, by adapting and refining this small-scale liquefaction approach, a technically-feasible and commercially-viable solution for production and distribution of much smaller volumes of LNG revolutionised the landscape, bringing power to off-grid locations and providing an alternative transport fuel for trucks, ships, and even railway locomotives.

The key to the success of small-scale LNG is bringing gas to the market quickly, as well as simple plant operation. As a result, instead of a bespoke, custom design every time, a major feature is a range of standard, repeatable-design liquefaction plants. This significantly reduces the project

timescale and delivers lower CAPEX. Small-scale cryogenic liquefaction plant sizes typically range from 15 000 gal./d (25 tpd) through to 450 000 gal./d (720 tpd), where the larger plants (50 000+ gal./d) are predominantly aimed at liquefaction of pipeline gas for virtual pipeline solutions, and plants below 50 000 gal./d are often applied to liquefaction of waste methane to produce liquified biogas (LBG). As with their much larger counterparts, there is also a choice of liquefaction technologies through mixed refrigerant processes, as well as the Reverse Brayton Nitrogen Cycle.

Modular mid-scale LNG

The concept of modular mid-scale LNG is best demonstrated by the liquefaction plants that export large quantities of North American shale gas. Instead of a single, large, custom-built facility, total plant capacity is achieved through a series of replicable modules. For example, a plant with a total liquefaction capacity of 12 million tpy could be achieved through six identical 2 million tpy modules or 12 identical 1 million tpy modules. By using proven, standard equipment packages, maximising shop build and minimising onsite construction, the chief advantages of the modular approach are: � Reduced overall project timescale. � Lower risk profile. � Modules that can be brought online and operated independently for earlier revenue recognition. � The ability to respond more quickly to demand fluctuations.

Small-scale LNG regasification

Figure 1. A small-scale LNG liquefaction plant in Pennsylvania, US, produces LNG for the local merchant market.

The concept of trucking liquid fuel to areas or facilities not connected to a pipeline grid is familiar to many through diesel, heavy fuel oil (HFO) and other distillates. Small-scale LNG regasification essentially uses the same model. The only difference is that the liquid fuel being transported is natural gas. A regasification station, also referred to as an LNG satellite station, incorporates storage, vaporisation, pressure regulation, and control systems to deliver natural gas exactly as if it were from a physical pipeline.

Small-scale LNG regasification is widely used to bring power to off-grid and remote locations, and provide LNG as a vehicle fuel. It is also an excellent solution to augmenting pipeline natural gas instead of oil-based fuels, as it utilises the same delivery system to the point of use as the pipeline gas.

Virtual pipeline

Where no physical pipeline for delivering natural gas exists, the process of delivering LNG from its source to the point of use by sea, road, rail or a combination of one or more of these, in cryogenic containers, is called the virtual pipeline.

Small-scale import terminals Figure 2. A series of small-scale LNG regasification facilities in Peru store LNG and provide natural gas to homes and businesses that previously used oil-based and wood fuels for heating.

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To compete with the economies of scale afforded by their much larger counterparts, small-scale import terminals have to provide a multi-function approach and respond quickly to demand fluctuations. The import terminal in Klaipeda, Lithuania, is a good example of this approach, where offloaded LNG can be used for marine bunkering,

loaded into road tankers for virtual pipeline distribution, or regasified for pipeline transmission.

Small-scale terminals also share many design and production features with their liquefaction plant counterparts. Shop-built equipment reduces cost and schedule, and modular construction reduces civil work and facilitates faster installation.

Replicable modules also mean that potential future capacity expansions can be incorporated into the base design. Another good example of a single-use, small-scale import facility is in Gibraltar, Spain. The 80 MW gas-fired power station is fed by a shore-built import terminal with 5000 m³ of LNG storage.

Bunkering terminals for marine fuelling are a further example of small-scale regasification in action.

The liquefaction of hydrogen produced from low-cost sources will allow for the storage and transportation of hydrogen energy all over the world, using a supply chain very similar to how the LNG supply chain is structured today.

Using LNG as the basis for developing global hydrogen supply chains

Not everything associated with hydrogen is ‘new’ or ‘novel’. In fact, liquid hydrogen products have been proven in use over decades, supporting a range of local markets and industrial applications, as well as launching satellites into space. It is the globalisation of liquid hydrogen that will require large-scale transportation systems that are used with LNG, and that extensive LNG experience can be applied to, for example, liquid export and import terminals, bunkering systems, and

cryogenic transport trailers and ISO containers for road, sea and rail.

All the way along the value chain, there are examples of increased demand for natural gas leading to developments in the capacity and capability of LNG equipment. As both LNG and liquid hydrogen are stored and transported in insulated vessels, many of those developments are directly transferable, and mean that the hydrogen infrastructure can similarly be expanded through shop-built, reliable and proven equipment.

One of the main features of hydrogen is its ability to store and produce electrical energy, enabled through the use of fuel cell technology. Fuel cell engines convert pure hydrogen into electricity through an electrochemical process without generating CO2 as a byproduct. This results in zero carbon emissions in the power generation process. Applications using natural gas or LNG to produce electricity or motive power require the combustion of natural gas, resulting in CO2 emissions at the point of use in the power generation process. As discussed earlier in this article, natural gas and LNG offer the ability to reduce emissions compared to gasoline or coal in power generation or transportation.

Producing hydrogen from natural gas, renewable natural gas (RNG) or renewable energy using fuel cell technology can reduce carbon emissions even further. In addition to the carbon and emissions reduction benefits of natural gas in internal combustion engines (ICEs), and hydrogen and fuel cell technology in fuel cell electric vehicles (FCEVs) for the power generation and transportation markets, fuel cell technology is more efficient in the conversion to

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The hydrogen gas produced from these sources can be liquefied, stored and transported into the markets as a low or zero-carbon electrical energy source for transportation or power generation. As with LNG, liquid hydrogen can be transported by truck, rail or water from regions with low-cost hydrogen production into regions with a demand for low-carbon energy feedstocks for transportation or power generation.

CCUS Figure 3. LNG bunkering terminal for fuelling ships in Jacksonville, Florida, US. electrical energy as compared to the traditional combustion technologies primarily used today.

When comparing the GHG emissions and energy efficiencies for natural gas and hydrogen to conventional gasoline, while liquid hydrogen has outstanding value regarding its gravimetric energy density, its volumetric energy density is very low compared to LNG, thus pushing the demand for larger volumes of storage tanks.

Furthermore, hydrogen is a much smaller molecule than natural gas, and components that are tight under natural gas services might leak in hydrogen service. Liquid hydrogen boils at -252.8˚C (22.3 K). Only liquid helium has a lower boiling point. Due to this, the cold temperatures of liquid hydrogen carry the potential of liquefying air and generating oxygen-rich condensates where the cold energy meets normal air. As such, the choice of potential refrigerants for a hydrogen liquefaction process and of purge gases for such cryogenic process units is extremely limited. The critical point of hydrogen is at 12.97 bar(a), above which it is a one-phase fluid and only has 50% of the density of cold liquid. Besides these fundamental characteristics, liquid hydrogen and gaseous hydrogen have other physical properties which need to be considered for all hydrogen equipment design and manufacturing in order to ensure safe and reliable operation.

Hydrogen can be liquefied by using either open-loop pre-cooling with liquid nitrogen (LIN) or with closed-loop pre-cooling. The first approach is typically used for smaller liquefiers, and where CAPEX is key to economic success and LIN is available at lower costs.

The second is more attractive for larger-scale liquefiers as the additional CAPEX is comparably small, but the effort for providing large amounts of LIN would be tremendous. The typical range for the required electrical power consumption starts from 7.5 kWh/kg for the open-loop process and from 10 to 15 kWh/kg for closed-loop processes. As with natural gas, hydrogen can be liquefied at a large, centralised production source and transported locally and globally, allowing it to be exported from geographies with low-cost production to the markets it serves. Some examples include: yy Green hydrogen can be produced via electrolysis in geographies where there is an abundance of wind and solar energy. yy Blue hydrogen can be produced in geographies with low-cost natural gas via steam methane reformation and carbon capture.

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Today, 10 million tpy of hydrogen capacity exists in the US, with most of that being grey hydrogen produced from natural gas. CCUS will play an important role in reducing carbon emissions and the transition to blue hydrogen playing a key role in the energy mix. A large concentration of the US-based hydrogen plants are located on the Gulf Coast, currently providing hydrogen for processing crude oil into transportation fuels. As the dependence on fossil fuels decreases, this hydrogen capacity can be used for other purposes such as mobility applications. Additionally, some of this hydrogen could be used for chemical applications, as well as hydrotreating in renewable diesel production facilities.

Technologies are being developed and demonstrated for the production of different colours of hydrogen. There has also been a huge uptick in carbon capture, both on a large-scale and, equally importantly, for smaller-scale solutions and retrofits to decarbonise existing facilities and industries where the captured CO2 is used in the production process. As well as creating blue hydrogen, the importance of CO2 as a valuable commodity was perfectly demonstrated in late summer in the UK when its main producer stopped work. This resulted in a cut of 60% of the UK’s food-grade CO2 supply. Production at the fertilizer plant, where the CO2 is produced as a byproduct, was only restarted after the government stepped in and agreed a price five times higher than it was previously.

Conclusion

There is significant evidence that the model for LNG can be applied to the liquid hydrogen value chain, further enabling hydrogen to play a significant part in the world’s sustainable energy future. Liquefaction processes were developed in the middle of the previous century and there are multiple, proven processes that are being further optimised for larger capacity liquefaction facilities. A lot of the key capital equipment is the same for natural gas and hydrogen liquefaction, and has been proven over many decades. Similarly, liquid hydrogen vessels and trailers, used for storage and transportation, are well-established across multiple cryogenic services, including hydrogen, and in applications such as high-tech manufacturing and aerospace, where quality is paramount. In summary, the cryogenic technology at the heart of LNG is uniquely positioned to play a key role in the build-out and scale-up of the global liquid hydrogen chain, and can also be applied to its decarbonisation.

Reference

1. ‘The Role of Gas in Today’s Energy Transitions’, IEA, (July 2019), https://iea.blob.core.windows.net/assets/cc35f20f-7a94-44dca750-41c117517e93/TheRoleofGas.pdf

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There is currently a shortfall of hydrogen available for traditional industrial uses. David Wolff, Nel Hydrogen, USA, explains why, and explores options for ensuring security of supply.

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H

ydrogen is a multi-skilled industrial chemical.

It is valued as a powerful reducing gas and for its high thermal conductivity, and is widely used for industrial processes such as metals processing and fabrication, as well as chemical processing.

Hydrogen’s reducing and thermal properties are also highly important in semiconductor manufacturing.

In addition to its primary reducing gas and thermal properties, hydrogen has many other unique attributes that are not easily substituted for other products, such as a power plant cooling gas; a lift gas for dirigibles and balloons; a powerful fuel for thermal spray, leak checking, gas chromatography; and more.

There are also new and significant hydrogen requirements that are emerging in the environmental realm, including hydrogen to replace carbon monoxide (CO) in primary steel production and hydrogen to replace natural gas for furnace heating. Additionally, new hydrogen demand is growing from a small base in the mobility market as a fuel for carbon-free transportation for heavy and

light-duty vehicles, and in stationary power applications.

While demand is up for hydrogen, its availability is showing signs of trending down. This article will explore the reasons for hydrogen’s shortfalls, as well as options for those users that need hydrogen for their processes and products.

Significant trends are narrowing the availability of hydrogen

Hydrogen is generated in certain industrial processes, particularly in chlorine and caustic manufacturing, and petroleum manufacturing. These processes generate excess byproduct hydrogen which is then collected, purified, and made available for distribution to others who need hydrogen for the variety of applications previously mentioned. Its distribution is mostly provided by truck, along with pipeline supply. If hydrogen demand exists, but no byproduct hydrogen is available, it is created by some means of near or onsite generation.

There are three megatrends happening that will strain delivered hydrogen availability. The first is the emergence

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of hydrogen as a vehicle fuel for over-the-road freight trucks. From 2010 to 2020, the market for hydrogen in the lift/forklift truck market alone has grown from non-existent to being the top user of liquid hydrogen worldwide, just for lift trucks (fork trucks) used inside factories. The impact on availability when over-the-road freight trucks begin to use hydrogen as fuel, too, will be huge.

The second is the return and expansion of semiconductor manufacturing in the US that is currently happening at speed. The US government enacted the CHIPS for America Act in 2021, and further investment in various semiconductor-related bills are now undergoing the legislative process. In addition to the hydrogen used for

annealing in semiconductor fabrication, the emergence of extreme ultraviolet lithography (EUV), which will enable the production of more advanced chips, is expected to double the hydrogen requirement in fabrication shops that adopt the technique.

The third is the resurgence of manned space flights lifting off from the US, which are dramatically impacting the demand for liquid hydrogen. It is important to note that NASA created the needs that spawned liquid hydrogen production in the US in the 1950s, and many of the plants that are now providing liquid hydrogen have been around for 60 or more years. Space Shuttle flights ceased in the US 10 years ago, and the hydrogen that served those flights has gradually been dedicated to industrial customers. Starting in 2022, NASA is going to begin space flights using the Space Launch System (SLS). Each of the SLS’ flights is going to require 50 trailer loads of liquid hydrogen. As such, each flight will require hydrogen equal to one day of production of the entire liquid hydrogen capacity of the US. Additionally, a handful of companies are creating a space tourism market, and some of them use liquid hydrogen fuel.

Liquid hydrogen

Most hydrogen that is delivered to customers today is transported in liquid form for efficiency of transportation. The hydrogen may be delivered as a liquid or may be vaporised and compressed near the use site for delivery as a compressed gas.

A lot of fuel cell vehicle fuelling stations begin operation using delivered liquid hydrogen because it is relatively less expensive to produce Figure 2. As demand for hydrogen continues to grow, and the supply of delivered hydrogen continues to high-pressure shrink, applications that do not require liquid hydrogen may be best served by onsite hydrogen generation. gaseous hydrogen

Figure 1. Hydrogen is a critical industrial raw material. Many of the products used in everyday life could not exist without it.

Table 1. Hydrogen supply options: merchant vs generation

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Hydrogen source

Volume range

Advantages

Drawbacks

Anticipated trend

Liquid hydrogen delivery

Medium, from 300 000 to 3 million standard ft³/ month

Inherent purity, low capital investment

Contract implications, price volatility, supply reliability

Shortages, reliability issues, price increases

Compressed hydrogen delivery

Low, < 500 000 standard ft³/month

Low capital investment, Contract, relatively high excellent for infrequent use gas price, purity

Onsite generation

Low to high

Stable pricing, designed for specific use

Pipeline third party supply

Typically high, 3+ million Predictable pricing standard ft³/month

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Shortages, reliability issues, price increases

Capital investment, back-up Market share increase Dependency, reliability, back-up

May be attractive when possible

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which is needed for the vehicle fuel tanks from liquid hydrogen. As those fuelling sites grow, they will inevitably shift to generated hydrogen and gas compression.

All space flight applications require liquid hydrogen for the energy density, and liquid hydrogen is highly valued in semiconductor applications for its simple implementation and inherent purity. Over time, it is projected that approximately half of the semiconductor plants will wind up with liquid and the others will either start or shift over to generated hydrogen onsite, primarily driven by hydrogen demand and availability.

Unfortunately for users, the supply of low-cost, raw byproduct hydrogen is dropping. This is not because of temporary conditions, but rather because of fundamental changes in production of chemicals all over the world. Many chlorine and caustic plants are shutting down in the US and Europe. Furthermore, refinery production is lessening, partly because automobiles now have improved mileage, and because electric vehicles (EVs) and hybrid vehicles have reduced gasoline consumption. Byproduct hydrogen for industrial use from chemical plants and refineries is less than it once was, driving down the supply of raw hydrogen available for liquefaction, just when the demand for it is going up.

More strains on hydrogen supply, demand and costs

Additional liquid hydrogen supply challenges are evident in other costs. For example, the cost of liquid hydrogen distribution trailers have almost doubled over the last few years. They now cost almost US$1.5 million. Meanwhile, lead times for those trailers are out to about 18 months.

Liquid hydrogen tanks for siting at customer locations are similarly escalating in price and are delayed in availability.

Complicating matters, a standard practice in the liquid hydrogen distribution industry has been to have two tractor drivers so that a trailer can move constantly and not have to stop when a lone driver would be required to rest. It has been big news in the US that there are simply not enough truck drivers to move goods.

Another point is that liquid hydrogen is a highly-specialised commodity requiring safe distribution.

The industrial gas industry must be extremely careful in the drivers that it chooses to employ, and it needs to pay at the top end of the payscale in order to retain these drivers.

Frequently, liquid hydrogen transportation involves long distances from the production site to the customer location. The transportation of liquid hydrogen is what is called ‘dead head’ transportation, which means that the hydrogen trailers go out full but return empty because there is nothing else that can be put in a liquid hydrogen trailer. This drives up the cost and reduces the effective use of these expensive liquid hydrogen trailers. It costs between US$4 – 5/mile for liquid hydrogen transportation today, and those costs are rising with the cost of drivers, trailers and fuel. It is also a highly-hazardous cargo which may be unattractive to haulers and drivers.

Possibly aggravating the situation further, industrial hydrogen suppliers have suggested that they might convert their tractor fleets over to hydrogen fuel. This is exciting because it demonstrates the technology, but it also means that some of the precious liquid hydrogen is going to fuel the delivery vehicle, meaning that the industrial uses may come up short.

Considering alternatives

Figure 3. When hooked up to a renewable energy source, both alkaline (top) and PEM electrolysers (bottom) can provide users with a continuous supply of green hydrogen, at a stable cost.

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Because of the strains on the availability of delivered – or merchant – hydrogen, many of the industrial hydrogen applications such as metal fabrication, chemicals and more should strongly consider whether they might be best served by moving away from liquid hydrogen to other hydrogen approaches that can give them assurance of cost-effective supply. The forces that affect liquid hydrogen costs, and therefore pricing, are the cost of the raw hydrogen, the size of the liquid hydrogen plant, the cost of the electric power at the plant, and the distance from the plant to the customer.

There are several quandaries about tank size at the customer location, too. Generally, industrial gas providers want larger tanks

because they are more efficient for distribution, yet the users of hydrogen prefer smaller tanks because the tank rental is cheaper, and they occupy less space.

How did this happen?

Why has there been so little advance investment in new liquefaction capacity? How did we get to this position?

As described, there are fewer good sources of raw gas. The availability of cheap raw hydrogen is falling for all the reasons presented in this article. Additionally, distribution is by truck.

There is no pipeline to the customer to subsidise the investment in a liquid hydrogen plant – it Figure 4. Electrolysers now come in a variety of sizes and hydrogen output is a great risk on the part of the industrial gas volumes – from small industrial units to large-scale megawatt plants to match company to build a plant and assume that any application. they will load it with customers. Building the liquefaction plant is only the first stage. Once the plant is built, they must have US$50 million worth of producing hydrogen for industrial processes. Starting in liquid hydrogen trailers to distribute that hydrogen. the 1960s, electrolysers became less popular, as delivered Traditionally, liquid hydrogen contractual relationships liquid hydrogen took over that role. Now, electrolysers have been built around a mutual requirements contract. are resuming the predominant role of future hydrogen Market disruptions for liquid hydrogen supply have created production, as they have become less expensive, more an opportunity for new types of contractual relationships, efficient, smaller, and produce hydrogen with optimal such as hybrid liquid hydrogen contracts that will enable purity. hydrogen users to supply a portion of their hydrogen The hybrid contract approach described supplies needs by generation, and the remainder to augment users with continual hydrogen with a diversity of supply their generation supply with delivered liquid or gaseous approach, at the lowest possible cost. The return on hydrogen. Users should aim for a consistent supply between investment (ROI) is often under five years. Considering generated and delivered hydrogen to pay the same or less the current hydrogen supply and trends, fewer than money overall as before. Naturally, the unit price of the five years can be attractive compared to facing disruptions delivered portion may have to be higher as a less regular and sudden price increases that affect the ability to make buyer. products that require hydrogen.

There are alternatives to delivered hydrogen. Some The cost of hydrogen by generation is a combination current users of hydrogen gas blends may be making of fixed and variable costs. The fixed cost is the cost of their own blends out of dissociated ammonia, or they the equipment. The variable cost is electricity, water and may be cracking natural gas to produce endothermic or maintenance. As the equipment becomes larger in scale, exothermic gas. These generation techniques produce the variable cost dominates. Compared to delivered the gas blends that are primarily used for metalworking. hydrogen, the fixed cost of buying a piece of equipment However, these alternatives have issues of their own in may be higher, but the variable cost is much lower than the terms of hazardous material storage, gas purity, or – in cost of delivered hydrogen today. the case of endothermic and exothermic – carbon dioxide (CO 2) emissions. Going forward, large-scale liquid hydrogen users could think about commissioning an onsite It is certainly a time of change in the deliverable hydrogen gaseous hydrogen plant, or they might receive a pipeline market. Hydrogen has become one of the leading stars supply from a third party that would build such a plant of the green movement and its many public initiatives to next door. All users should consider onsite-generated combat carbon emissions around the world. That very gaseous hydrogen based either on water electrolysis or movement, however, is causing the supply of merchant hydrocarbon reforming technology – steam methane hydrogen – for its traditional industrial uses – to decrease. reforming (SMR) – or other type of reformer. For a greener There are also significant trends occurring in the mobility, process, only electrolysis technology offers zero-carbon space travel, and semiconductor markets that will continue hydrogen. to require an increasing quantity of hydrogen. Fortunately, the supply strain is presenting itself just as the capability of onsite hydrogen generation is becoming more feasible than Barbara Heydorn, a noted hydrogen market expert, was ever. a co-author on the 1988 Chemical Economics Handbook Product Review, ‘Hydrogen’, which is one of the landmark 1. ‘Hydrogen’, Chemical Economics Handbook Product Review, studies of the hydrogen market.¹ She pointed out that at IHS Market, (1988), https://www.hugedomains.com/domain_ one time, electrolysers were the predominant means of profile.cfm?d=ihsmarket.com

Conclusion

Back to the future

Reference

Spring 2022

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Bharat Naik and Phil Millette, Honeywell Process Solutions, discuss how simulation could drive value across the hydrogen market.

C

ompanies looking toward net zero emissions are beginning to take actions to reduce their carbon footprint. Currently, there is a wealth of information that is being published by industry experts, which discusses the energy transition and technologies required to reach net zero. One of these technologies is the production of hydrogen from renewable energy sources, known as green hydrogen. As green technologies evolve and government policies develop, experts frequently mention the use of green hydrogen as a sustainable energy source, and it is seen by many companies as a key component of their net zero strategy.

Green hydrogen policies and initiatives can often be measured by the intended capacity of hydrogen production, initial plans, and envisioned growth. The growth expectations from the policies currently being announced in the medium-term (to 2030) and the longer-term (2040 and 2050) are significant. For example, the EU Hydrogen Policy, published in July 2020, plans for the installation of 6 GW of renewable hydrogen electrolysers by 2024, and 40 GW by 2030.¹ This is a significant increase in capacity, given that at the start of 2021 only 1 GW was installed in the EU.² Even though hydrogen is an energy carrier, it is neither a primary source of energy nor the first step in the value chain. Because green hydrogen is obtained through the electrolysis of water, the electricity required for electrolysis is the real front end of the value chain. This electricity can come from renewable sources such as wind or solar, or from hydroelectric or geothermal sources.

Since renewable power is the key starting point, Honeywell’s activity in battery energy storage, wind and solar facility SCADA, substation control, microgrid control, and virtual power plant control is also relevant to understanding and managing the performance of green hydrogen production. These areas can help when developing an approach to mitigating the intermittency of renewable energy, and ensuring reliable hydrogen production. The company’s activity also spans the rest of the hydrogen value chain, including process simulation, performance management, automation and management of efficient hydrogen production, storage, and integration.

Honeywell has made its own public commitment toward achieving carbon neutrality at its facilities and within operations by 2035.³ This commitment also includes the responsibility of sustainable innovation and helping customers reduce their own emissions. As the company’s net zero commitment extends to digital transformation sustainability solutions for clients, it is using software and expertise available today to support the sustainability goals of plant operations, while focusing on future innovations aligned with its culture of continuous improvement.

The simulation challenge and scope

Modelling a green hydrogen plant requires the representation of a wide scope of process equipment, including the electrolyser stack, water treatment and disposal facilities, electrolytes, and standard equipment such as gas/liquid separators, compressors, pumps, tanks, heat exchangers, and dryers.

The overall plant layout can include power supply transformers and rectifiers, utility supply (water, or potassium hydroxide [KOH] or steam, as relevant), drying, purification of hydrogen, hydrogen compression, and local pressured storage. It can also include water or KOH circulation, and purification of generated oxygen.

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This does not include further upstream processing that is considered for some projects, including water desalination, nor any downstream ammonia or methanol units that are themselves considerable investments.

Multiple electrolyser stacks are typically required to achieve the desired capacity, hence the requirement to combine multiple electrolysers into a single performant simulation model.

Furthermore, the unique physical characteristics of hydrogen require specific and accurate thermodynamic models to support the effective design and modelling of green hydrogen production.

The modelling scope can address the complexity of: yy Reliably producing hydrogen at expected production rates and of sufficient quality, with overarching safety requirements. yy Storing hydrogen and maintaining quality and safety. yy Transporting hydrogen efficiently, reliably and safely.

yy Main electrolyser stack parameters. yy Battery limit conditions of product streams.

The intermittency of many renewable power sources poses a primary challenge to efficient hydrogen production. In some projects, intermittency will be mitigated by the project scope itself, such as additional battery storage, green energy contracts to the grid, or designing the facility to handle extreme energy fluctuations. To meet these challenges, accurate simulation of hydrogen electrolysis and power variability mitigation strategies will be a critical component in project planning, design, and operational performance management of green hydrogen production.

The design of a new green hydrogen facility carries with it unique challenges, due to factors such as power supply intermittency, the various levels of electrolyser technology maturity, hydrogen storage requirements, and the disconnect between hydrogen demand and electricity supply. Hence, the decision on an optimal size and design of the plant will require the evaluation of tens, if not hundreds, of cases. The goal will be to minimise CAPEX and levelised hydrogen production costs while utilising available plot space and consistently meeting expected hydrogen demand.

The true CAPEX investment required of a green hydrogen project extends far beyond the electrolyser stack. Additional major blocks must be considered to estimate the investment required and to make decisions about plant design. These blocks include electrical supply stations, water purification units, electrolyte supply and discharge, cooling systems, wastewater treatment, hydrogen and oxygen distribution network, and ancillary systems including safety systems and storage tanks.

Aside from CAPEX considerations, other key aspects of designing a green hydrogen plant include ensuring that the design software has the requisite capabilities to precisely replicate the produced hydrogen and produced oxygen networks through a wide range of pressures and temperatures.

Additionally, modelling the electrolyser to accurately predict performance and hydrogen production can be very complex.

Assuming most viable technologies today are alkaline and PEM electrolysers, the following are key variables to model: yy Current density: affects hydrogen produced per active area.

Process simulation as an engine to drive value across an asset’s life cycle

Process simulators, such as Honeywell’s UniSim® Design Suite, are applicable across the entire life cycle of a green hydrogen project, including feasibility studies, option analysis, engineering design, detailed engineering, operator training, operations, and optimisation. UniSim Design’s process simulation is central to analysing the various options that will determine the economic and operable feasibility of a selected design. The early conceptual phase of a green hydrogen project will include sorting through numerous options with the following key process variables: yy Electrolyser technology: alkaline, proton exchange membrane (PEM), or solid oxide. yy Variability of electrical supply. yy Electrolyser water quality. yy Discharge water quality.

Figure 1. Produced H2 network, produced O2 network, and electrolyser.

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Near-term innovations in process simulation are focused on the accurate replication of the electrolyser stack design in order to accommodate evolving electrolyser technology. The electrolyser stack will contain proprietary technology and knowledge about the internal details that will not be available outside the development company. Therefore, the electrolyser stack model, within a process simulator, must be broad and generic to accommodate a variety of designs. Much like a catalytic reactor in a refinery, the final design of the electrolyser will be supplied by the technology vendor. The process simulation will represent the overall performance of this stack, and the balance of the plant.

Choosing the best design

yy Power density: the required electricity and power supply/rectifier size. yy Gas crossover: helps determine limitations to maintain safety and achievable faradaic efficiency. yy Operating temperature: increasing temperature improves kinetics and thermodynamics and decreases overpotentials, but decreases stability and may increase crossover. yy Heat management: the reaction is endothermic, but overpotentials generate excess heat. yy Pressure: elevated hydrogen pressure at stack reduces downstream compression stages, but increases crossover. yy Feed water purity/composition: impurities lead to stability issues and recycling leads to product impurities. yy Internal flow dynamics and temperature gradients: affect local performance.

Additional near-term modelling developments will mirror electrolyser innovations, with capabilities to support alkaline and PEM technologies, including solid oxide electrolysers.

UniSim Design’s integrated case scenario manager further supports the green hydrogen evolution via right and fast analysis of various design scenarios by simultaneous execution of several cases with minimal user intervention. Results of various cases can be easily integrated with cost-estimating software Cleopatra Plus for developing techno-economic analysis and selection packages.

In addition to helping determine an optimal process design, UniSim Design can also be applied throughout the life cycle of a green hydrogen project, including: yy Feasibility studies. yy Basic engineering design.

Powering the energy transition

yy EPC phase. yy Operator training utilising UniSim Dynamics via Honeywell’s Workforce Competency. yy Opportunity analysis via what-if scenarios. yy Operational performance tracking and optimisation via UniSim Live.

Green hydrogen and the path to net zero

In summary, the emerging field of green hydrogen faces many challenges to consider and overcome, such as product supply infrastructure, cost optimisation, operations under varying inputs, technological feasibility/operability, reliability, and safety. The end goal is to build a safe and reliable facility while maximising the use of plot space and minimising the levelised cost of hydrogen.

Solving these challenges and optimising process variables through modelling is the first step toward sustainable hydrogen production.

Across the entire value chain and life cycle of green hydrogen projects, process simulation will be a key tool that helps enable the success of these projects, and contribute to a net zero future.

References

1. ‘EU hydrogen policy: Hydrogen as an energy carrier for a climate-neutral economy’, European Parliamentary Research Service, (April 2021), https://www.europarl.europa.eu/RegData/etudes/BRIE/2021/689332/ EPRS_BRI(2021)689332_EN.pdf 2. ‘The European hydrogen strategy’, Watson Farley & Williams, (3 February 2021), https://www.wfw.com/articles/the-europeanhydrogen-strategy/ 3. ‘Honeywell Commits To Carbon Neutrality In Its Operations And Facilities By 2035’, Honeywell, (8 April 2021), https://www.honeywell. com/us/en/press/2021/04/honeywell-commits-to-carbon-neutrality-inits-operations-and-facilities-by-2035

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Hydrogen Usage

Caroline Stancell, Air Products, Europe, asks how the transport sector can grow its use of hydrogen, and what barriers are preventing it from going to the next level?

G

reenhouse gas (GHG) emissions have been accelerating climate change, which is affecting the planet. To generate a cleaner future, the world faces a huge challenge where we, as both individuals and industries, must transition towards clean, sustainable energy sources. Governments and

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national leaders around the world are taking action by implementing emission reduction targets and subsidies to develop greener technologies. The 2021 UN Climate Change Conference (COP26) brought together leaders from across the globe in a bid to accelerate action towards the goals of the Paris Agreement. Key emitting sectors and

areas have been identified and are being driven to reduce their emissions. This includes transportation and logistics.

As an example of this, the European Commission has proposed to cut GHG emissions by at least 55% by 2030. This sets the EU on a path to becoming climate neutral by 2050. Similar ambitions have been replicated in other regions, marking the recognised need for – and commitment to – tackling climate change and the energy transition head on. However, generating a cleaner future requires experience, investment and innovation on a world scale. Action is needed, and it is needed now.

Transition in the transportation sector The transportation sector has been identified as a key emitting sector. According to the International Energy Agency (IEA), transport is currently more reliant on fossil fuels than any other sector, and accounts for 37% of carbon dioxide (CO2) emissions.¹ Unfortunately, emissions from transport are continuing to rise. The European Environment Agency revealed that GHG emissions from transport have been increasing since

2014, and by 2016, transport emissions were 26.1% higher than they were in 1990.² By 2017, preliminary estimates from EU Member States showed that GHG emissions from transport were 28% above what they were in 1990.

However, the sector is making big changes in a quest to decarbonise. Heavy-duty transport is one of the ‘hard-to-abate’ sectors. While battery electric vehicles (EVs) work for some heavy-duty transport applications, they do not for others. This leaves many transport applications without a straightforward transition towards decarbonisation. The challenge lies in investing in new manufacturing and production processes that use clean fuels, including better design and greater efficiencies in energy, materials and circularity, which come with higher abatement costs. Fortunately, there already exists a solution to combat this challenge: hydrogen.

In many ways, hydrogen is the perfect fuel. It is efficient and produces no harmful emissions when used in a fuel cell. Deployed together, battery and fuel cell EVs have the potential to facilitate a significant transition towards a sustainable transportation sector, due to

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the complementary strengths of both technologies.

The Hydrogen Council and McKinsey & Co. believe this will “enable greener transportation faster and cheaper compared to relying on a single technology.”³ There is no doubt that, with the journey to decarbonisation already well underway in the transport sector, recognition of hydrogen as a solution is rocketing due to the benefits that it can provide. Hydrogen fuel provides a long driving range, quick refuelling times, zero tank-to-wheel emissions, and a high payload capacity.

It must continue to play the role of a catalyst, driving significant change.

Hydrogen expertise and potential

Hydrogen is a solution that has long been recommended

by Air Products – a company that has 60 years’ experience in the production, distribution, storage, and dispensing of hydrogen. In that time, it has developed a range of proven hydrogen technologies and end-to-end solutions to support the wide-scale energy transition in the transport sector.

Hydrogen is the future for heavy-duty segments of the transportation market, and Air Products will be one of the

first to transition its heavy-duty fleet of trucks to hydrogen fuel cell EVs. Deployment of hydrogen is quickly accelerating in response to global decarbonisation commitments, and its demand is expected to continue on this trajectory.

According to the IEA’s ‘Global Hydrogen Review 2021’ report, by 2050, demand for hydrogen and hydrogen-based fuels across all transport end-uses is expected to be over 15 times higher than in 2030, meeting 6% of the sector’s energy demand.4 Not all transport is suited to being powered by hydrogen.

For example, for vehicles under a certain size or weight, or that need to travel only shorter distances (for example, less than 200 km between refuelling, according to the Hydrogen Council),5 direct electrification is probably going to be more suitable. The Hydrogen Council’s ‘Hydrogen Insights’ report states that “hydrogen is only competitive in heavier road transportation applications (not including passenger cars),” according to the price targets for blue and green hydrogen for 2030 and without costs for carbon emissions.6 It is believed that there will be space for multiple technologies in this market in the future.

Different fuels will always be better suited to different uses – whether it is EVs or a particular mode of heavy-duty transport that utilises hydrogen, such as buses, trucks, trains and ships. Therefore, the question is: how can the transport sector grow its use of hydrogen, and what barriers are preventing it from going to the next level?

Challenges and opportunities

Figure 1. A hydrogen-powered bus filling up at a mobile hydrogen refuelling station.

Figure 2. A truck demonstration using hydrogen to fuel heavy-duty vehicles.

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Time is money, so transport operators are keen to find a solution that gets their sustainable vehicles on the road as quickly as possible.

Reliability of supply (whatever the application) is crucial, as operators look for proven, commercial solutions. Air Products has been involved in more than 250 hydrogen fuelling projects in over 20 countries worldwide. The company’s experience has resulted in an understanding of both the pressures that operators face, and the importance of making any investment viable.

A ‘one-size-fits-all’ approach is not always the best solution for customers, which is why the company provides different modes of supply to fit individual requirements. These can be tailored to different demands, based on what is most suitable for an operator, regardless of fleet size.

There also needs to be an incentive mechanism in place for zero-emission vehicles (ZEV). Regulation can help, but questions remain about how such a policy should look. For example, the UK included a reference to a ZEV mandate in its Net Zero Strategy, which aims to “guarantee greater number of zero emission vehicles [...] unlocking the transformation of our road transport.”7 This is a step in the right direction and will help to grow the demand for

clean fuels infrastructure; however, there is a barrier that might affect its progress: cost.

While time may equal money, it certainly helps if government subsidies kick-start the market.

Stimulus to drive markets is what the hydrogen for mobility sector needs – these technologies, products and solutions are already available, but they need to be adopted at scale. Subsidies aimed at stimulating demand will help the industry to move forward and support a commercial case. In other words: the market needs an incentive to convert.

The NEOM Green Hydrogen Project in Saudi Arabia will make green hydrogen available in Figure 3. 3D conceptual design of a bus at Air Products’ hydrogen refuelling significant quantity. Air Products is a key partner station. in this project, which will supply renewable hydrogen to power buses and trucks around the world in a few years, eliminating 3 million tpy it is fairly new to the transport sector. These questions also of CO2 emissions, equivalent to the emissions from over link to another barrier: the perception that lots of upfront 700 000 cars. The joint venture (JV) project in Saudi Arabia investment is needed. This is why a flexible end-to-end with NEOM and ACWA Power will include 4 GW of solution, including a demonstration with a mobile refueller, renewable energy – from solar and wind sources – which can help to support businesses in making the transition will produce 650 tpd of hydrogen. This project will become to a hydrogen powered future. For years, Air Products a frontrunner in the green hydrogen economy, and will has provided businesses with demonstrations and flexible also diversify the sourcing of the renewable energy that testing solutions, which can be mobilised within weeks decarbonising economies need. to provide a supply that starts small and can be scaled up Occasionally, there are questions around using a new as needed. As an example of this, the company recently fuel such as hydrogen. Even though hydrogen has been participated in a demonstration of a hydrogen truck used in other sectors for years – particularly in industry, in France, and provided its mobile hydrogen refuelling such as in oil refining and for the production of fertilizers – station, making it tangible for future potential users of

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is a limited choice of trucks on the market.

A greater number and variety of vehicles are needed.

The Hydrogen Council describes the next few years as being “decisive for the development of the hydrogen ecosystem, for achieving the energy transition and for attaining the decarbonisation objective”.6 There has been so much progress made already that has got us to this point, and this is just the tip of the iceberg.

There are so many opportunities to work together to take hydrogen for mobility to the next step, and greater collaboration will unlock new projects and encourage more investment. To drive rapid progress in transport decarbonisation, however, demand-side Figure 4. A truck delivering liquid hydrogen to power heavy-duty vehicles. subsidies are required to ease the transition to clean fuels and drive the hydrogen transport market forward. this technology. The company’s agreement with the local Hydrogen will play a pivotal role in generating a cleaner municipality of the city of Hürth, Germany, to build and future for the transport sector. In addition to this, it will operate a new hydrogen refuelling station is another lead to a skills revolution where mechanics and engineers example of how it is working in partnership to decarbonise can retrain and become qualified to work with hydrogen transportation, by showcasing expertise, technology and vehicles too. Other opportunities for job creation include design, while proving hydrogen’s reliability. the maintenance of local hydrogen fuelling stations, designing the next generation of stations, and training the engineers of tomorrow. Air Products has begun by training What does fuelling the next generation of heavy-duty its engineers on real hydrogen fuelling stations rather than vehicles look like? Air Products’ work with on 3D schematics, in order to ensure that they are able to The Go-Ahead Group is a positive model of the growing become experts in this area before demand ramps up. movement to hydrogen and is one of the largest hydrogen Tomorrow’s challenges demand diverse thinking, varied supply contracts for buses in the UK to date. In early 2022, sourcing, applications, technologies, mega-project expertise, it agreed to a 15-year hydrogen supply deal to power and a collaborative spirit. By working together, we can use the Go-Ahead’s fleet of 20 fuel cell buses for deployment power of hydrogen to decarbonise our future transport. around Gatwick Airport in the UK. It is the intention that the hydrogen to power the buses will meet, or indeed exceed, UK government standards on sustainable fuel for public 1. ‘Improving the sustainability of passenger and freight transport’, transport. Hydrogen will be stored at Go-Ahead’s Metrobus IEA, https://www.iea.org/topics/transport Crawley depot in liquid form, before being converted to gas 2. ‘Progress of EU transport sector towards its environment and held in tanks on the buses. This provides Metrobus with the climate objectives’, European Environment Agency, https:// www.eea.europa.eu/publications/progress-of-eu-transportinfrastructure to not only fuel its initial fleet but allow for sector-1 rapid expansion without additional footprint or cost.

3. ‘Greener, faster, cheaper: a combination of battery and fuel The single-decker fuel cell buses are funded in part with cell electric technology is key to successfully decarbonising global transport’, Hydrogen Council, (27 October 2021), money from the UK government and EU zero-emission https://hydrogencouncil.com/en/greener-faster-cheaper-abus schemes, as well as investment from Gatwick Airport. combination-of-battery-and-fuel-cell-electric-technology-is-keyto-successfully-decarbonising-global-transport/ This additional funding support, as well as the accelerated 4. ‘Global Hydrogen Review’, IEA, (October 2021), iea.org/reports/ pressure to move towards net zero, are making schemes such global-hydrogen-review-2021 as this one possible. The supply deal will start by temporarily 5. ‘Path to hydrogen competitiveness: A cost perspective’, Hydrogen Council, (20 January 2020), https://hydrogencouncil. using gaseous hydrogen, before moving towards liquid com/wp-content/uploads/2020/01/Path-to-Hydrogenhydrogen. The core capital equipment and investment will Competitiveness Full-Study-1.pdf stay the same, even when the fleet grows in size.

6. ‘Hydrogen Insights: A perspective on hydrogen investment,

Solutions in play

References

Looking ahead

It is an exciting time for the transport sector, and it is clear that the hydrogen industry is ready to respond to demand from the market. To supply hydrogen to vehicles at scale, there needs to be more of those vehicles – this means bus and, particularly, truck manufacturers need to deliver more vehicles to take advantage of the growing demand to provide customers with a range of options. Heavy-duty hydrogen vehicles are not yet available in large numbers, so there

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market development and cost competitiveness’, Hydrogen Council, (February 2021), https://hydrogencouncil. com/wp-content/uploads/2021/02/Hydrogen-Insights-2021.pdf 7. ‘Net Zero Strategy: Build Back Greener’, HM Government, (October 2021), https://assets.publishing.service.gov.uk/ government/uploads/system/uploads/attachment_data/ file/1033990/net-zero-strategy-beis.pdf

Note

The product images shown in this article are for illustration purposes only, and may not be an exact representation of the product. Air Products reserves the right to change product images and specifications at any time without notice.

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Ollie Burkinshaw, Neil Gallon and Jason Edwards, ROSEN UK, address the challenge of integrity management of hydrogen pipelines.

C

limate change is perhaps the biggest global challenge of the 21st century. If the world is to succeed in limiting global temperature increases to below 2˚C, all available solutions must be leveraged and accelerated.

Electricity and gas will continue to fulfil complementary roles in the future integrated energy system. Electrification of all industrial and residential energy demand is not feasible, and certain industries cannot be readily electrified. In terms of low-carbon energy supply, hydrogen is a logical means to address these issues, as it is easy to transport and store using a significant proportion of repurposed infrastructure. In the medium-term, it appears inevitable that blue hydrogen – whereby hydrogen is extracted from natural gas, and the carbon dioxide (CO2) is stored to prevent emissions (carbon capture and storage [CCS]) – will play a large role. Longer-term, green hydrogen predominantly generated via electrolysis using renewable energy sources is an effective solution for the storage and transportation of intermittent and excess power, providing flexibility and resilience in our energy supply.

Regardless of the colour of the hydrogen, pipelines will be required to transport it. This has been recognised globally with initiatives such as the European Hydrogen Backbone, a growing group of now 29 European gas infrastructure companies targeting a hydrogen transmission network of 39 700 km by 2040, with further growth expected after 2040.1 The capital cost of repurposing existing pipelines is expected to be between 10 – 25% of the cost of building new pipelines. For hydrogen pipeline infrastructure (either with 100% hydrogen or a blend of hydrogen and natural gas) to be economically feasible, a significant proportion of the existing global pipeline infrastructure (of which there are several million kilometres) must be leveraged to form the future hydrogen pipeline infrastructure. The European Hydrogen Backbone currently projects that approximately 70% of future hydrogen pipelines will be repurposed existing pipelines.

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The challenge

While the concept of hydrogen pipelines is not new or inherently impossible – there are already thousands of kilometres of hydrogen pipelines in service – the introduction of hydrogen into existing natural gas transmission and distribution networks creates unique challenges.

The challenges associated with converting existing pipelines can be summarised in two simple questions for pipeline operators: � Can my existing pipeline be safely converted to hydrogen service? � How can the integrity of a hydrogen pipeline be managed?

Apart from the general integrity challenges and threats to any pipeline, the integrity challenges and damage mechanisms specific to hydrogen transport can be split into two main areas. Hydrogen can cause cracking directly (hydrogen-induced cracking), though this is generally not likely from gaseous hydrogen exposure alone and would require high concentrations of hydrogen typically resulting from sour service conditions or cathodic over-protection. More relevant for gaseous hydrogen service, however, is the more insidious influence of hydrogen negatively affecting the material properties of steel line pipe. The most important mechanical properties of steel line pipe are strength (yield strength and ultimate tensile strength), ductility, fracture toughness, and resistance to fatigue cracking. The effect of hydrogen on these properties are summarised in Table 1.

The figures in Table 1, which are supported by literature and industry testing, show a wide range of hydrogen-related effects on the different material properties, with varying degrees of severity. Although this wide range is partially accounted for by the different test protocols, hydrogen concentrations, and temperatures used in the studies, it is also largely a function of the very significant variation in how different materials respond to the presence of hydrogen. Line pipe in existing pipeline infrastructure can be up to 100 years old, with the majority in the US and Europe having been installed between 30 – 50 years ago.

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During this time, metallurgy, manufacturing and welding processes have changed and evolved dramatically. Existing pipelines therefore encompass a whole spectrum of different pipe grades, microstructures, chemical compositions and welding techniques, and these different materials are found to respond very differently when exposed to hydrogen.

The vast majority of existing hydrogen pipelines have been specifically designed, built or operated to hydrogen-specific codes and standards, which tend to be significantly more restrictive than their natural gas equivalents. Operating pressures and pipeline design are generally specified to ensure lower hoop stresses as a percentage of specified minimum yield strength (SMYS). Another key aspect of codes for purpose-built hydrogen pipelines is in the selection and specification of materials: grades are more tightly specified (in terms of allowable chemical composition and mechanical properties). In an attempt to limit susceptibility to hydrogen embrittlement effects, grades are also generally restricted to X52 (corresponding to an SMYS of 52 ksi [360 MPa]) or below. Additionally, qualification testing is conducted to ensure sufficient toughness to guarantee adequate flaw tolerance. For existing pipelines, grades of up to X80 (corresponding to an SMYS of 80 ksi [550 MPa]) are common.

Material considerations

When considering converting an existing pipeline to hydrogen service, it must be recognised that the materials present – in particular, older line pipe materials – may have not been specified

Table 1. The effects of hydrogen on the mechanical

properties of pipelines Property

Effect of hydrogen compared to natural gas

Typical approximate range of effect from testing in literature

Strength

Minimal effect

< 5%

Ductility

Significant decrease

20 – 80%

Fracture toughness Significant decrease

35 – 70%

Fatigue-crack growth rate

Up to 10x

Significant increase

Figure 1. ROSEN’s hydrogen pipeline integrity framework.

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or manufactured with any minimum toughness requirements at all, and toughness may be very low in the parent and weld materials. Introducing hydrogen to a pipeline for which there is uncertainty around the properties of the materials present leads to unquantified risks. Flaws that may have been stable for a long time when transporting natural gas may become critical when hydrogen is introduced, and without robust knowledge of the pipeline materials, the results could be highly unpredictable.

Understanding the different materials within a pipeline (both parent and weld), and their behaviour in hydrogen environments, is therefore incredibly important. Although some operators may have records of the original pipeline material, many do not, and a complete understanding of the pipeline history in terms of modifications, repairs and replacements might not be obtainable.

Over time, confidence in historical records can easily be eroded as operating companies are bought and sold, key staff changes, processes evolve, and paper records are lost. This can result in significant uncertainty regarding how many different material types exist within the pipeline, as well as their locations.

The solution

To support pipeline operators in this process, ROSEN has developed a holistic Hydrogen Pipeline Integrity Framework (see Figure 1) based on an integrated asset management approach, recognising that every pipeline is unique and will have its own specific set of circumstances. This framework provides a structured but flexible roadmap for the safe and efficient conversion of existing pipelines to hydrogen, and for the reliable integrity management of hydrogen pipelines.

This integrity approach is founded on research of issues such as material susceptibility to hydrogen embrittlement and accelerated fatigue cracking, as well as both well-established and novel or emerging diagnostic technologies targeted at detecting and quantifying the associated threats.

The first stage of the integrity framework consists of understanding the potential threats. This aspect is fundamental.

In essence, the potential threats can be divided into three main categories. The first is threats that exist regardless of the medium being transported, such as external corrosion or third-party

mechanical damage. The second is direct threats caused by hydrogen, such as cracking. The final threat is hydrogen-induced changes to pipeline material properties such as embrittlement and increased fatigue susceptibility. These threats should then be assessed against existing knowledge about the pipeline, current condition, operating and failure history, known presence or susceptibility to certain threats or feature types, environmental conditions, material properties, seam types, and welding procedures used during construction. An essential outcome of this assessment is the identification of any knowledge gaps that must be filled to enable accurate risk assessment and ongoing integrity management in the context of hydrogen service.

Data gaps can be filled using a combination of existing in-line inspection (ILI) tools, direct assessment, in-situ non-destructive testing, and destructive testing from coupons or cut outs. Of particular relevance for ILI services in the conversion process of existing natural gas pipelines to hydrogen are metal loss, deformation (such as dents and buckles), cracks and crack-like features, and material property determination.

ILI services for the detection of metal loss and deformation are well-established and mature services, though advances are still being made to improve their detection and sizing capabilities.

Crack-detection technologies are well-established for liquids lines.

More recently, however, electromagnetic acoustic transducer (EMAT) technology has been developed to allow for crack detection in gas lines without the need for a liquid couplant. The evolution of EMAT technology capability is therefore of prime importance for crack detection and thus for the facilitation of integrity management programmes for hydrogen service.

The identification of different pipe materials that are present, as well as their properties, has historically not been possible, aside for spot checks at above-ground locations or a small number of excavations. However, recent technologies have transformed the industry’s capability to identify and measure material properties in a way that is financially and operationally viable.

ROSEN’s material property inspection tools include a unique ILI service, RoMat PGS, that can reliably identify the different pipe materials present within a pipeline down to each individual pipe spool, and group them into ‘populations’ with shared material properties and attributes. This service is also able to report the strength, and therefore grade, of each pipe, enabling operators to directly identify grades, which are an essential factor in calculating maximum allowable operating pressure (MAOP) and derating factors specified in hydrogen pipeline design codes such as ASME B31.12. Another service in the RoMat family, RoMat DMG, is able to reliably detect and size hard spots, which may act as locations for stress concentrations, severe hydrogen embrittlement, and crack initiation. With ROSEN’s modular inspection technologies, hard spot, pipe grade, metal loss and deformation data sets can be captured in a single inspection, maximising efficiency for operators.

It is also important to note that synergistic benefits can be gained from running multiple inspection technologies, since the information can be overlaid (integrated) and analysed in combination to assist with improvements in probability of identification, feature classification, segmentation, and risk assessment. Depending on the existing knowledge and the current conditions of the pipeline, it may be essential to run a combination of diagnostic tools as a baseline inspection before and after conversion to hydrogen service – firstly, to ensure safe operation,

Figure 2. While ROSEN’s PGS ILI tool measures the pipe grade strength of each pipe joint, the RoMat DMG identifies hard spots in the pipe steel.

Figure 3. ROSEN’s RoCD EMAT service detects cracking or crack-like features in gas pipelines and can be ideally applied to integrity management programmes for hydrogen pipelines. and secondly, to facilitate efficient comparison of pipeline condition and feature sizing following the introduction of hydrogen.

Apart from the effects on line pipe that have been outlined above, hydrogen can also affect the performance and integrity of ILI tools. ROSEN has already made and used ILI tools that can operate in up to 100% hydrogen at 100 bar at ambient temperature, using specific designs for sealing, special materials for discs and cups, and hydrogen-proofed electronic components, alloys, and magnets. These tools have been proven in service, and successful inspections of hydrogen pipelines have already been performed.

Conclusion

Once the appropriate pipeline inspection runs have been identified and successfully performed, the gathered information can be analysed and assessed. These integrity assessments will support strategies for validation and remediation, and provide data for input into fitness-for-service and remaining life assessments. Finally, these results must be reflected in an updated risk assessment that serves as input for robust future integrity management plans and processes. A holistic and structured approach using ILI as the foundation is essential to supporting accurate risk assessments and paving the way for an economic and safe conversion and operation of existing assets to hydrogen service.

Reference

1. ‘European Hydrogen Backbone’, Gas for Climate, https://gasforclimate2050.eu/ehb/

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Joost Meeuwissen, Calderys, the Netherlands, describes how pre-cast, pre-fired catalyst support domes are setting new standards when it comes to long-lasting durability.

A

ny industrial process involving high temperatures requires refractories in order to operate. Heat is not, however, the only issue that these materials face. In most chemical processes, refractories will be exposed to a range of other stresses, including mechanical (abrasion), thermal (wide swings in temperature), and chemical stress.

With any industrial operation, the first step in refractory selection is to identify the operating conditions that will determine the origin of the refractory wear. These will differ depending on the industry process in question: in some conditions, certain types of wear will be more relevant than others. Refractory properties should therefore be optimised to the specific process environment in order to maximise refractory life at the lowest cost.

Within the growing hydrogen economies, specialised equipment such as autothermal reforming (ATR) and other reformers will be in demand for flexible and more efficient hydrogen, and for producing blue hydrogen and green ammonia with a lower carbon footprint.

When considering refractories for hydrogen production units, chemical corrosion is the main concern. Although process temperature is high, it is constant, reducing the risk of thermal shock caused by large fluctuations in the thermal profile. Meanwhile, processing units only contain gas; there are no solids or liquids. As a result, abrasion is minimal and does not represent a major concern.

Case study: pre-cast, pre-fired catalyst support domes

Catalyst support domes are installed in various chemical production processes (such as ammonia and syngas) that contain secondary reformers.

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The conditions experienced by these domes are severe: environments comprising significant percentages of carbon monoxide (CO), carbon dioxide (CO2), hydrogen (H2), water (H2O), and nitrogen (N2), at maximum temperatures of about 1300°C and high pressures of approximately 35 bar, are common. In such conditions, the performance of the refractory lining is critical. Aluminous refractories, which are low in both silica and iron oxide, are typically recommended.

These are usually as pre-fabricated, sintered bricks, from which the dome is constructed.

The major consideration when selecting the support dome is the compressive stress that is placed on it by the weight of the catalyst bed. Combined with the high-pressure conditions inside the secondary reformer, and high process requirements of the plant, the dome would be liable to crack over time. However, novel solutions that extend refractory lifetime and reduce turnaround time for replacement offer key benefits. The first pre-cast, pre-fired (PCPF) catalyst

support dome has been demonstrating these benefits over the past six years of operation.

Improved quality and delivery time of a PCPF catalyst support dome

This first dome was supplied to a US chemicals manufacturer

by Calderys in 2015 as a significant part of the refractory construction. The faster fabrication time of the PCPF dome compared to traditional refractory brick construction meant that it could be delivered just before installation, without causing any delays to the project.

In fact, that same year, another PCPF catalyst support dome was ordered from Calderys based on quick delivery, as there was no spare dome available, and the original brick supplier was not able to produce and supply the spare dome within the delivery time required to hit the onsite installation date. This meant that Calderys had to produce the monolithic and prepare moulds, as well as pre-cast, pre-fire and pack the dome blocks in its workshop for shipment.

Finding the desired strength to avoid hairline cracks

Figure 1. A 3D computer model of the PCPF support dome.

Occupying the space between a full monolithic solution and bricks are ready shapes, which are made from monolithic refractory materials, shaped and thermally treated at the refractory manufacturing unit, before being dispatched to the job site. Their primary advantage is the time needed for their production, which is typically about 50% shorter than that needed for bricks. Lead times can be reduced by a further 50% by employing the latest 3D printing technology to create precise moulds.

Apart from this, there is a greater freedom in the choice of moulds, mould materials, and mould shapes.

Figure 2. Calde Cast LT 93/1 PCPF secondary reformer dome. Assembled dome for mock-up in the ready shape production facility (left). The actual onsite assembly of the dome in progress is inside the secondary reformer (right).

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1008.5 Max 1004.5 1000.6 996.62 992.67 988.71 984.76 980.8 976.85 972.89 Min

2.8692e6 Max 2.194e6 1.5188e6 8.4358e5 1.6838e5 -5.0683e5 -1.182e6 -1.8572e6 -2.5324e6 -3.2076e6 Min

Figure 3. Thermal field on the upper part of the dome (left); tensile stress in the centre of the dome (right).

Compressive strength was therefore a key factor: traditional sintered bricks could only offer the minimum required in the specifications (80 MPa). In contrast, the monolithics provide strengths of up to 100 MPa. This high compressive strength comes from the fact that it is vibrated in the mould during the production process, compacting from multiple directions.

Bricks, on the other hand, can only be compressed from one press direction.

The properties of the material used for ready shapes, CALDE® CAST LT 93/1, are equivalent to the white, tabular, alumina-based bricks recommended for use in reformers, and this solution is one of Calderys’ spinel-containing raw materials, comprising 92.5% aluminium oxide (Al2O3) and 5.7% magnesium oxide (MgO). This higher-than-standard MgO content is integrated within the crystal lattice of the spinel, improving the strength of the material; there is no ‘free’ MgO or periclase, even at very high temperatures (> 1800°C).

This product is low in both iron oxide and silica, demonstrates high hot and cold strength and, above all, has very high creep resistance in compliance with the specification of the product recommended by the licensors for the secondary reformer dome. As a result, the Calderys team could be sure that the dome would remain stable, despite its large size of about 2.5 m dia. x 1.5 m height.

During the detailed design stage, Calderys took a close look at the mechanical strength and heat inside the PCPF ready blocks to determine in advance whether there was any risk of hairline cracks or other damage. The company’s Science & Technology Department was able to support this by using the numerical simulations tool. Different studies were realised to better understand the conditions and optimise the geometry.

After defining the initial thermal conditions (1400°C on the upper part of the catalyst bed, and 1000°C below the dome), it was possible to precisely define the thermal field appearing on the dome.

After defining the initial mechanical conditions (weight of the catalyst bed on the upper face of the dome), the company was able to get a clear idea of the mechanical stress inside the dome.

Even working with simplified conditions, the numerical simulations tool helped to optimise the design of the dome, and clearly show that the level of stress appearing in the dome due to gravity and weight of the catalyst bed is always lower

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than maximum tensile stress (20 MPa) and compressive stress (90 MPa) permitted by the CALDE Cast LT 93/1.

The turnaround on a brick dome is normally two to three years after start-up. After this, the catalysts are usually washed or replaced, along with the dome. Calderys intended to deliver the monolithic dome on the basis of a five-year lifetime. However, the dome is still in place after more than five years in operation and through a number of maintenance stops.

Additional domes

Based on the performance of the original domes, Calderys teams have been able to supply a like-for-like spare dome to the same customer.

With a maintenance stop coming up early in 2022, it was thought prudent to have a spare dome on standby to ensure process continuity, should it be necessary to replace the dome. It would also be standard to consider upgrading the design of the dome at this point. However, the performance of the dome has surpassed expectations, and the customer decided that it was not necessary to make any changes.

Since the original installation, Calderys has supplied a second and even a third, heavier dome to other customers.

The challenge is always with the specification of the licensor, which tends to require a 99% Al2O3 material. Calderys has always looked beyond specifications with a view to delivering performance and results that exceed operations expectations. Chemical composition is an important feature of Calderys’ products, but the company continues to look at other parameters that might deliver greater value to customers.

A complete refractory portfolio

Calderys envisions a bright future for PCPF domes. Despite this, it also recognises that there will always be customers for brick domes, and so will continue to offer domes as pressed bricks and as PCPF monolithics shapes. PCPF solutions are also applicable for other applications where bricks are being used as the refractory lining. This results in a much quicker installation, as PCPF solutions can be fabricated at a much larger size than bricks, limited solely by the ability of the workshop and job site to handle such materials. By increasing the size of the refractory blocks, there is less work required onsite for the construction of the lining, ultimately saving time, equipment, and manpower.

Gilles Theis, Ali Gueniche, Christoph Strupp and Chuck Baukal, John Zink Hamworthy Combustion, A Koch Engineered Solutions Company, detail how radiant wall burner technology can combat the issues associated with introducing hydrogen fuels into combustion systems.

H

ydrogen has the potential to be a very important fuel.¹ Global demand for it is increasing rapidly,² and interest in its use as a fuel continues to grow, mostly because it generates water when combusted, with little – if any – carbon dioxide (CO2), depending on how it is produced. Figure 1 shows that the more hydrogen that is present in a fuel, the less CO2 is produced.

In the past, using hydrogen as a fuel was only economical in certain applications. Reducing CO2 emissions and concerns about fossil fuel depletion are two major recent drivers for

considering fuels that contain a high percentage of hydrogen for more applications.³ The importance of hydrogen fuel depends on the way in which it is generated.4 Today, large-scale hydrogen production is carried out by steam methane reforming (SMR). SMR furnaces generate CO2 emissions. If those emissions are captured, this is referred to as blue hydrogen. Oil and gas producers are particularly well positioned to produce blue hydrogen, as natural gas is relatively low cost and because those producers have the infrastructure to produce hydrogen.5 If the CO2 is not captured, this then becomes

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grey hydrogen. Hydrogen made with renewable energy, such as wind or solar energy powering an electrolysis process, is referred to as green hydrogen.

While there is increased interest in using hydrogen as a fuel, high levels of hydrogen have been used in certain applications, such as boilers and fired heaters, for many years. For example, the off gas from ethylene crackers using ethane as the feedstock is 70 – 85% hydrogen, which is used as fuel for the cracking furnaces.

Figure 1. CO2 reduction with hydrogen added to various fuels (refinery fuel gas [RFG] = 20% hydrogen, 55% methane [CH4], 10% ethane, 10% propane, 5% butane). This assumes that no CO2 is produced whilst making the hydrogen.

There are important challenges to consider for new applications using a high volume of hydrogen in fuel.

These fuels may impact the combustion system, which means that it may not be a simple transition from existing hydrocarbon fuels to hydrogen fuels.

Hydrogen is an element whose natural state at atmospheric temperature and pressure is gaseous. In that state, it has low density and can easily leak from piping systems. Additionally, this fuel gas has many unique properties compared to common hydrocarbon fuels (see Table 1). It has a very high heating value on a mass basis, but a very low heating value on a volume basis because of its low density. Hydrogen’s low volumetric heating value results in much higher volumetric flow rates for a given heat input when compared to other common fuels. Higher volumetric flows result in higher fuel gas pressure.

Hydrogen also has a higher flame speed and ignition temperature compared to many common fuels. It has very low minimum ignition energy, so it is easily ignited with a spark. In addition to this, it has a relatively high adiabatic flame temperature and wide flammability limits compared to other fuels. It also requires considerably less combustion air per unit firing rate, and generates fewer combustion products (see Figure 2).

Potential advantages

Table 1. Properties of some common fuels Property

Hydrogen

Methane

Propane

Molecular weight

2

16

44

LHV (MJ/Nm³)

10.8

35.8

91.2

LHV (MJ/kg)

119.8

50

46.3

Adiabatic flame temperature* (˚C)

2048

1878

1904

Maximum flame speed (cm/sec.)

325

44.8

46.4

Flammability limit (vol% 4 – 74.2 5 – 15 air) * Based on 10% excess air; air temperature: 20˚C

Hydrogen combustion

2.1 – 9.5

An important potential advantage of using pure hydrogen as a fuel is that the combustion products do not contain CO 2. However, if hydrogen is generated by conventional SMR, then CO2 is a byproduct of the production process.

If hydrogen can be produced using renewable energy, it is possible to minimise or even eliminate CO2 generation, depending on the process. Another benefit is the absence of carbon in the fuel, which means that no soot (smoke), carbon monoxide (CO), or unburned hydrocarbons are emitted to the atmosphere.

Design considerations

While firing on pure hydrogen, a more conventional fuel such as natural gas may be used at start-up before switching to a high level of/pure hydrogen. This typically occurs when hydrogen is produced by SMR, for example.

Burners that are designed to fire on hydrogen are initially started up with natural gas, until the SMR process is established and hydrogen is being produced. This means that burners may need to be capable of firing on both natural gas and fuels containing a high level of hydrogen.

As the combustion characteristics between hydrogen and other fuels can be significantly different, this could complicate burner design concept and operation.

Potential challenges for premixed process burners Figure 2. Combustion air is required, and wet flue gases are produced, for blends of hydrogen in CH4 (15% excess air assumed).

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The actual impact on retrofitting existing burners is very dependent on the burner design. Traditional premix burner designs, as shown in Figure 3, use a venturi system and fuel gas pressure to aspirate combustion air into the furnace.

There are many potential challenges when using fuels with a high level of hydrogen in a premix burner: yy Hydrogen has a considerably higher flame speed, which makes it much more susceptible to flashback in a premix burner. Flashback describes the phenomena when undesired internal combustion takes place inside the burner, leading to fast destruction (see Figure 4). This means that existing premix technology, if not specifically designed for higher volumes of hydrogen, may not operate safely on a new high hydrogen concentration. yy Higher adiabatic flame temperature will have an influence on thermal NOx produced by the burner.

Evaluation on a case-by-case basis would be required to understand whether permit levels can still be met or exceeded with a fuel change. yy Increasing the fuel gas pressure within the burner when increasing the hydrogen content – as shown in Figure 4 – will generate a higher noise level. yy The aspiration of air by premixed burners is dependent on the fuel gas pressure. Figure 5 shows the fuel gas pressure on a constant fuel orifice for different fuels.

For the same fired capacity of the burner, there are considerable differences in fuel pressure. As such, air aspiration can be impacted.

Figure 3. JZHC PMS premix burner series.

To overcome these limitations, John Zink Hamworthy has developed the patent pending/patended WALFIRETM technology for process heaters (see Figure 6). Mainly targeted for use in high temperature applications such as ethylene cracking furnaces or reformers, the technology works as a diffusion style burner. The main distinguishing characteristic for a diffusion burner is that air and fuel gas are not premixed prior to combustion, but rather at the location where combustion is supposed to take place.

With such a design, flashback cannot take place, and no limitation of hydrogen concentration in the fuel gas Figure 4. Glowing venturi of a premix burner. applies.

To sustain and complete combustion, the adequate amount of combustion air needs to be supplied from the burner inside the firebox. As opposed to the premix burner, where the fuel gas pressure and fuel gas composition are the dominating factors when it comes to air aspiration (refer to Figure 5), WALFIRE technology uses the furnace’s negative pressure to aspirate and measure air. The burner’s operation becomes independent from fuel gas pressure Figure 5. Fuel gas pressure for same heat duty on different fuel compositions using constant gas orifice. and composition, which

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makes fuel quality adjustments easier during operation, as there is no longer a need to re-adjust air registers on the burner.

Case study: a petrochemical plant in the US

A customer in the US was experiencing high maintenance intervals and frequent flashback on their installation of ultra-low NOx (ULN) radiant wall burners in an ethylene cracking furnace. The design limitation on the radiant wall burners limited the overall amount of hydrogen in the fuel system, as the flashback conditions would worsen, and higher operator awareness and maintenance would be required.

Figure 6. 3D WALFIRE burner (left) and WALFIRE CFD velocity profile (right).

The ethylene cracker has a mixed firing concept, e.g. the firing equipment is a combination of ultra-low NOx, diffusion-type floor burners, and ULN premix radiant wall burners. As the floor burners do not limit the hydrogen concentration in the fuel mix, the customer decided to replace the wall burners with WALFIRE burners. The burners were designed in such a way that no modifications to the existing steelwork of the furnace, nor the fuel connection, were required (see Figure 7).

After successful installation, the furnace was started up together with John Zink Hamworthy Combustion service engineers onsite. Figure 8 (left) shows the WALFIRE radiant wall burners during light off. The heating curve of the furnace was followed, and consequently more burners were brought into service as the heater temperature increased.

Figure 8 (right) shows all of the wall burners in operation with the furnace at design load. During design operation of the furnace, flue gas was sampled in different locations inside the radiant firebox, as well as after the convection section of the heater. Analysis of this data showed that the ULN emissions performance of the fired equipment was identical to the historical data of the furnace.

After two years of successful operation of the unit, the customer decided to proceed with installation of additional heaters.

Conclusion

Using fuels with a large volume of hydrogen has the potential to dramatically reduce or eliminate CO2 emissions compared to conventional hydrocarbon fuels, depending on how the hydrogen is produced. Hydrogen has many unique characteristics, such as a higher flame speed and adiabatic flame temperature, compared to conventional fuels. However, there are many challenges and design issues that need to be considered when using these fuels.

New burner concepts, as detailed in this article, have proven to safely widen the operating window of radiant wall burners, while eliminating the risk of flashback and increased maintenance requirements.

Figure 7. WALFIRE furnace installation.

Figure 8. Furnace start-up (left) and design operation (right).

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References

1. BAUKAL, C., JOHNSON, B., HAAG, M., THEIS, G., and WHELAN, M., ‘Hydrogen: potential superfuel?’, Decarbonisation Technology, (November 2021), pp. 33 – 35.

2. ‘Hydrogen’, International Energy Agency, https://www.iea.org/fuelsand-technologies/hydrogen 3. NIKOLAIDIS, P., and POULLIKKAS, A., ‘A comparative overview of hydrogen production processes’, Renewable and Sustainable Energy Reviews, (2017), pp. 597 – 611.

4. DINCER, I., ‘Green methods for hydrogen production’, International Journal of Hydrogen Energy, (2012), pp. 1954 – 1971.

5. ROBINSON, J., ‘US oil, gas producers advantaged in blue hydrogen adoption: S&P Global Ratings’, S&P Global Platts, (23 April 2021), https://www.spglobal.com/platts/en/ market-insights/latest-news/electricpower/042321-us-oil-gas-producersadvantaged-in-blue-hydrogenadoption-sampp-global-ratings

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Marie-Laure Gelin, Howden, the Netherlands, explores the challenges associated with scaling up the use of hydrogen in support of the energy transition, and details a number of projects in which the company’s compression technologies have been used.

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t is becoming increasingly clear that hydrogen will play an essential role in accelerating the global energy transition. Global hydrogen production is forecast to more than double by 2030, following international public and private sector commitments. As a cleaner and secure fuel source, hydrogen has the capacity to be a powerful enabler in the transition away from fossil fuels, as it can function as both a carrier and converter of energy. However, in order to harness its full potential to decarbonise energy systems, the challenge of securing sufficient supply must be overcome by developing global and local energy infrastructure – quickly, with commercially-viable technologies.

The development of renewable energy sources, and the switch to a low-carbon energy carrier, is aimed at

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decarbonising the energy system across the heavy industry and mobility sectors. Integrating hydrogen into the energy system will allow for the deployment of renewable energy in power-to-X and gas-to-power settings, depending on hydrogen storage and distribution demand.

The role of compression

Compression is a key aspect in hydrogen applications, to facilitate the efficient movement of hydrogen across the value chain, from production to consumption. The compressor is the heart of the system; if it fails, production comes to a halt. As a global provider of mission-critical air and gas handling products, Howden has provided hydrogen compression technologies to refineries, chemical plants, and industrial premises for over 100 years.

To meet the challenges of energy demand and the ongoing energy transition, there is a need for further investment in hydrogen infrastructure. Scaling up is required to support the wider adoption of hydrogen, which would lend itself to the efficient decarbonisation of industries. Given hydrogen’s molecular structure and behaviour (it is explosive, highly volatile, and capable of altering mechanical properties of metals), further challenges present themselves on a larger scale and in new applications. The development of new hydrogen value chains – producing more and cleaner hydrogen, to be stored and distributed on demand to reach end users – is changing compression solutions’ circumstances, leading to different operating environments and specifications that will require investment.

Hydrogen can provide cost-effective and clean energy.

In order to reduce the overall cost per unit of hydrogen, economies of scale are necessary throughout production, distribution, and end use segments. The accommodation of larger flows will enable increased production, while greater pressures will allow for higher energy density. What positions hydrogen as an ideal energy carrier is the fact that it has a very high energy content per unit of weight (approximately 33 kWh/kg). However, it has low energy content per unit of volume at atmospheric conditions (90 g/m³), meaning that compression is mandatory in order to meet various industrial applications’ process conditions. Compression solutions are key to getting more energy out of the same volume.

Howden’s compression technology, based on reciprocating pistons and diaphragm compressors, enables

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large volumes of hydrogen and associated high pressures to obtain the required energy values, while managing pressure differences through the transfer and storage of hydrogen to prevent pressure build-up and leakages, and delivering the highest gas purity when required. Developments in materials, lubricants, seal and valve design – together with computer-aided analysis and design – have resulted in proven marginal improvements in efficiency, reliability, and extended mean time between maintenance (MTBM).

For efficient and reliable operations, it is imperative that the correct compressor technology is selected, based upon the following: yy Volumetric flow. yy Increased pressure. yy Static pressure range. yy Temperature range. yy Continuous or intermittent operation. yy Flow and pressure regulation requirement.

Figure 1. Howden’s reciprocating compressors in a refinery, providing support to a hydrogen process.

Figure 2. A containerised Howden diaphragm compressor for a renewable power-to-X application.

When scaling up for hydrogen applications, flow and pressure regulation, as well as capacity control technology, are paramount. This is due to the fact that today’s process requirements often operate on shorter timescales, as customers are producing more on demand. Based on Howden’s proprietary calculation software, compressor module selection software packages, and knowledge of leading standards for certifications previously used in the petrochemical industry, a customised solution can safely address the known low volumetric density energy of hydrogen, while benefitting from its gravimetric density energy.

Howden designs and manufactures compression solutions as individually-engineered packages to meet the specific demands of unique applications and requirements.

The compression matter requires early engagement to integrate seamlessly into the hydrogen value chain that it serves. Howden’s consultation services ensure that equipment design, mitigation, and administrative systems supporting the required process meet the proposed compression solution, with minimum CAPEX and OPEX, and maximum safety, performance and availability. As the hydrogen value chains are building and gaining in maturity, Howden will systematically and consistently address every stage of the compressor’s life cycle – from concept design to future maintenance and monitoring considerations.

Reliability, safety and continuous performance are vital requirements for hydrogen compressors. However, it is equally important to understand how to operate equipment efficiently. Insight software, coupled with an increase in remote operation/control and reduced experience onsite, has introduced an opportunity to integrate machine learning and Internet of Things (IoT).

In partnership with Microsoft, Howden has developed Howden Uptime with PTC – a digital platform that monitors rotating equipment performance and provides actionable insight with regards to operations. It can increase the life of assets by providing data to create a more predictive maintenance strategy and real-time communication options for customer support. Compressor performance is optimised using digital twin technology to avoid unplanned downtime, with expert advice close at hand.

Case studies Chile An e-fuel project in Chile uses the green hydrogen produced from wind farms, as well as carbon captured directly from the air, to produce e-methanol. Howden supplied technology, equipment and advisory services to the project to deliver approximately 900 000 l/yr of e-methanol in 2022, with future full-scale production units forecast to be ready by 2026. These will have the capacity to deliver 550 million l/yr of e-fuels.

Sweden Figure 3. The Howden team working on a compressor.

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At a fossil-free steel plant in Svartöberget, Sweden, Howden provided a storage compression solution. This initiative led

Introducing the Palladian Energy Podcast Series 1: Digitalisation in the oil and gas sector

produce 4.8 tpd of hydrogen, and refuel up to 600 hydrogen fuel cell vehicles, including large vehicles such as trucks and buses. The Daxing hydrogen refuelling station is part of the 200 000 m² Beijing International Hydrogen Energy Demonstration Zone.

France

Figure 4. Howden Uptime – the data-driven advantage and digital twin.

Figure 5. Howden’s Thomassen Compression Systems, developed and built in the Netherlands. to the development of a fossil-free value chain for the iron and steel industry, in order to address renewable hydrogen storage.

Specifically, the company supplied a high-pressure diaphragm compression package to integrate the storage cycle of hydrogen production. This included installation and commissioning of a packaged, three-stage diaphragm compressor. The reliability, efficiency and safety delivered by this solution meets large-scale hydrogen storage requirements, relative to the storage conditions and the evaluation of the amount of time during which the compression pressure remains at the desired level. The facility consists of 100 m³ of hydrogen storage, built in an enclosed rock cavern approximately 30 m below ground.

This offers a cost-effective solution to storing large amounts of energy in the form of hydrogen, at the required pressure.

HYBRIT supports the EU’s Hydrogen Strategy and its ambition to install at least 6 GW of renewable hydrogen electrolysers across the EU by 2024, and at least 40 GW by 2030.

This project has the potential to reduce Sweden’s total carbon dioxide (CO2) emissions by at least 10%. The steel industry currently accounts for approximately 7% of the world’s global carbon emissions, and so the creation of a zero-emission steel may help to reduce emissions from iron and steel production worldwide in the long-term.

China Howden supplied three hydrogen diaphragm compressor packages for use at Hypower’s Daxing hydrogen refuelling station in Beijing, China. The project has the capacity to

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As the move from large, centralised operations, to smaller-scale, decentralised applications has emerged, regional infrastructure is being developed in tandem – such as in Etrez, France, and in Wunsiedel, Germany – so that hydrogen production and supply can be closer, based on the possibility of local renewable energy generation to feed local industries and transport, as needed. The commercial viability of projects is at stake, and as hydrogen remains delicate to transport, the development of ecosystems (where possible) appears to be a good alternative. Here, there is demand for specific compression solutions.

As an illustration, the green hydrogen infrastructure in Etrez is a project that aims to demonstrate the feasibility of underground hydrogen storage to support the development of the hydrogen economy in Europe and ultimately lower the economy’s carbon usage. Located north-west of Bourg-en-Bresse, the critical demonstration facility intends to assess the role of underground storage in the hydrogen value chain. It will also assess industrial-scale green hydrogen production and storage in salt caverns and the technical and economic reproducibility of the process to other sites throughout Europe.

As part of the development, Howden will supply a containerised, high-pressure diaphragm compressor, as well as a tube trailer filling station. The reliability, efficiency and safety delivered by Howden’s compression solution aligns with the large-scale hydrogen storage and distribution system requirements, and will also meet injection, extraction and storage conditions.

The facility is one of France’s leading natural gas storage sites in salt caverns in terms of capacity. It will rely on local renewable energy (photovoltaic [PV], hydraulic) to produce 400 kg/d of green hydrogen – the equivalent of the consumption of 16 hydrogen buses. This is fully in line with the objective of lowering the economy’s carbon intensity. It also addresses the integration of underground storage into the hydrogen value chain.

Conclusion

Hydrogen can do so much, across many applications, and is currently emerging as an undeniable key player in our energy mix. Similarly, national ESG commitments favour an industry shift towards an environmentally and economically sustainable energy source such as hydrogen.

As individuals become aware of the environmental impact of economic activity on their surroundings, hydrogen has the opportunity to take on a major role in leading the fight against climate change. Fundamental understandings in the field of climate change, combined with Howden’s compression solutions with digital twin and augmented reality (Vuforia) technologies, will contribute to the emergence of a new energy production and distribution model supported by policies and investments.

Fabrice Billard, CEO, Burckhardt Compression Following a Master of Science at the Ecole Centrale in Paris, France, and a year in the Netherlands, Fabrice Billard started his career in 1994 with the Hay Group and the Boston Consulting Group (1999 – 2004). He then went on to join Sulzer, where he held various positions in Switzerland and Singapore at Sulzer Pumps Services, at Sulzer Chemtech as Head of the Mass Transfer Technology Business Unit, and as Chief Strategy Officer of the company. Fabrice joined Burckhardt Compression as President of the Systems Division in 2016, and has been CEO of the company since 1 April 2022.

Hydrogen offers huge potential for car and truck mobility nowadays. What prospects does it provide specifically, and what are the main persisting challenges and technological obstacles?

While hydrogen is indeed used in the industry, energy and transport sectors, mobility is the main application at present.

Hydrogen-powered cars and dedicated gas stations have been available for several years now. While the technical feasibility of vehicles is irrefutably clear, we’re now faced with new challenges, including: yy Cutting the cost per kg of hydrogen at the pump by a factor of approximately three, so that hydrogen as a product is as competitive as diesel or gasoline. yy Increasing the reliability and durability of all gas station components, including the dispenser and compressor. yy Changing the scale to make gas stations capable of delivering several tons of hydrogen daily in order to fuel a growing number of cars, not to mention the trucks that have only more recently become available on the market and offer a promising alternative to electric battery-powered trucks.

More specifically, the change in scale requires technological developments in the field of compressors: the challenge involves developing compressors with flow rates that are 10 times higher than current solutions, for pressures ranging from 500 to 900 bar. This is a huge task as the sensitivity of the vehicles’ fuel cells means the hydrogen must not be polluted with compressor lubricants. Two stand-out technological opportunities are currently being combined to remove this obstacle: yy Using industrial piston compressors to enable this scaling up at a competitive cost and with greater reliability

yy Developing high-pressure, lubricant-free sealing systems by combining existing technologies and new materials.

How is Burckhardt Compression positioning itself in this context? What solutions are you providing to the various stakeholders to address these challenges?

We’ve been compressing hydrogen at several hundred bars in industrial applications for 50 years and in (lubricant-free) mobility applications for over 20 years. We’ve got all the technological building blocks and a range of products to support hydrogen development for mobility, as well as for industry, green ammonia production or energy. We are producing, assembling and testing our compressors on all the major hydrogen markets: Europe, China, the US and South Korea.

Beyond the compressors field, we’re leveraging our skills to design complete systems that take our customers’ constraints and parameters into account, allowing us to optimise overall project costs.

Compression is an important link in the hydrogen production chain. At what level can you intervene in this context?

There are many applications that require compression solutions upstream of gas stations. The hydrogen may come from a hydrogen production and liquefaction plant. High-capacity compressors are needed to liquefy this hydrogen. Hydrogen stored in liquid form generates evaporation gas that has to be recompressed constantly.

While hydrogen is indeed produced by renewables and electrolysers, it also needs to be compressed for transport in pipelines or trucks. If hydrogen is to be transported over long

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distances, it can also be compressed so it can be combined with nitrogen to make ammonia and transported by ship – an operation that also requires hydrogen compression on an industrial level.

To sum up, hydrogen is very versatile and needs to be compressed in most applications. And, at our level, we’re intervening in all these applications by leveraging our expertise and our specific products.

You’re also interested in producing green ammonia, which can be used as a fuel for ships. Could you tell us more about this prospect?

While this is still an emerging application, it’s one that has huge potential for development. Ammonia is an alternative to liquid hydrogen for long-distance transport. What makes ammonia advantageous is the fact that it has a much higher energy density than liquid hydrogen and can be transported in liquid form at less extreme temperatures. But it is a toxic product, so mature and controlled processes like those used in transporting LNG are vital.

In its production and use chain, green ammonia is produced from hydrogen from renewable energy sources, which is compressed to combine with nitrogen to form ammonia. Once liquid, ammonia generates evaporation gases that usually need to be recompressed. This ammonia can then be used in this state in ship engines that are under development, or it can be separated back into hydrogen and nitrogen following transport.

This will enable green hydrogen production in countries and regions with high renewable energy generating capacity, such as Australia, the Middle East or South America, and then transportation to consumption centres in Europe, the US, China, South Korea or Japan. Several avenues are being explored at present. But there will certainly still be a considerable need for industrial compressors.

What are your hydrogen goals? What main projects are you currently working on?

The fight against climate change has caused things to speed up on the market over the last 18 months. But there are many unanswered questions even today, such as: in what form will the hydrogen be transported (gas, liquid, ammonia, etc)?

Meanwhile, several parameters have to be taken into account, such as the cost, the availability of renewable energies, the existence of the transport infrastructure, the speed of cost cutting for each technology, etc. Some scenarios are more favourable than others for compressor manufacturers in this regard. We’re considering all cases and would like to provide our customers with the full range of compression solutions required for the development of the hydrogen industry.

With this in mind, we’re working on three main projects.

In the field of ‘lubricant-free’ technology for higher and higher pressures and volumes, we’re developing a piston compressor that can supply a heavy-duty hydrogen station (for trucks). The first model has been launched with 550 bar of discharge pressure. This will be followed by a model for 900 bar.

We’re also working to increase the capacity of our lubricant-free compressors for hydrogen production and liquefaction plants.

Finally, as we’ve got decades of experience in evaporative gas treatment on vessels transporting LPG and LNG, we’re assessing technologies and products for liquid hydrogen and ammonia vessels.

At the same time, we’re still developing our plants and global supply chain to optimise the cost of these solutions and to help ensure that the hydrogen industry is an economic success. Our goal is to contribute to the sustainable development of the energy sector.

Figure 1. Burckhardt Compression solutions for hydrogen mobility and energy.

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Eric M. Rud, Eaton, USA, explains why reliable lube oil filtration is an important consideration in the production of hydrogen at very low temperatures, and details a project that the company completed under sub-zero conditions.

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ydrogen is fundamental to a global sustainable economy, as it is an environmentally-friendly, mobile energy source that can be stored, and is carbon neutral when used in manufacturing.

When utilised as a fuel, its only combustion product is water.

Beyond vehicles, many energy-intensive industries such as steelmaking can benefit from a combustion process that is free of carbon-containing pollutants.

Hydrogen also plays an important role in fertilizer production for farming. In the Haber-Bosch process, hydrogen and nitrogen form ammonia, which is the basis for a number of different fertilizers. Increasingly, hydrogen production is carried out at large-scale across the world to support the growing demand for fuel cells, transportation fuels, and a ready supply of gas that is critical to petroleum refining, food processing, metal treatment, and other industrial processes.

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In the production of hydrogen, all system components must perform at maximum capacity, especially under extreme weather conditions. Hydrogen is produced worldwide, including in regions where exceptionally cold winters are a challenge for the industry. One of these cold regions is also home to some of the largest fertilizer manufacturers in the world, and has seen numerous production facilities being built in recent years, including one in an area where the winter season tends to be harsh and long.

The compressors at this new hydrogen plant were used at temperatures ranging from as low as -58˚F (-50˚C).

This presented challenges for the filtration of the lube oil in the machinery, which is subject to a high degree of wear and tear. A team of Eaton filtration experts accepted the challenge of helping to place the plant into initial service on time.

Case study

Recently, an Eaton distributor engaged this new plant in discussions centred around reliable filtering of lube oil at sub-zero ambient temperatures. Understanding the steep challenges ahead, this distributor was seeking a solution that would help the fertilizer manufacturer to achieve its goals.

The challenge

Figure 1. Increasingly low temperatures can present challenges for the filtration of lube oil in machinery.

To ensure that hydrogen production would be safe and reliable even at the local temperatures, all components of the fertilizer plant were designed for such conditions.

Notably, the facility’s compressors needed to meet a special challenge: the plant had to manage the staged compression of hydrogen and other gases in production, at pressures of as high as 5075 psi (350 bar). Uncompromising reliability is vital under these conditions, as the entire production chain would quickly come to a halt if a compressor were to fail.

When the facility was planned, a decision was made to use a manufacturer with experience in building large-scale piston compressors, using engines delivering up to 1000 kW, as is required to produce hydrogen.

However, these higher requirements not only affect the machine as a whole, but also affect each individual component and all consumables. The lube oil is especially important. It must perform as intended, thereby mitigating the risk of compressor failure as much as possible. As in other critical industries, hydrogen producers rely on both high-quality oils and filters to effectively remove dirt particles.

The solution

Figure 2. The duplex configuration of the ASME-certified stainless steel pressure filter can be used for continuous operation. If a filter element is subject to maintenance, or the element must be replaced, the operator can redirect the flow through the filter from one side to the other.

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After careful evaluation, the Eaton team recommended a stainless steel duplex configuration filter solution for the fertilizer plant. Offering excellent filtration capacity and high intrinsic stability, this ASME-designed filter could be used in continuous operation in the plant, in compliance with the API STD 614 standard (lubrication, shaft-sealing, and oil-control systems and auxiliaries), thus providing durable protection for hydrogen production system components.

The selected filter works as a pressure changeover solution in numerous compressors, turbines, and large pumps that all function similarly. The medium enters the filter housing and is filtered by the filter element in one of two filter compartments. A pressure gauge displays the status of the filter element inside the active filter compartment.

If the element is especially dirty, or even blocked, the centre-mounted changeover ball valve permits the redirection of the flow to the second filter compartment. The contaminated filter element can then be flushed or replaced without interrupting the filtration process.

Making the filter suitable for use at frigid temperatures, however, was no simple task. Eaton’s engineers checked the filter, component by component, testing and

modifying it to meet the plant designer’s requirements.

A decision was made to use size 633 (29 in. [738 mm] long x 7.9 in. [200 mm] wide x 25.7 in. [652 mm] high) as the basis to reliably filter the required flow volume, as well as two NL filter elements made of glass fibre, with a 10 �m filter unit.

Due to the specific challenges of the environment, these modifications were necessary to ensure that all components of the duplex filter solution were suitable for extended use in sub-zero temperatures.

The gaskets of the filter presented a greater challenge. In addition to chemical stress placed upon elastomers by the lubrication medium, the seals are subject to vibration and mechanical stresses, as well as low ambient temperatures.

While a wide variety of materials are suitable for this type of gasket, only a few are fundamentally compatible with sub-zero conditions. As a result, finding the right combination of temperature and chemical durability was difficult, especially as the fertilizer producer insisted upon a safety buffer being designed into its facility. Ensuring that the selected filter would withstand temperatures of as low as -58˚F was paramount.

The Eaton team drew on the company’s years of partnership with leading gasket manufacturers to solve the problem. While the frigid temperatures proved challenging even for these experienced suppliers, discussions soon uncovered a low-temperature gasket material that would stand up to the harsh conditions of the job.

Eaton provided a non-functioning filter prototype to the compressor manufacturer that was built to exact

dimensional details. This allowed the manufacturer to install the compressor in the facility during the summer months by using the prototype, and to finish welding all of the pipelines while Eaton’s engineers were completing design adaptations to the functional filter. This helped to significantly reduce the time needed to build the facility.

The result Less than two months passed between the engineering request and the plant starting initial operations. The fertilizer producer received an effective filtration solution in a short time that not only met its specifications and all necessary ASME requirements, but also used components that can reliably withstand sub-zero temperatures. The hydrogen plant, with its complex production process, now benefits from continuous, uninterrupted filtration using an inline-mounted duplex filter that allows for simple and quick maintenance and is designed for long service life.

The construction of the plant was significantly accelerated by providing a prototype filter during the building phase, as work was able to continue while the production filter completed laboratory testing and validation.

Trial operation soon demonstrated that the compressors were capable of operating at an optimum level of lubrication.

The filtration of the lube oil using the adapted filter works as smoothly as planned, and the plant has remained in routine operation while supplying hydrogen – a basic element for fertilizers that contribute to global food supplies – on a daily basis.

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Wood to engineer Total Eren’s large-scale green hydrogen project

Green Hydrogen Systems receives electrolyser order from Logan Energy

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Gasunie and Vopak develop future open access hydrogen import terminal infrastructure

Alberta government to invest in the region’s hydrogen sector

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T

ood will provide conceptual engineering for Total Eren’s H2 Magallanes Project, a large-scale green hydrogen production facility to be located in the commune of San Gregorio, in the Magallanes region, Southern Chile.

Wood’s scope covers the development of a complete off-grid integrated energy complex to produce ammonia from green hydrogen – avoiding up to 5 million tpy of CO2. The engineering package will include up to 10 GW of installed wind capacity, coupled with up to 8 GW of electrolysis capacity, a desalination plant, an ammonia plant, power transmission and back-up, and port facilities to transport the green ammonia to national and international markets.

Wood’s studies will provide ground for Total Eren and the UMAG to deliver precise environmental impact assessments and risk analysis surrounding the H2 Magallanes Project, in accordance with the high environmental and social standards defined by the Chilean authorities.

asunie and Vopak have entered into a cooperation agreement. The aim is to jointly develop future terminal infrastructure projects that will facilitate the necessary imports of hydrogen into Northwest Europe via Dutch and German ports. Both parties have been working together on the Gate LNG terminal in the Port of Rotterdam, the Netherlands, which came into operation in 2011.

The cooperation agreement includes import projects for hydrogen through green ammonia, liquid organic hydrogen carriers, and liquid hydrogen technologies.

Vopak and Gasunie will focus on developing import infrastructure related to storage that enables further distribution of hydrogen to end users (e.g. by means of pipeline, vessels, road and rail) and contributes to the security of supply in Northwest Europe.

In April 2022, Gasunie, Vopak and HES International announced that they have joined forces to develop an import terminal for a hydrogen carrier in the port of Rotterdam, named ACE Terminal.

reen Hydrogen Systems has signed a supply agreement with Logan Energy to deliver electrolysis equipment for a project in Scotland.

The order includes the supply of two GHS HyProvide® A90 electrolysers with a combined capacity of 0.9 MW. The electrolysers will be deployed in a 40 ft container as a complete green hydrogen plant used in the ARBIKIE Distillery in Scotland. Green Hydrogen Systems will be responsible for delivering the electrolyser units, and will assist the project with onsite maintenance and remote monitoring and support, as part of a three-year service agreement.

The project will comprise a 1 MW wind turbine on the distillery’s farmland, which will export the electricity generated to Green Hydrogen Systems’ electrolysis plant.

When fully operational during 4Q22, the electrolysers will have the capacity to provide up to 389 kg/d of green hydrogen.

he Alberta government will invest US$50 million to create a Clean Hydrogen Centre of Excellence, which will drive innovation in the production, deployment and use of hydrogen across the economy. The centre is a pillar in Alberta’s Hydrogen Roadmap, which lays out the path to growing the provincial hydrogen economy and accessing global markets.

Alberta is already the largest hydrogen producer in Canada. Hydrogen is expected to be a US$2.5 – 11 trillion industry worldwide by 2050 and Alberta is ready to emerge as a leader in that global market.

The centre of excellence will support research, development and demonstration that will help companies and entrepreneurs that are building hydrogen technologies. It will bring together industry, researchers and small businesses from across the province to take technology that is in the early stages of development and prepare it for the move into the global marketplace.

Peak oil may be three years away, reports McKinsey & Co.

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he energy transition continues to gain steam, with oil demand projected to peak in this decade, perhaps as soon as 2025, according to new research by McKinsey & Co. This year’s ‘Global Energy Perspective’ launched when global energy markets were facing an unprecedented array of uncertainties, including the conflict in Ukraine. Nonetheless, the long-term transition to low-carbon energy systems continues to see strong momentum and, in several respects, acceleration.

Key findings of this year’s report include: the global energy mix is projected to shift towards low-carbon solutions, with a particularly strong role for power, hydrogen and synfuels; renewables are projected to grow 3x by 2050; hydrogen demand is expected to grow 4 – 6x by 2050, driven primarily by road transport, maritime, and aviation; and hydrogen and hydrogen-derived synfuels are expected to account for 10% of global energy consumption by 2050.

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