Hydrogen Technologies 303116296X, 9783031162961

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Fraunhofer-Forschungsfokus

Reimund Neugebauer Editor

Hydrogen Technologies Schlüsseltechnologien für Wirtschaft & Gesellschaft

Hydrogen Technologies

Reimund Neugebauer Editor

Hydrogen Technologies

Editor Reimund Neugebauer Fraunhofer-Gesellschaft München, Germany

ISBN 978-3-031-16296-1 ISBN 978-3-031-22100-2 (eBook) https://doi.org/10.1007/978-3-031-22100-2 © Springer Nature Switzerland AG, part of Springer Nature 2022 This work is subject to copyright. All rights are reserved by the Publisher, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publisher, the authors and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publisher nor the authors or the editors give a warranty, express or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publisher remains neutral with regard to jurisdictional claims in published maps and institutional affiliations. Printed on acid-free paper This Springer imprint is published by the registered company Springer Nature Switzerland AG, part of Springer Nature. The registered company address is: Gewerbestrasse 11, 6330 Cham, Switzerland

Contents

1

What the future is made of . . . . . . . . . . . . . 1.1 Introduction: Hydrogen as part of life . . . . 1.2 Scientific discovery and commercial use . . 1.3 Hydrogen as an energy carrier . . . . . . . . 1.4 Future prospects for hydrogen technologies

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The hydrogen economy: a land of opportunity . . . . . . . . . 2.1 The hydrogen economy: a land of opportunity . . . . . . . 2.2 Hydrogen-powered transportation as a solution and tool . 2.3 A climate-neutral industry and a closed carbon cycle . . . 2.4 Sector coupling—The next phase in the energy transition 2.5 Germany’s place in a global H2 economy . . . . . . . . . . 2.6 Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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The potential of a hydrogen economy: an economic and social perspective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 The economic relevance of hydrogen . . . . . . . . . . . . . . . . 3.2 Value creation potential for German industry . . . . . . . . . . . 3.2.1 The hydrogen economy value chain . . . . . . . . . . . . 3.2.2 Sales potential and job creation . . . . . . . . . . . . . . . 3.2.3 Promising value creation potential for the German industry sector . . . . . . . . . . . . . . . . . . . . . . . . . 3.3 The role of hydrogen in achieving climate and environmental targets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4 Public acceptance of hydrogen . . . . . . . . . . . . . . . . . . . . 3.4.1 Socio-political acceptance of hydrogen . . . . . . . . . . 3.4.2 Market acceptance . . . . . . . . . . . . . . . . . . . . . . . 3.4.3 Local acceptance . . . . . . . . . . . . . . . . . . . . . . . .

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Potential hydrogen demand and the economic situation . 3.5.1 Industry sector . . . . . . . . . . . . . . . . . . . . . 3.5.2 Transportation sector . . . . . . . . . . . . . . . . . 3.5.3 Heating sector . . . . . . . . . . . . . . . . . . . . . 3.5.4 Energy systems sector . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

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Hydrogen technologies in energy systems . . . . . . . . . . . . . . . . 4.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2 The role of hydrogen and synthetic energy carriers in energy systems by 2050 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3 Regional factors in supply and demand: possible locations for electrolyzers and renewable power generation . . . . . . . . . . . 4.3.1 Discussions surrounding the location of hydrogen supply and demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4 Direct hydrogen production from offshore wind energy from a European perspective . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.1 Discussion of the quantities involved . . . . . . . . . . . . 4.4.2 System comparison . . . . . . . . . . . . . . . . . . . . . . . 4.4.3 Economic assessment and comparison . . . . . . . . . . . 4.5 Requirements for the transmission grid in Germany . . . . . . . . 4.6 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Hydrogen technologies in industry . . . . . . . . . . . . . . . . . . . . . 5.1 Hydrogen as a material: steel industry . . . . . . . . . . . . . . . . 5.1.1 Hydrogen in crude steel production . . . . . . . . . . . . . 5.1.2 Smelting gases as a chemical resource (CCU) . . . . . . . 5.2 Hydrogen in the chemical industry . . . . . . . . . . . . . . . . . . 5.2.1 Green hydrogen overview: demand and potential . . . . . 5.2.2 Green hydrogen in refineries . . . . . . . . . . . . . . . . . 5.2.3 New methods of synthesizing basic chemicals with green hydrogen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3 Unavoidable industrial CO2 emissions: a future source of carbon 5.4 Hydrogen: an energy source for industry . . . . . . . . . . . . . . . 5.4.1 Supplying process heat from hydrogen: the basic principles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.2 Combustion of natural gas and hydrogen mixtures . . . . 5.4.3 Direct steam generation using hydrogen . . . . . . . . . .

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5.5 Hydrogen in the ceramic industry . . . . . . . . . . . . . . . . . . . 110 5.6 Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114 6

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Hydrogen technologies in mobility and transportation . . . . . . . . 6.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2 Hydrogen technologies for powertrains . . . . . . . . . . . . . . . . 6.2.1 Fuel cell drives . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2.2 Internal combustion engine-powered drives for hydrogen 6.2.3 On-board hydrogen storage . . . . . . . . . . . . . . . . . . 6.3 Synthetic hydrogen carriers . . . . . . . . . . . . . . . . . . . . . . . 6.3.1 Requirements for synfuels . . . . . . . . . . . . . . . . . . . 6.3.2 Types of synthetic fuels . . . . . . . . . . . . . . . . . . . . 6.3.3 The limits of synfuels . . . . . . . . . . . . . . . . . . . . . . 6.4 Infrastructure for hydrogen technologies—Hydrogen refueling stations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.5 Discussion by mobility sector . . . . . . . . . . . . . . . . . . . . . 6.5.1 Personal mobility . . . . . . . . . . . . . . . . . . . . . . . . 6.5.2 Public transportation . . . . . . . . . . . . . . . . . . . . . . 6.5.3 Freight transportation . . . . . . . . . . . . . . . . . . . . . . 6.5.4 Aviation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Hydrogen technologies in buildings . . . . . . . . . . . . . . . . . . . 7.1 Use cases and systemic integration . . . . . . . . . . . . . . . . . 7.2 Buildings and heat generators—Current status and trends . . . 7.3 Heat generators—Decentralized solutions . . . . . . . . . . . . . 7.3.1 Hydrogen boilers . . . . . . . . . . . . . . . . . . . . . . . 7.3.2 Fuel cells for CHP . . . . . . . . . . . . . . . . . . . . . . . 7.4 Hydrogen in urban districts . . . . . . . . . . . . . . . . . . . . . . 7.5 Hydrogen in gas networks—Blending and conversion . . . . . 7.5.1 Blending hydrogen depending on natural gas origin . . 7.5.2 Converting the natural gas network to 100 percent hydrogen . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.6 Cost and efficiency of a hydrogen-based decentralized heating supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

151 151 154 157 157 157 159 160 160

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Hydrogen infrastructures — Networks and storage . . . . . . . . . . 8.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.1 Hydrogen infrastructures as the foundation for sector coupling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1.2 Pure hydrogen networks . . . . . . . . . . . . . . . . . . . . 8.2 Construction of hydrogen network infrastructure . . . . . . . . . . 8.2.1 Blending hydrogen into natural gas networks . . . . . . . 8.2.2 Transforming gas transmission networks . . . . . . . . . . 8.2.3 Transforming gas distribution networks . . . . . . . . . . . 8.3 Transforming hydrogen islands and hydrogen valleys into connected networks . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4 Requirements for transforming infrastructure components . . . . 8.4.1 Effects of hydrogen on materials in the pipe system . . . 8.4.2 Consequences for the monitoring of pipe systems . . . . 8.4.3 Effects of hydrogen on compressor systems . . . . . . . . 8.5 What are the challenges and solutions involved in operating the infrastructure? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.5.1 Data and digital twins . . . . . . . . . . . . . . . . . . . . . . 8.5.2 Mathematical models . . . . . . . . . . . . . . . . . . . . . . 8.5.3 Decision support tools/Smart gas networks . . . . . . . . . 8.6 Geological storage options . . . . . . . . . . . . . . . . . . . . . . . 8.7 Other storage options . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.7.1 Compressed gas storage . . . . . . . . . . . . . . . . . . . . 8.7.2 Liquid hydrogen . . . . . . . . . . . . . . . . . . . . . . . . . 8.7.3 Binary metal hydrides . . . . . . . . . . . . . . . . . . . . . 8.7.4 Liquid organic hydrogen carriers (LOHC) . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Producing hydrogen through electrolysis and other processes . 9.1 Hydrogen production processes . . . . . . . . . . . . . . . . . . 9.2 Hydrogen production by electrolysis . . . . . . . . . . . . . . . 9.2.1 Fundamentals of water electrolysis . . . . . . . . . . . . 9.2.2 Alkaline water electrolysis . . . . . . . . . . . . . . . . . 9.2.3 PEM electrolysis . . . . . . . . . . . . . . . . . . . . . . . 9.2.4 AEM electrolysis . . . . . . . . . . . . . . . . . . . . . . 9.2.5 High-temperature steam electrolysis . . . . . . . . . . . 9.2.6 Co-electrolysis of water and carbon dioxide . . . . . . 9.2.7 High-temperature ceramic-based proton-conducting electrolysis . . . . . . . . . . . . . . . . . . . . . . . . . .

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Other innovative processes for hydrogen production . . . . . . 9.3.1 Steam reforming with carbon capture and utilization . 9.3.2 Methane pyrolysis . . . . . . . . . . . . . . . . . . . . . . 9.3.3 Photocatalytic systems . . . . . . . . . . . . . . . . . . . 9.3.4 Biological procedures . . . . . . . . . . . . . . . . . . . . 9.4 Summary and outlook . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Fuel cell technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2 Low-temperature polymer electrolyte membrane fuel cells . 10.2.1 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2.2 Stack components . . . . . . . . . . . . . . . . . . . . . 10.2.3 System components . . . . . . . . . . . . . . . . . . . . 10.2.4 Operational management . . . . . . . . . . . . . . . . . 10.2.5 Service life and degradation . . . . . . . . . . . . . . . 10.3 High-temperature polymer electrolyte membrane fuel cells 10.3.1 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3.2 Stack components . . . . . . . . . . . . . . . . . . . . . 10.3.3 System components . . . . . . . . . . . . . . . . . . . . 10.4 Direct methanol fuel cells . . . . . . . . . . . . . . . . . . . . . 10.4.1 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4.2 Stack components . . . . . . . . . . . . . . . . . . . . . 10.4.3 System components . . . . . . . . . . . . . . . . . . . . 10.5 Alkaline fuel cells . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5.1 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . 10.6 Solid oxide fuel cells . . . . . . . . . . . . . . . . . . . . . . . . 10.6.1 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . 10.6.2 Stack components . . . . . . . . . . . . . . . . . . . . . 10.6.3 System components . . . . . . . . . . . . . . . . . . . . 10.6.4 Operational management . . . . . . . . . . . . . . . . . 10.6.5 Service life and degradation . . . . . . . . . . . . . . . 10.7 Molten carbonate fuel cells . . . . . . . . . . . . . . . . . . . . 10.7.1 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . 10.7.2 Stack components . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Production of PEM systems, upscaling and rollout strategy . 11.1 Fuel cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.1.1 Production elements . . . . . . . . . . . . . . . . . . . 11.1.2 Technology optimization . . . . . . . . . . . . . . . . 11.1.3 Manufacturing processes . . . . . . . . . . . . . . . . 11.1.4 Automation . . . . . . . . . . . . . . . . . . . . . . . . 11.1.5 Continuous process management . . . . . . . . . . . 11.1.6 Economies of scale . . . . . . . . . . . . . . . . . . . 11.1.7 Comparison of selected BPP production processes 11.1.8 Rollout strategy . . . . . . . . . . . . . . . . . . . . . 11.2 Electrolyzers . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.2.1 Cost components and cost reduction potential . . . 11.2.2 Technologies . . . . . . . . . . . . . . . . . . . . . . . 11.2.3 Scaling . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.2.4 Rollout strategy . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Standardization, testing and certification . . . . . . . . . . . . . . . 12.1 The importance of standardization for hydrogen technologies . 12.2 Standardization overview: stakeholders and processes . . . . . 12.2.1 Terminology and processes . . . . . . . . . . . . . . . . . 12.2.2 Standardization in Germany . . . . . . . . . . . . . . . . . 12.2.3 International standardization . . . . . . . . . . . . . . . . 12.3 Existing standards for hydrogen technologies . . . . . . . . . . . 12.3.1 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.3.2 Production . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.3.3 Transportation and infrastructure . . . . . . . . . . . . . . 12.3.4 Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.3.5 Transportation and industry . . . . . . . . . . . . . . . . . 12.3.6 Heating sector . . . . . . . . . . . . . . . . . . . . . . . . . 12.3.7 Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.3.8 Fuel cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.4 Use cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Accident prevention and service life — Materials . . . . . . . . . . 13.1 Motivation: Hydrogen as an energy carrier . . . . . . . . . . . . 13.2 Accident prevention and service life: Hydrogen embrittlement 13.3 Materials and mechanisms: Steel materials . . . . . . . . . . . .

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13.4 Experimental material testing and theoretical material modeling 349 13.5 Discussion: Hydrogen readiness . . . . . . . . . . . . . . . . . . . . 353 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 354 14

Sensors and safety . . . . . . . . . . . . . . . . 14.1 Introduction . . . . . . . . . . . . . . . . . 14.2 Challenges . . . . . . . . . . . . . . . . . . 14.3 H2 sensor technologies and applications 14.3.1 Established sensors . . . . . . . . 14.3.2 MEMS-based sensors . . . . . . . 14.3.3 Optical sensors . . . . . . . . . . . 14.4 Sensors for non-destructive testing . . . 14.5 Summary and outlook . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . .

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Digitalization and simulation of hydrogen technologies . . . . . . 15.1 Introduction and overview . . . . . . . . . . . . . . . . . . . . . . . 15.2 Future hydrogen demand and the integration of hydrogen into energy markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.3 Modeling and simulating hydrogen pipelines . . . . . . . . . . . 15.3.1 Stationary models . . . . . . . . . . . . . . . . . . . . . . . 15.3.2 Transient models . . . . . . . . . . . . . . . . . . . . . . . . 15.3.3 Challenges and outlook . . . . . . . . . . . . . . . . . . . . 15.4 Integration into process engineering methods . . . . . . . . . . . 15.5 Optimized stack design . . . . . . . . . . . . . . . . . . . . . . . . 15.5.1 Model-based simulation approaches . . . . . . . . . . . . 15.5.2 Bipolar plate design . . . . . . . . . . . . . . . . . . . . . . 15.6 Scaling and flexibilization through digital transformation . . . 15.7 Simulation-based design of hydrogen infrastructures . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Hydrogen technologies in the energy system: the international perspective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.1 The importance of green hydrogen . . . . . . . . . . . . . . . . 16.2 An international hydrogen economy . . . . . . . . . . . . . . . 16.2.1 The Green Deal . . . . . . . . . . . . . . . . . . . . . . . 16.2.2 The Paris Agreement . . . . . . . . . . . . . . . . . . . .

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16.3 Hydrogen strategies and road maps . . . . . . . . . . . . . . . . . 16.3.1 Strategy developments in chronological order . . . . . . 16.3.2 Strategy papers by non-government institutions . . . . . 16.4 The driving forces behind the hydrogen economy . . . . . . . . 16.4.1 Environmental concerns . . . . . . . . . . . . . . . . . . . 16.4.2 Economic concerns—exports, industry, prosperity . . . 16.4.3 Energy-related concerns . . . . . . . . . . . . . . . . . . . 16.5 International trade and partnerships . . . . . . . . . . . . . . . . . 16.5.1 Europe—Middle East and North Africa (MENA) . . . . 16.5.2 Germany—West Africa . . . . . . . . . . . . . . . . . . . . 16.5.3 Australia—Japan/Germany . . . . . . . . . . . . . . . . . 16.6 Importing green hydrogen and synthesis products: external conditions and design issues . . . . . . . . . . . . . . . . . . . . . 16.6.1 The market for imports . . . . . . . . . . . . . . . . . . . . 16.6.2 Renewable energy potential and imports . . . . . . . . . 16.6.3 Sustainability . . . . . . . . . . . . . . . . . . . . . . . . . . 16.6.4 Market mechanisms and pricing . . . . . . . . . . . . . . 16.6.5 Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.6.6 International collaboration . . . . . . . . . . . . . . . . . . 16.6.7 Local expertise . . . . . . . . . . . . . . . . . . . . . . . . . 16.6.8 Technological sovereignty . . . . . . . . . . . . . . . . . . 16.7 Global production potential for green hydrogen and synthetic fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.7.1 Factors affecting analyses of potential . . . . . . . . . . . 16.7.2 Key findings . . . . . . . . . . . . . . . . . . . . . . . . . . 16.7.3 Global PtX potential . . . . . . . . . . . . . . . . . . . . . 16.7.4 Location costs . . . . . . . . . . . . . . . . . . . . . . . . . 16.7.5 Results for individual energy carriers . . . . . . . . . . . 16.8 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Hydrogen technologies: outlook and future possibilities . . . . . 17.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.2 Offshore hydrogen production—options for covering future hydrogen demand . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.2.1 Hybrid offshore hydrogen production . . . . . . . . . . 17.2.2 Self-sufficient offshore hydrogen production plants . 17.2.3 Impact of electrolysis technologies . . . . . . . . . . . 17.2.4 Lighthouse projects for offshore hydrogen production

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Contents

17.3 Working toward climate neutrality in the basic chemical industry 17.3.1 Working toward climate neutrality in methanol synthesis and its downstream chemical processes . . . . . . . . . . . 17.3.2 The road to climate-neutral Fischer-Tropsch synthesis . . 17.3.3 How recycling plastic material can help . . . . . . . . . . . 17.4 Evolutionary manufacturing technologies for electrolyzers . . . 17.4.1 Current situation . . . . . . . . . . . . . . . . . . . . . . . . . 17.4.2 Main challenges . . . . . . . . . . . . . . . . . . . . . . . . . 17.5 Possible development paths for a systemic road map outlining radical upscaling measures for electrolyzer production . . . . . . 17.5.1 Route A—upscaling existing products . . . . . . . . . . . 17.5.2 Route B—evolving design and manufacturing technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.5.3 Systemic road map . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Glossar . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 467

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What the future is made of

Reimund Neugebauer President of the Fraunhofer-Gesellschaft 1.1 Introduction: Hydrogen as part of life Hydrogen is the most abundant element in the universe. It has the lowest atomic mass of any element, consisting of just one proton and one electron, and is thus located on the upper left corner of the periodic table. Under normal conditions, it occurs on Earth almost exclusively in chemical compounds and as molecular hydrogen, where two atoms have bonded to form H2 . Hydrogen is an essential requirement for forming and sustaining life as we know it. Plants and some microorganisms split water using energy from the sun. Of the products produced during this reaction, the oxygen is released to the air, while the hydrogen is used directly by the cell to build organic substances from carbon dioxide that has been captured. The simplified equation for photosynthesis is as follows: 6 H2 O C 6 CO2 C solar energy D 6 O2 C C6 H12 O6 Put into words, this means that solar energy is used to convert water and carbon dioxide into oxygen and glucose. The glucose serves as a raw material for other organic substances, which are then used to form cells or store energy. Photosynthesis thus stores energy from sunlight in organic material for terrestrial life—whether for the organism carrying out photosynthesis itself or for the benefit of all the other organisms that feed on it. Living things rely on their metabolisms, which means consuming energy. Plants, animals and other organisms use the stored energy to carry out their life processes. Humans need energy, too—and not only for our metabolisms. We are constantly tapping into new sources of energy and using them intensively. In the © Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_1

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What the future is made of

context of a growing world population in need of food and other supplies, this is an advantage. However, increasing energy consumption comes with undesirable consequences such as depleted resources, destruction of habitats and damage to our climate. This means we need to look for environmentally compatible and sustainable ways to meet our energy needs. It is therefore worth taking a closer look at the natural processes that have already been evolving over many millions of years to optimize efficiency, lasting benefits and sustainable effects. The negative effects of organic fuels such as straw, wood, wax and fish oil on the environment were limited. As the population increased, however, the need for new energy sources such as coal, crude oil and natural gas grew in turn. The demand for ores also rose, as the metals produced from these accelerated the rate at which energy was procured. Today, we know that these raw materials must be used prudently in order to minimize the harm caused to people, the climate and the environment. Hydrogen plays a key role here.

1.2 Scientific discovery and commercial use The discovery of “inflammable air” by British scientist Henry Cavendish in 1766 marked one of mankind’s first interactions with gaseous hydrogen. By dissolving iron in dilute sulfuric acid, Cavendish produced a flammable substance that resembled air—however, he did not realize that he was dealing with a chemical element. This was only discovered by French chemist and scientist Antoine Laurent de Lavoisier following further experimentation. In 1785, his quantitative analyses also proved that water is composed of hydrogen and oxygen. Lavoisier also coined a name for the newly discovered element: “Hydrogenium”, which directly translates as “maker of water”. This simply became known as “hydrogen” in English. Thereafter, basic research began into the scientific and technical importance of this newfound element. There are over 40 million known substances in organic chemistry, a field that is defined as all chemistry involving carbon atoms; almost all of these 40 million substances contain hydrogen. Many of these compounds have a major influence on our health, for example in the form of food, cosmetics and medicines, as well as on other aspects of our everyday needs such as clothing, furniture, dyes, flavorings and textiles. Our energy supply for heating, mobility and electronics is largely dependent on fossil-based hydrocarbons. However, we do not only need these for our everyday lives. All known living organisms are based on carbon-hydrogen compounds and need water to metabo-

1.3

Hydrogen as an energy carrier

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lize. There are no known life forms that do not contain hydrogen in their chemical makeup. Acids and bases, which are essential to chemistry, function by releasing or absorbing hydrogen ions. Large-scale industrial processes involving hydrogen, such as the Haber-Bosch process for producing ammonia from hydrogen and nitrogen, have had an enormous effect on humans. The large-scale production of ammonia at the beginning of the last century enabled the production of fertilizers such as urea and ammonium nitrate. This marked a revolution in both applied chemistry and agriculture, laying the foundation for food supplies to a major part of the contemporary world population.

1.3 Hydrogen as an energy carrier Initial tests with hydrogen quickly showed that the gas held great potential: Its high reactivity means that, when activation energy is provided through combustion, molecular hydrogen will combine with oxygen to form water, while also releasing thermal energy. If they are mixed with the correct ratio, the combustion is explosive (oxyhydrogen). Making technical use of this energy has always been an exciting prospect, but it is difficult to put into practice. The production of hydrogen became easier in 1799, when the Italian physicist Alessandro Volta developed the first usable and efficient battery, the voltaic pile. Just a year later, British researchers William Nicholson and Anthony Carlisle carried out the first electrolysis of water. The German physicist Johann Wilhelm Ritter determined that the resulting gases were hydrogen and oxygen. Based on these findings, researchers further developed their knowledge of electrochemistry, particularly electrolysis. Among the climate-friendly (that is to say, carbon-neutral) production methods for hydrogen, water electrolysis is considered to be a particularly advanced and promising option. Interestingly, in terms of energy technology, the opposite reaction can also be used under certain conditions: chemical energy from hydrogen and oxygen can be directly converted to electrical energy in a fuel cell. German-Swiss chemist and physicist Christian Friedrich Schönbein discovered and verified this principle in 1838. Thanks to this discovery, it became possible to store electrical energy obtained through electrolysis as hydrogen and oxygen, and to use the captured gases later to produce energy. One initial challenge in storing hydrogen for the longer term was preventing the gas from escaping from containers—due to their small size, the molecules can diffuse through materials. Today, special surface coatings can prevent this. A further challenge was the fact that hydrogen must be stored under high pressure. To

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What the future is made of

make it easier to handle, Fraunhofer researchers have developed a “power paste” in which the gas is absorbed and can be transported, transferred and released again without the need to be under pressure. Last but not least, there had to be a simple way of harnessing the conversion of hydrogen and oxygen to water. Today, fuel cells can control this reaction as required and use it to generate both electricity and heat. Additionally, oxygen and hydrogen create an ideal propulsion system for rocket engines due to their low weights and explosive reaction, which releases large amounts of energy.

1.4 Future prospects for hydrogen technologies Even decades ago, the enormous range of possible applications encouraged visionaries and researchers to consider an energy economy based on hydrogen. As early as the 19th century, the French author Jules Verne, whose technological ideas were ahead of his time, believed this element would be the energy carrier of the future. In 1923, the British scientist John Burdon Sanderson Haldane developed the basic principles of a hydrogen economy. In the 1970s and 1980s, this field gained momentum due to pressure from multiple energy crises and renewable energy production methods becoming ever more efficient. In the subsequent years, energy generated using decentralized photovoltaics, wind power and hydropower became available at lower and lower prices. This meant that storing hydrogen produced through electrolysis—and in so doing, creating the hydrogen economy—became a viable option. Fraunhofer researchers, for example, achieved a record-breaking efficiency of 46 percent by using multi-junction solar cells; this high efficiency makes storing surplus energy in the form of hydrogen an attractive option. Further successes in optimizing the suitable technologies also led to a focus at the political level on promoting a sustainable and economical hydrogen economy: In 2020, the German federal government set out its National Hydrogen Strategy (NWS), which illustrates how Germany can use green hydrogen in industry and in transportation and energy systems in order to meet climate protection goals, attain competitiveness and tap into new markets. As part of the European Green Deal, the European Union has also formulated specific goals to efficiently set up the infrastructure of the hydrogen economy. Hydrogen plays a major role in defossilizing industrial processes in order to achieve climate neutrality. A key requirement for establishing a goal-oriented, sustainable hydrogen economy is having a global, systematic approach across the entire value chain, with an openness to using different technologies. The FraunhoferGesellschaft aims to make a decisive contribution to achieving this. Fraunhofer

1.4 Future prospects for hydrogen technologies

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expertise comprises both research into the materials and systems associated with hydrogen, including their production, transportation and use, as well as the crosscutting topics of safety and service life. To reduce the cost of electrolysis, thereby enabling the widespread use of hydrogen technologies, Fraunhofer researchers are developing new membrane materials, extending the service life of cells using an anti-corrosion coating and conducting service life tests. With applied research and scientific excellence, the Fraunhofer-Gesellschaft can act as an innovation driver for this transition and support the transfer of hydrogen technologies to industry across all sectors. If, in the future, our society is to be based around technology, a major—or perhaps key—task will be ensuring a secure, efficient, environmentally friendly supply of energy that the public can support in the long term.

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The hydrogen economy: a land of opportunity

Simon Harst  Bernhard Aßmus  Angelika Hackner  Anja Haslinger Fraunhofer-Gesellschaft Abstract

Hydrogen offers a unique degree of potential due to its extensive versatility, be it as a storage medium for electricity produced from renewable energies or as a synthetic basic material or fuel. For this reason, hydrogen technologies are key to a carbon-neutral economy: They can provide solutions for further expanding renewable energy supplies, climate-neutral industry processes and sustainable mobility. For Germany and Europe alike, they represent an opportunity to maintain industrial value creation and secure export opportunities. The Fraunhofer-Gesellschaft possesses knowledge and experience ranging across the entire value chain of the hydrogen economy, encompassing materials and system development, production, the upscaling of systems, applications in the energy sector, emission-intensive industry processes and mobility, as well as practical, overarching issues such as safety, standardization and service life.

2.1

The hydrogen economy: a land of opportunity

Hydrogen is the smallest molecule and the most abundant element in the universe. However, it only rarely occurs naturally on earth, and in small quantities at that. If humanity wants to harness hydrogen, we must manufacture it, which takes highly sophisticated technology and enormous volumes of energy. We have already been doing this for many years to produce hydrogen for use in refineries and for manufacturing fertilizers and methanol, mostly using natural gas as the starting substrate [1]. © Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_2

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But why is hydrogen expected to play a key role in our future lives and economy? Why have wave after wave of authors enthused about an imminent “hydrogen age” for decades? Why is it that after every disappointment, the fields of research and technology have picked up the pieces and continued their attempts to make the necessary processes ready for use and market entry? The answer can be found in the growing concern around the issue of sustainability, and the search for solutions to make our society climate neutral. These factors have brought about a renaissance for hydrogen, because it is becoming increasingly clear that the light gas can support these efforts in a wide variety of ways. Hydrogen can be used directly as a fuel or converted into electrical energy using fuel cells. Both methods produce no exhaust gases, only water vapor. This would make hydrogen an environmentally friendly source of energy. However, for this to work, the hydrogen must be produced in a climate-neutral manner. Most methods for achieving this are based on water electrolysis, where electrical energy is used to break water down into oxygen and hydrogen. If the electricity is sourced from renewable energies, then the production process is climate neutral. The product is referred to as “green hydrogen”. The overall vision of a hydrogen economy also includes other processes which can be summarized by the keyword “power-to-X”. In these processes, chemical substances are synthesized from hydrogen and, normally, carbon dioxide (CO2 ); green electricity can also be used in this process. They can produce fuels, known as synfuels, or basic chemicals, which can serve as source materials for synthesizing polymers, thereby replacing fossil raw materials. The Fraunhofer-Gesellschaft is Europe’s largest applied research organization and, as such, is perfectly poised to address these major societal challenges. From an early stage, Fraunhofer has grappled with the technical issues involved in converting energy systems to a more sustainable format and systematically expanded its expertise and resources capacities, from establishing and incorporate suitable institutes (including the Fraunhofer Institutes for Solar Energy Systems ISE, for Environmental, Safety and Energy Technology UMSICHT and for Wind Energy Systems IWES) to founding the Fraunhofer Group for Energy Technologies and Climate Protection at the beginning of 2021. As an efficient, high-profile consortium, this group has become a worldwide leader in energy transition research. Many of its institutes are making significant contributions to the energy transition, as well as resource-saving production processes and mobility. So, it is not a surprise that H2 research has been a part of Fraunhofer for decades. In 1994, a German Federal Parliament commission for the protection of the earth’s atmosphere recommended using hydrogen produced via electrolysis as a means of storing chemical energy. The commission also noted that it would be worth giving

2.2 Hydrogen-powered transportation as a solution and tool

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fuel cells special attention and making rapid efforts to develop them further [2]. At that time, Germany’s first energy self-sufficient solar house was already two years old and equipped with electrolysis and fuel cell systems from Fraunhofer ISE [3]. Below, we will briefly examine the opportunities that a hydrogen economy could open up in the abovementioned fields of application, and the course that must be set at the beginning of the 2020s to make them a reality.

2.2

Hydrogen-powered transportation as a solution and tool

When people talk about hydrogen applications, hydrogen-powered vehicles are often the first thing that comes to mind. The idea of a fuel that is produced in an environmentally friendly way and emits nothing but water vapor when used seems close to a fairytale solution at a time when our growing individual levels of mobility are accompanied by constant discussions about our carbon footprints. However, hydrogen-based, climate-neutral mobility is just one of many possible uses of hydrogen. In fact, the promising solutions that hydrogen could deliver go far beyond the field of future car transportation. In that field, it is in competition with batterypowered electromobility, which can claim the advantage of using electricity more efficiently. For this reason, in urban and short-distance driving, using electrical energy directly with a battery-powered vehicle may be the better alternative. Using hydrogen as an energy carrier in transportation would be a complementary solution, as hydrogen only truly shows its advantages over direct electrical engines when it comes to transporting large loads or covering large distances. That is why, in the medium term, hydrogen-powered fuel cell engines are bound to prevail in long-distance and heavy goods transportation and on non-electrified railway lines. Weight savings, short refueling times and long ranges make them the preferred option here. However, hydrogen-powered cars do still present many opportunities. For example, they can allow the traditionally strong German automotive and mechanical engineering industries to maintain their leading global position during the transition to a climate-neutral economy. Not only that, but they can also help introduce people to the idea of a hydrogen economy and help accelerate the transformation in two ways. The first is that fuel-cell-powered vehicles would constitute a mass market. This means that the technologies they are based on could reach marketable prices more quickly through economies of scale. This would also facil-

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2 The hydrogen economy: a land of opportunity

itate the use of these technologies in other sectors. Secondly, as a fuel, hydrogen will reach price parity with fossil fuels in the field of automotive transportation in the relatively near future—much earlier than it will become cost-efficient to use in industry, for example. The demand for increased hydrogen production for transportation will in turn make innovation cycles shorter, which means that it will more quickly become economically viable to use hydrogen in other contexts as well. In 2019, the European consortium Fuel Cells and Hydrogen Joint Undertaking developed an ambitious road map for the European hydrogen economy. One of the calculations outlined in the road map stated that, by 2040, 15 to 20 percent of cars and vans should be fuel cell vehicles [4]. The rest of the world has also long since recognized the key role of transportation in the hydrogen economy, and many governments want to seize upon the opportunities it offers for their domestic economies. Japan and South Korea, for example, are focusing on the export opportunities for hydrogen cars that their national industries could capitalize on, using strategic programs to gain a favorable starting position. Japan calculates that, by 2030, it will already have up to 800,000 fuel cell vehicles on its domestic roads. By then, Japanese market researchers predict that the global market volume will have increased thirty-fold to over 19 billion US dollars compared to 2018 [5]. Transportation and travel do not only take place over land. Once we take shipping and aviation into consideration in our calculations, it becomes clear that mobility requires hydrogen. A battery-powered ship might work in the leisure sector, but cruise ships or container ships require long-distance drive systems and fuels with high energy density. This will involve liquid fuels synthesized from hydrogen in most cases. Aviation groups have long been planning to use hydrogen and synfuels to make their aircraft climate neutral. Fraunhofer institutes are developing the hydrogen-based drive and refueling systems required for this. In one large initiative and a number of regional clusters, they are designing manufacturing technologies for the mass production of fuel cells and developing sensor, control and testing technology for integrating them into the overall vehicle system. They are researching efficient, large-scale production methods for synthetic fuels made from hydrogen and developing mobility strategies for shipping and aviation based on hydrogen and synfuels. Meanwhile, other initiatives are using the latest technological findings to calculate the ecological and carbon footprints of various drive systems and demonstrate the options for future mobility. These Fraunhofer technologies always take into account the issues of safety, robustness, durability and cost-effectiveness.

2.3 A climate-neutral industry and a closed carbon cycle

2.3

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A climate-neutral industry and a closed carbon cycle

For important sectors of the basic industry, too, there is no alternative to using hydrogen. Of course, companies in this industry are also faced with the challenge of reducing the energy-related emissions of their plants, precisely because many of their processes are enormously energy-intensive. In addition, large amounts of CO2 are produced in basic industry as a result of chemical conversion processes during production: these are known as “process-related” emissions. Hydrogen helps to replace these processes with climate-neutral processes in a variety of ways. The steel industry is currently a particular focus of discussion. To date, coke has normally been used in industry as a reducing agent when reducing iron ore to crude steel in blast furnaces. In the process, the carbon is oxidized to form CO2 and huge volumes of the greenhouse gas are emitted. If the ore was reduced using hydrogen instead, the process would only produce water vapor, not CO2 . The German steel industry would require around 80,000 GWh of hydrogen1 per year [6]. The first large-scale tests have begun with the aim of one day achieving “green” steel. But another method is available for the transitional period while current blast furnace models are still in use. Smelting gases, which have a high concentration of carbon monoxide (CO) and CO2 , can be used to manufacture source materials for chemical production in power-to-X processes. Methanol and higher alcohols can be produced from carbon oxides and green hydrogen. This process not only reduces the carbon footprint of steel production, but also helps the chemical industry, which is expected to replace the fossil-based source materials in its products with alternatives. All plastics and organic chemicals are based on the element of carbon. Until now, natural gas and crude oil have been the most common raw materials used in production. In the future, however, this innumerable list of substances will be produced from CO2 in a step-by-step procedure very similar to the processes of the natural world. This will then remove the CO2 from the global material cycle and will close the carbon cycle. However, the process of capturing CO2 from the air is extremely energy intensive. Nature shows us how this can be done in plants using sunlight. But plant-based, renewable raw materials will not suffice to meet humanity’s need for organic chemicals and polymers. This is because the cultivation areas worldwide are limited, and food production must be given prior1 In the relevant literature, hydrogen volumes are indicated in different units, for example as mass, in standard cubic meters or according to the energy content. The latter is the most common form internationally and has been adopted for this text. Hydrogen has an energy density of around 33 MWh/t.

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2 The hydrogen economy: a land of opportunity

ity. As a result, the chemical industry will also require green hydrogen in the future to capture gaseous CO2 and convert it into basic substances. As mentioned above, these processes can be combined with steel production, which makes it possible to implement power-to-X strategies with particular efficiency at suitable locations, as the concentration of CO2 in smelting gases is much higher than in the atmosphere. Incidentally, hydrogen is already required by the chemical industry for certain mass-produced products. In Germany alone, the sector consumes around 22,000 GWh of hydrogen per year to synthesize ammonia and methanol, most of which is produced from fossil raw materials. If green hydrogen were to be used in this process, it would represent a pioneering hydrogen application on the path to climate neutrality. Another industrial process that cannot avoid producing large amounts of CO2 is lime burning for cement production. Here, lime (CaCO3 ) is converted to burnt lime (CaO), which releases CO2 . This is another process where concentrated CO2 can be captured and used as a material in power-to-X processes. The use of processrelated CO2 emissions in power-to-X processes would improve the carbon footprint of the basic industry. Aside from these issues, there is also the problem that processes in sectors such as the chemical or glass industry require very high temperatures. Using green hydrogen to generate high levels of heat would therefore help further reduce the use of fossil fuels and greenhouse gas emissions in these industries. Fraunhofer institutes are conducting intensive research to enable large-scale, economically viable implementation of these processes. Together with companies from the steel industry, they are experimenting with using hydrogen to directly reduce iron ore. They are also working to achieve technical readiness for the process of using the high carbon monoxide and carbon dioxide concentrations in smelting gases or from cement production to produce methanol from hydrogen. The institutes are also adapting power-to-X processes to suit industrial processes and environments and combining them with other synthesis reactions, so that highervalue substances such as waxes can also be produced from basic chemicals. Using special hydrogen production processes such as high-temperature electrolysis, they are increasing overall energy efficiency to an even greater degree by harnessing industrial waste heat. The long-term EU strategy published in 2018 [7] contains some ambitious scenarios for reducing the European industry sector’s greenhouse gas emissions by 2050. One scenario for an almost entirely carbon-neutral industry predicts that the hydrogen demand will reach around 340 TWh, which underlines hydrogen’s potential to make a very significant contribution to a climate-neutral industry.

2.4 Sector coupling—The next phase in the energy transition

2.4

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Sector coupling—The next phase in the energy transition

The energy industry itself represents the biggest obstacle on the path to a climateneutral industrial society, as around four fifths of Germany’s CO2 emissions are rooted in the energy supply [8]. German science academies have divided the energy transition into four different stages [9]. The process of transforming the energy system is now going through what they deem to be the second phase: In the past decade, the focus has been on the development of energy generation and its efficiency (mainly in terms of solar and wind power). Now, system integration is becoming increasingly important. Phases three and four will soon follow, with the large-scale expansion of the hydrogen economy and, finally, the elimination of fossil fuels from the energy system. The second phase is now underway, but what challenges does it bring? Electrifying processes that previously relied on fossil resources for energy, while also drawing more and more electricity from volatile sources, means that there is now a greater focus on the flexible storage and distribution of energy. That is why the share of renewable energies already achieved in the overall system requires increased sector coupling across all branches. With water electrolysis and power-toX processes, this sector coupling can be achieved effectively across the electricity market and the heat and transportation sectors. Coupling these sectors results in a much greater level of flexibility than would be possible with electrical energy storage alone, which is also limited by regional conditions (e.g., pump storage plants) and would be disproportionately expensive at larger sizes (battery storage). The need to account for volatile energy production and the increase in flexibility allowed by the reversible conversion of electrical energy into hydrogen and back are the main reasons why many countries are intensifying their research and funding efforts in this area. The reversible process of converting electricity into hydrogen or power-to-X products also makes it possible to store green electricity in the long term and transport it over long distances. This creates additional options for ensuring that renewable energies are used efficiently, even if the increased use of green electricity is inhibited by limited grid capacity or if certain industry branches always consume more energy than they can generate themselves. Fraunhofer institutes are investigating which technical processes are best suited for the reversible conversion of green electricity to hydrogen and vice versa and for optimizing the required system components. For example, there is demand for electrolyzers that can cope with rapid load changes, as these are needed to ensure

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2 The hydrogen economy: a land of opportunity

Fig. 2.1 Overview of some important value chains and sector interactions in a future hydrogen economy. © Fraunhofer/A. Roth

a reliable, flexible energy supply. Fraunhofer scientists are also exploring hydrogen’s potential to serve as a heat supply to buildings. They are developing system models with varying levels of detail and spatial resolution and testing their theories with their partners in living labs and model regions. They are also gaining more in-depth system knowledge by modeling and simulating all components used in hydrogen technologies, up to and including creating a digital twin of the entire hydrogen economy.

2.5 Germany’s place in a global H2 economy

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If we conceive of hydrogen this way, as a hinge or “exchange currency” in the future energy system, then it becomes clear that we must pursue even more extensive sector coupling across industries. In order to achieve climate neutrality, key industries require large amounts of hydrogen for their production processes. A system that takes into account the demand for hydrogen as an energy and a material in those industries, the production of hydrogen as a by-product of chemical processes and the use of waste heat from industrial processes would be well on the way to comprehensively coupling the energy, mobility and production sectors (Fig. 2.1). When compatible companies are located in the same industrial parks, this creates industrial value creation networks with optimum use of material flows and energy flows. Regional clusters can act as pioneers in testing the interaction of technologies and infrastructure and grow together to form H2 model regions.

2.5

Germany’s place in a global H2 economy

The opportunities that a hydrogen economy would create are directly related to Germany’s most important sectors, namely the automotive industry, mechanical and plant engineering and the chemical, steel and cement industries. Overarching issues such as safety, service life and efficient production of all the necessary systems and infrastructures in large batches and sizes are inextricably linked to the topics presented above. It is only once these practical issues have been resolved that hydrogen can live up to its potential in the practical world. Thanks to their many years of expertise, Fraunhofer institutes are perfectly positioned to provide outstanding support in these areas. For decades, they have been working on projects concerning durability, corrosion resistance and the embrittlement of materials in pipes or tanks; they are also developing safety strategies and sensors for hydrogen infrastructures. What is more, their research is creating the necessary conditions for mass industrial production of components and systems, ensuring that water electrolysis becomes economically viable. Working in consortia with leading companies, they are demonstrating and testing hydrogen technologies in practical applications, with the largest sizes the world has ever seen. Through their test platforms and in living labs, they offer interested industry customers and research partners an excellent basis for testing various processes for producing or using hydrogen, from pilot to industrial scale and under real-world conditions. It is clear that hydrogen technologies can be of great benefit to the German industry sector. However, this benefit is not only limited to helping domestic production sites along the path to sustainability and climate neutrality. It also extends to export opportunities, as hydrogen technologies and systems with the label made

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2 The hydrogen economy: a land of opportunity

in Germany can play a leading role on the world market. To achieve this however, Germany must establish a strong domestic lead market. Before this point can be reached, partners from business, politics and society must deal with the limited possibilities for generating renewable electricity in Germany. Producing high volumes of hydrogen would result in considerable growth in electricity demand. However, these limitations become less inhibiting once we take a step back from ideas of energy self-sufficiency and begin to consider the prospect of imports. When designing a future global energy supply system based on solar power and hydrogen [10] back in the mid-1980s, the hydrogen pioneer Ludwig Bölkow quite naturally considered the prospect of intercontinental hydrogen transportation—and with good reason. Forecasts largely agree that renewable energies will drive the global economy in the future. The energy transition is a global task. As in the past, regions that are particularly efficient at generating energy will trade with those that use more energy than they can produce themselves. However, trading large amounts of energy over long distances limits the use of direct electricity in any case. In Germany, solar and wind energy will arrive in the form of hydrogen, or in the form of chemical energy carriers that were generated from hydrogen using power-to-X processes. For this reason, Fraunhofer institutes have long been working on forecasts and simulations to predict the roles of different countries and global regions that will play in this system. It is becoming apparent that tropical and subtropical countries, which have plenty of sunshine and constant wind, long coasts and efficient ports, will play an important role in supplying industrial regions in the northern hemisphere. By analyzing demand and potential, the Fraunhofer institutes support industry and the public sector in designing the energy markets of tomorrow and setting their course today in such a way that the transition to a renewable age can succeed through global collaboration. Germany’s industry is closely linked to its European neighbors and could no longer function without the internal EU market. With the Green Deal, the European Union made a commitment to becoming the world’s first climate-neutral continent. This aim would be impossible to achieve if it were not for hydrogen. Conversely, the opportunities posed by the hydrogen economy also apply to the whole of Europe. That is why the EU hydrogen strategy provides for a rapid expansion of the infrastructure for producing and transporting hydrogen. The EU Commission has set itself the goal of installing an electrolyzer capacity of at least 40 GW by 2030, which could be used to produce 333 TWh of green hydrogen even at that stage [11]. An optimistic, but nevertheless well-founded, scenario predicts up to 5.4 million jobs and an annual turnover of 800 billion euros in 2050 for the hydrogen economy in Europe [12].

2.6 Outlook

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Numerous countries have developed their own national hydrogen strategies in recent years. Depending on the overall conditions and individual strengths of the countries, their focus may be on producing and exporting hydrogen, hydrogenpowered mobility or other issues. The National Hydrogen Strategy, published by the German federal government in the summer of 2020, is justified in emphasizing the importance of the manufacturing industry and exports [13]. It also clearly indicates that there is an important international dimension to the hydrogen economy, and that establishing energy partnerships with countries that could potentially be top hydrogen exporters is in Germany’s strategic interest. Fraunhofer has made significant contributions to discussions on this strategy [14].

2.6 Outlook As demonstrated above, a hydrogen economy would be a versatile tool for successfully transitioning to a climate-neutral and sustainable—but still efficient—economic system. This will be examined in more detail in the later chapters of this book. Great achievements take more than a standing start. An athlete who wants to jump far needs a long run-up. The same is true of the hydrogen economy: Today, Germany and Europe can make a decisive start on shaping change and setting a new course so that, in the decades to come, the various concepts involved in a hydrogen economy will become a reality. Ports, storage facilities and pipelines must be prepared or converted and living labs at actual scale must prove that the technologies can interact as planned in practice before the energy transition can enter its next phase, where synthetic fuels will increasingly replace fossil fuels and water electrolysis is required on a large scale. It should be noted that establishing an infrastructure is more than just a technical issue. Establishing the right legal framework and economic incentives at an early stage, as well as helping to determine industrial standards and environmental labels, will ensure that our national economic area gets a head start. At the same time, it would be detrimental to slacken our efforts in terms of research—even if many technologies are already considered ready for use today, questions regarding service life, robustness and the efficiency of the systems used are still unanswered. Not only that, but once hydrogen becomes a mass segment in many industries from about 2035, new generations of technology will be in use. If we do not want to have to import these into the EU from other economic areas, we must ensure that the latest, most advanced technology is always available on our continent and is constantly undergoing further development. When it comes

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to transferring these technologies into practice, Fraunhofer institutes will continue to be the ideal partners for industry in the future. After all, who can say with certainty what will come after water electrolysis at this stage? Fraunhofer institutes are already thinking ahead: Will we produce hydrogen using the direct, photochemical method, or will we use more advanced biological mechanisms? The smallest molecule continues to pose big questions for us, and it is in this smallest molecule that our greatest hopes lie.

References 1. International Energy Agency (2019): The Future of Hydrogen. https://www.iea.org/ reports/the-future-of-hydrogen, last viewed on November 16, 2021 2. German Federal Parliament (1994): Final report of the Enquete-Kommission “Schutz der Erdatmosphäre” (Protection of the Earth’s atmosphere), Bundestag document 12/8600, October 31, 1994, p. 507 3. https://www.ise.fraunhofer.de/de/ueber-uns/geschichte.html 4. Fuel Cells and Hydrogen Joint Undertaking (2019): Hydrogen Roadmap Europe: Hydrogen Roadmap Europe: A sustainable pathway for the european energy transition. https://www.fch.europa.eu/news/hydrogen-roadmap-europe-sustainable-pathwayeuropean-energy-transition, last viewed on November 16, 2021 5. Zimmer K., Robaschik F., Sauermost M., Sundermann L. (2019): Unter Hochdruck (Under high pressure). Markets International 6/2020: 35 ff. https:// www.marketsinternational.de/wasserstoff 6. Deutsche Energie-Agentur (2018): dena-Factsheets: PowerFuels. https://www.dena. de/newsroom/publikationsdetailansicht/pub/dena-factsheets-powerfuels, last viewed on November 16, 2021 7. European Union (2018): A Clean Planet for all—A European strategic long-term vision for a prosperous, modern, competitive and climate neutral economy. https://eur-lex. europa.eu/legal-content/EN/TXT/?uri=CELEX:52018DC0773, last viewed on November 16, 2018 8. German Environment Agency: Jährliche Treibhausgas-Emissionen in Deutschland (Annual greenhouse gas emissions in Germany). Nationales Treibhausgasinventar 2020 (National greenhouse gas inventory 2020). https://www.umweltbundesamt.de/daten/ klima/treibhausgas-emissionen-in-deutschland#emissionsentwicklung, last viewed on November 26, 2021 9. acatech, Leopoldina, Union of Academies (2017): Coupling the different energy sectors options for the next phase of the energy transition. Series on Science-Based Policy Advice. ISBN 978-3-8047-3673-3, 100 p. 10. https://ludwig-boelkow-stiftung.org/die-stiftung/der-stifter, last viewed on November 16, 2021 11. European Union (2020): A hydrogen strategy for a climate-neutral Europe. https://eur-lex.europa.eu/legal-content/EN/TXT/?qid=1594897267722&uri=CELEX: 52020DC0301, last viewed on November 16, 2021

References

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12. Fuel Cells and Hydrogen Joint Undertaking (2019): Hydrogen Roadmap Europe: A sustainable pathway for the European energy transition. https://www.fch.europa.eu/ news/hydrogen-roadmap-europe-sustainable-pathway-european-energy-transition, last viewed on November 16, 2021 13. BMWK (2020): The National Hydrogen Strategy. https://www.bmwk.de/Redaktion/EN/ Publikationen/Energie/the-national-hydrogen-strategy.html, last viewed on November 16, 2021 14. Hebling C., Ragwitz M., Fleitner T. et al. (2019): A hydrogen roadmap for Germany. https://www.fraunhofer.de/content/dam/zv/de/ueber-fraunhofer/wissenschaftspolitik/ Positionen/2019-10-a-hydrogen-roadmap-for-germany.pdf, last viewed November 16, 2021

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The potential of a hydrogen economy: an economic and social perspective

Martin Wietschel  Elisabeth Dütschke  Marius Neuwirth  Aline Scherrer  Lin Zheng Fraunhofer Institute for Systems and Innovation Research ISI Norman Gerhard Fraunhofer Institute for Energy Economics and Energy System Technology IEE Sebastian Herkel Fraunhofer Institute for Solar Energy Systems ISE Matthias Jahn Fraunhofer Institute for Ceramic Technologies and Systems IKTS Aleksandar Lozanovski Fraunhofer Institute for Building Physics IBP Benjamin Pfluger  Natalia Pieton  Mario Ragwitz Fraunhofer Research Institution for Energy Infrastructures and Geothermal Systems IEG Frieder Schnabel Fraunhofer Institute for Industrial Engineering IAO Abstract

In order to create a comprehensive overview of a future hydrogen economy, different climate target and energy demand scenarios will be considered and the key issues of economic relevance, value creation, climate protection, public support and demand for hydrogen will be examined. This chapter starts with © Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_3

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a section on the economic relevance of hydrogen and hydrogen-based synthesis products and makes predictions as to how a potential hydrogen market may develop in the future. It then discusses the value chain that would result from a climate-neutral hydrogen economy and addresses the sales and labor market potential that chain would give rise to. Lastly, it highlights the opportunities this would present for German industry. Subsequently, the chapter focuses on how the use of hydrogen can help achieve climate and environmental targets, including an explanation of how hydrogen production can potentially help to reduce greenhouse gas generation, depending on which raw materials are used. Finally, three essential factors for achieving public support for and removing the barriers to a hydrogen economy will be discussed, followed by the challenges and opportunities that a hydrogen economy would present for the key demand sectors of industry, transportation, heating and energy.

3.1 The economic relevance of hydrogen A number of studies have examined the global potential of hydrogen and its synthesis products. The global market potential of power-to-X (PtX) processes has been estimated to lie within the range of 320 to 726 TWh for 2030 and 972 to 6180 TWh by 2050 [1]. This corresponds to a market size of between 45 and 102 billion euros in 2030 and between 107 and 680 billion euros in 2050. By comparison, oil markets at today’s prices reach volumes of about 2000 billion euros per year. Depending on the study and the given projection scenario, ambitious climate protection plans for Germany estimate that demand for synthetic fuels alone will range between 530 TWh and 910 TWh in 2050 [3–5]. By comparison, in 2018, total electricity demand in Germany amounted to 560 TWh, while the total final energy consumption came to 2500 TWh. This shows that on the one hand, a great deal of effort will be required in this area in the future. However, on the other hand, it also indicates the economic opportunities that this market could offer. To meet this demand, we assume that in Germany alone, the water electrolysis market will have to ramp up to reach a power grid contribution of between 50 and 80 GW by 2050. To achieve this, electrolyzers with output capacities in the double-digit MW range must be installed now, and growth rates of about 1 GW per year must be achieved by the end of the 2020s. Table 3.1 shows the possible levels of hydrogen demand and electrolysis capacity in Germany and the EU. Water electrolyzers will be used on a large scale in regions where the cost of generating electricity at solar and wind farms that achieve more than 4000 full

3.2 Value creation potential for German industry

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Table 3.1 Possible hydrogen demand levels for 2030 and 2050, including PtX demand and electrolysis capacity, for the regions of Germany and the EU [6] Parameter Hydrogen demand (TWh) Electrolysis capacity (GW)

Region Germany EU Germany EU

2030 Lower level 4 30 1 7

Upper level 20 140 5 35

2050 Lower level 250 800 50 341

Upper level 800 2250 80 511

load hours per year falls below 3 ct/kWh. With these figures, it would be possible to break into the global renewable energy trade, as both hydrogen and hydrogenbased synthesis products could then be produced at internationally competitive costs. Expectations from industry and politics are increasing accordingly, as is reflected in the growing involvement of various stakeholders from these spheres in Germany. Business associations and German federal states are playing a particularly active role here, by developing strategies and road maps, and working to create the conditions needed to leverage the technology (e.g., by means of government funding and changes to existing regulations, for example, on taxes and levies).

3.2 Value creation potential for German industry Hydrogen technologies are expected to play a key role in achieving climate and environmental targets, and as such, the global market for hydrogen applications is undergoing corresponding large-scale, dynamic developments. Germany also hopes to benefit from this market, which will be worth billions in the future, and the promising sales opportunities it offers, as hydrogen applications are associated with enormous potential for value creation. Its aim is to leverage this potential, create jobs and ultimately become a pioneer in the global hydrogen economy [7]. German industry has already laid the necessary foundations for this, with many companies and research institutions already covering the entire hydrogen and fuel cell value chain in different integration stages [8]. For example, Germany has a great deal of existing expertise in terms of manufacturing fuel cells and electrolysis systems for green hydrogen production. Despite this, achieving these targets will still require new stakeholders and technology developments, as well as innovative business models and service offerings for every stage of the value chain. This is the only way that Germany can maximize its advantages in terms of expertise and expand its opportunities for exporting products.

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3.2.1 The hydrogen economy value chain In its National Hydrogen Strategy, the German federal government focused on issues such as the leveraging of value creation potential offered by hydrogen applications, the development of new technologies, the creation of jobs and the establishment of an advantage in terms of expertise: “In order to make hydrogen a key element of our decarbonisation strategy, our entire value chain [. . . ] needs to be looked at.” [9]. This value chain is made up of the following basic stages (Fig. 3.1):  Energy generation The primary requirement for environmentally friendly hydrogen production is using renewable energy sources (e.g., wind, sun) to power the production process.  Conversion to hydrogen There are a number of different ways of producing hydrogen. Our target here is to produce it via electrolysis that is powered solely by electricity from renewable energy sources (green hydrogen). It can also be produced via thermal cracking of methane in methane pyrolysis (which produces turquoise hydrogen), or via steam reforming of fossil fuels, either with or without carbon capture, utilization and sequestration (CCUS) (which produces blue or gray hydrogen respectively). For more information on hydrogen production, see Chap. 9.  Distribution and transportation Distribution and transportation logistics form a significant link in the value chain. Within national and global supply chains, hydrogen can be transported by truck, rail, ship or pipeline.  Storage Producing, transporting and using hydrogen in practical applications requires suitable storage technologies. Hydrogen can be stored under pressurized conditions as a liquefied gas by means of cooling or compression (e.g. in pressurized vessels or caverns). However, there are also other hydrogen storage options, such as absorption of the gas into solid storage materials like metal hydrides or by chemically bonding the molecules with other compounds to form a liquid carrier medium.  Use There are a wide variety of possible fields of application for hydrogen, ranging from electricity and heat generation to direct use in industrial processes, all the way up to serving as a fuel in transportation (see Chaps. 4–7).

3.2 Value creation potential for German industry ENERGYGENERATION

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HYDROGENPRODUCTION

+

STORAGE

-

DISTRIBUTION & TRANSPORTATION

H2

INDUSTRY

MOBILITY

HEAT

ENERGYSYSTEM

Fig. 3.1 Hydrogen economy value chain. (Fraunhofer IAO)

3.2.2

Sales potential and job creation

Currently, hydrogen still plays a minor role in the energy system. Different studies have suggested different estimates as to the levels that hydrogen demand will reach in the future, but they are all in agreement that demand will grow significantly (Sect. 3.1). The sales potential for German industry is set to increase in proportion to the growth in demand for hydrogen and the related technologies. According to estimates outlined in the Hydrogen Roadmap Europe, the sales potential for European companies in the hydrogen and fuel cell sectors is set to reach approximately 130 billion euros in 2030 [10]. This ambitious projection scenario predicts that companies operating in Germany along the entire value chain will account for approximately 44 billion euros of this total. It is expected that the technology costs in this domain will decrease significantly in the future, making hydrogen more and more competitive at economic level and thus supporting the abovementioned development [8]. This will also result in expanded export opportunities and growth in terms of job creation. According to a Europe-wide study from 2019, the hydrogen industry could create over 5.4 million jobs across Europe by 2050 [10]. In Germany, the German Hydrogen and Fuel-Cell Association is already predicting positive developments in employment, with 70,000 new jobs being created by 2030 [11].

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3.2.3 Promising value creation potential for the German industry sector Industry The entire value chain of the German hydrogen economy offers huge potential for value creation, particularly in the industry sector, which consumes enormous volumes of energy. The main areas that will require large quantities of hydrogen in this sector are refineries, steel production, the chemical industry and more generally, the generation of high levels of heat for industrial processes (e.g. in cement, paper and glass production)—all fields where hydrogen could replace conventional energy sources. Mechanical and plant engineering companies that produce hydrogen technologies and service providers in the hydrogen sector also offer significant potential here. German companies’ primary economic strengths relate to their expertise in automated production of high-quality parts and components and in the industrialization processes that are required to initiate the market ramp-up. The German industrial landscape, which consists of both large companies and the “hidden champions” of the SME sector, is heavily skewed toward exports, meaning that it is in a good position to meet the high demand for hydrogen technologies that is expected to come from other countries. German electrolyzer manufacturers are a good example of this, with estimates predicting that their domestic value creation will reach approximately 5.5 billion euros per year by 2050 [6]. Germany also has more expertise to offer in the chemical industry—e.g., in the production of synthetic fuels (power-to-liquid, PtL) and methanation—in the area of carbon capture and storage (CCS) and/or carbon capture and utilization (CCU) and in gas turbines for hydrogen.

Transportation and mobility The transportation and mobility sector is a particularly important focus area for the German hydrogen economy, as many component manufacturers (e.g. of fuel cell drive systems) and system integrators (e.g. vehicle manufacturers) are based in the country. These suppliers and OEMs must quickly adapt to market developments in the field of alternative drive systems and energy supply models (such as for stationary solutions), so that they can leverage the value creation potential of the hydrogen and fuel cell industry. The technological potential that hydrogen offers as an energy carrier is particularly relevant in the context of the transformation process that is currently underway in the automotive industry and the impending shift away from fossil fuels, as this potential could make a major contribution to

3.2 Value creation potential for German industry

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securing value creation and employment in the automotive sector. In the context of the fuel cell industry, which is very intensive in terms of employment, it can have positive effects on the local area if the work required can take place on-site at the companies involved [12]. The field of transportation and mobility will account for almost one-third of total global hydrogen demand by 2050. China and California are each expected to have one million fuel cell vehicles on their roads by 2030, while Korea is set to have as many as 1.8 million [13]. It is estimated that the production of fuel cells for transportation alone will create value for German companies amounting to approximately 2.4 billion euros per year until 2030 and approximately 26 billion euros per year in the decade running from 2040 to 2050 [6].

Heat The heating sector must account not only for the high-temperature industry processes mentioned above, but also for the supply of heat to residential and nonresidential buildings, which involves (micro-) combined heat and power (CHP) systems based on fuel cells. In this context, the German industry sector must also make gas turbines “hydrogen-ready”, by designing CHP systems that are suitable for mixed operation with gas and hydrogen.

Energy system The fourth important sector is the energy system, which comprises the production, storage and distribution of hydrogen. The important stakeholders here include energy suppliers and plant operators, grid operators (electricity and gas) and parties involved in electricity trading and hydrogen production. The field of renewable energy generation technologies offers great value-creation potential for German companies. As already indicated in the context of the industry sector, power-togas technologies (PtG) and the development and use of technologies for hydrogen storage also hold significant potential here. Many new technological solutions are currently emerging. In the latter case, for example, hydrogen can now be stored in carrier materials such as thermal oils in a comparatively safe, environmentally friendly manner (liquid organic hydrogen carriers, LOHC). One of Europe’s first live LOHC storage systems was set up several years ago at Fraunhofer IAO’s Micro Smart Grid in Stuttgart (Fig. 3.2)1 .

1

For more information, see: https://www.muse.iao.fraunhofer.de/de/ueber_uns/labors/ fraunhofer-iao-micro-smart-grid.html.

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Fig. 3.2 LOHC storage in Fraunhofer IAO’s Micro Smart Grid, Stuttgart. (Ludmilla Parsyak/Fraunhofer IAO)

Last but not least, a supply infrastructure must also be constructed, and this also offers potential for value creation. While smaller volumes of hydrogen will continue to be transported by truck, ship and rail, if larger volumes of the gas are to be used in industry, it will be necessary to set up and expand a pipeline network for hydrogen, or to convert existing natural gas networks. Building a pipeline network along the Rhine would be a particularly suitable location, as many large industrial consumers are situated in that region. The infrastructure must also include an expanded refueling infrastructure for cars and trucks, in order to promote the use of fuel cells in mobility. Because of its relatively low volumes of wind and sunshine hours, Germany is dependent on energy imports for its (green) hydrogen supply, and will remain so. As such, the country must strive to establish reliable energy partnerships and import structures at an early stage. All the abovementioned sectors will be described in more detail in Sect. 3.5.

3.3 The role of hydrogen in achieving climate and environmental targets

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3.3 The role of hydrogen in achieving climate and environmental targets For many industry sectors, hydrogen is an essential requirement if they are to achieve massive reductions in harmful greenhouse gas emissions. Electrolysis is a promising, established technology for green hydrogen production. In order for the hydrogen produced via electrolysis to be demonstrably (more) climate-friendly, low-carbon electric power is required. Fig. 3.3 shows the correlation between the potential greenhouse gas emissions stemming from hydrogen production (straight orange line) and the potential emissions of the electricity used. An efficiency rate of 65 percent in relation to the heating value was taken as a basis and the process of manufacturing the electrolyzer was taken into account, as recommended in [14]. As recommended by the EU, the greenhouse gas potential was calculated using the Environmental Footprint 3.0 method that the GaBi software and database system is based on [15]. The greenhouse gas potential of hydrogen that is produced via electrolysis is directly proportional to the greenhouse gas potential of the electricity used to power the process, as shown in Fig. 3.3. The horizontal dotted blue reference line indicates the greenhouse gas potential of the EU’s mix of hydrogen produced from natural gas (which is taken as the standard because it is a commonly used, fossilbased hydrogen production method), namely 92 g CO2 eq/MJ hydrogen. The entire value chain, which ranges from natural gas production and transportation to hy-

Fig. 3.3 The greenhouse gas potential of hydrogen production using electrolyzers (y-axis) as a function of the greenhouse gas potential of the electricity mix used in the process (xaxis)

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drogen production via steam reforming, has been taken into account here. The vertical green lines are included for reference, in order to show the greenhouse gas potential of different electricity mixes. The lines on the left correspond to wind and solar energy, which enable significant reductions in greenhouse gas potential (95 percent and 67 percent respectively) when compared to hydrogen produced using fossil natural gas. Based on the assumption that significant efforts will be made to reduce greenhouse gas emissions in the coming years, hydrogen produced using the average EU electricity mix will achieve a lower greenhouse gas potential than its fossil counterpart by as early as 2030. Hydrogen produced via electrolysis using hydrogen from fossil natural gas reaches its break-even point at around 215 g CO2 eq/kWh. If different electrolysis efficiency rates were taken as a basis for the calculation, the overall result would remain more or less the same. However, the slope of the curve would change. When efficiency rates are higher, the process requires less electricity, which results in a flatter slope and lower greenhouse gas potential for the same electricity mixes. Many projects and developments quite rightly focus on solutions for stopping climate change, i.e. for reducing greenhouse gas potential. However, that leaves many other important environmental issues unaccounted for. These are often included as control variables in environmental auditing, as with resource consumption, for example, which also forms part of the Environmental Footprint 3.0 method mentioned above. Fig. 3.4 shows the results calculated for these same electricity mixes (running in the same order from left to right as in Fig. 3.3) in terms of their use of mineral and metal resources. It is very obvious that there is no correlation between greenhouse gas potential and use of mineral and metal resources. For example, photovoltaics differ from all other electricity mixes by more than a factor of five. As such, the y-axis in this chart has a break in the middle, so that the differences between the other values can be clearly seen. In addition, unlike the previous calculations regarding greenhouse gas potential, the process of manufacturing the electrolyzers must be taken into account for these calculations. Manufacturing the electrolyzer can account for anything from 1 percent to as much as 49 percent of the mineral and metal resources used, depending on the electricity mix. This means that changing the materials and electrolyzer manufacturing processes used can affect the overall amount of resources used per MJ of hydrogen produced. The absolute values for hydrogen produced via electrolysis range from 2.6508 to 9.8507 kg of antimony eq. Although not shown in Fig. 3.4 due to a lack of visibility, the value for hydrogen produced from fossil natural gas amounts to 5.1309 kg antimony eq. As can be seen from this example, different life cycle phases result in different problems and loads. A life cycle assessment allows us to identify and account for

3.4 Public acceptance of hydrogen

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Fig. 3.4 Use of mineral and metal resources in hydrogen production via electrolysis, taking into account various electricity mixes

these differences, in order to generate the most comprehensive overview possible of the system in question and to select the optimum tool for supporting fact-based decision-making processes, while taking various points of view into account.

3.4 Public acceptance of hydrogen Public acceptance refers to “a favorable or positive response (including attitude, intention, behavior and—where appropriate—use) relating to a proposed or in situ technology or socio-technical system, by members of a given social unit (country or region, community or town and household, organization)” [16]. This definition directs focus to a number of areas in particular:  The variety of ways that this acceptance can manifest itself in attitudes, intentions, behavior, and use, where applicable. What do people think about hydrogen strategies, business models or applications? What opinions do they express and how willing are they to put them into practice by investing in hydrogen or adopting hydrogen solutions?  The differences between the objects of this acceptance in terms of their stage of development (proposed vs. impending) and scope (technology vs. sociotechnical system). This includes both ideas that are still in their early stages, such as the concept of an international hydrogen economy, and applications that have reached technological maturity, such as fuel cells.

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 The different social entities as subjects of acceptance—ranging from individuals or small groups (households or organizations) or larger collectives (cities, municipalities, regions or countries). Public support can be analyzed at different levels.  The geographic or political boundaries within which data is collected on public acceptance. Because hydrogen is an international issue and because the production and utilization scenarios discussed span different countries, it is important to place the results obtained regarding public acceptance in their proper context. Research into public acceptance in the field of hydrogen: can be broken down into three significant sub-categories: (1) socio-political acceptance, (2) market acceptance, (3) local acceptance.

3.4.1 Socio-political acceptance of hydrogen This dimension of public acceptance for hydrogen refers to the general social climate relating to the concept of a hydrogen economy and the relevant political conditions shaping the situation. Previous research (in the HYACINTH project) indicates that society has a positive attitude toward hydrogen innovations, but a low level of knowledge in this field [17]. Three in five people in the general population had heard of hydrogen cars, while only one in five had heard of stationary applications such as microCHP systems (Fig. 3.5). An expert survey revealed that not only the general population but also societal stakeholders from outside the fields of industry and research, including policymakers, have low levels of knowledge on this subject. Ongoing dialogues may have altered this situation to some extent, but hydrogen technologies are still new to many stakeholders in society. In a phase such as the one we currently find ourselves in, people’s attitudes are usually not very stable as yet and are easily influenced by prevailing arguments or opinion leaders [18]. As such, it can be assumed that the manner in which the social narrative around hydrogen technologies develops in the near future will have an important impact on socio-political acceptance. Important events and the way they are portrayed by the media also play a central role here. As a rule, socio-political acceptance is a prerequisite for market and local acceptance.

3.4 Public acceptance of hydrogen

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Fig. 3.5 Awareness of H2 fuel cell technologies in Europe. (Schneider et al. 2017)

3.4.2 Market acceptance Market acceptance for hydrogen and the associated innovation system (consisting of pre-competitive research, questions of supply and demand, and the overall

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conditions and financing options established by policy-makers) also constitutes an important factor. The primary challenge that must be addressed on the demand side is a lack of awareness regarding hydrogen applications. Other critical issues include the fact that the product offering to date has been quite limited. What is more, hydrogen technologies face strong competition, for example, from electric vehicles in the mobility sector, as these have reached a more advanced level of technological development. Expectations regarding the future of the hydrogen sector are heavily influenced by anticipated developments in economic factors and innovation policy. These expectations then in turn affect the intention of experts to actively drive advancements in the field [19]. In recent years, the German population has perceived hydrogen more positively than that of Spain or the UK, for example. As such, the German federal government’s current hydrogen programs have encountered a comparatively positive climate.

3.4.3 Local acceptance Finally, the question of establishing the required infrastructure in specific locations is giving rise to issues of acceptance at the local level. On the one hand, infrastructural projects can meet with resistance because they bring unwanted changes. On the other, however, they can also create opportunities by strengthening local economies and answering society’s calls for greater sustainability. Such projects require alliances of societal stakeholders (from industry, politics and science), as well as public participation. Sociological research is particularly useful for determining what forms this participation could take. This means that research into support for hydrogen systems requires a wideranging overview of the stakeholders involved in the innovation system together with a comprehensive understanding of the notion of acceptance as a social construct. This research must not only concentrate on citizens as voters and residents, but also on stakeholders from the spheres of politics, industry and other social domains. Regardless of whether they make or influence decisions, or invest in or are affected by developments, these stakeholders have a vital role to play in shaping the innovation ecosystem, which means they must be taken into account. The diverse range of stakeholders involved, together with the different concerns, possible influences and incentive systems that motivate their actions, is an indicator of both the far-reaching impact of industrial and technical systems and the relationships of power and dependency found in those systems.

3.5 Potential hydrogen demand and the economic situation

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3.5 Potential hydrogen demand and the economic situation There is a great uncertainty as regards future developments in the demand for hydrogen and hydrogen-based synthetic fuels. These predictions vary widely in the existing studies and have been summarized by Fraunhofer ISI [20]. According to the estimates of the various studies, the demand for hydrogen in the industrial, transportation and building sectors alone could range from 10 to 340 TWh in 2030 and 20 to 650 TWh in 2050. Taking hydrogen-based synthetic fuels into account, the demand for hydrogen in the abovementioned sectors could reach to up to 1000 TWh in 2050 (Fig. 3.6). However, it must be noted that synthetic fuels do not consist entirely of hydrogen. Depending on the study, hydrogen demand in the energy sector could range between 0 and 20 TWh in 2030 and 50 and approx. 300 TWh in 2050 (Fig. 3.7). In this context, the study commissioned by the German Federal Ministry for Economic Affairs and Climate action (BMWK) takes both blue and green hydrogen into account.

Fig. 3.6 Demand levels for hydrogen and hydrogen-based synthetic fuels in 2030, 2040 and 2050 in the industry, transportation, and building sectors, based on scenarios that achieve 95 percent emissions reduction or full climate neutrality by 2050 [20]

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Fig. 3.7 Demand levels for hydrogen in 2030, 2040 and 2050 in the energy sector based on scenarios that achieve 95 percent emissions reduction or full climate neutrality by 2050 [20]

Fig. 3.8 Demand levels for hydrogen-based synthesis products in 2030, 2040 and 2050 in the energy sector, based on scenarios that achieve 95 percent emissions reduction or full climate neutrality by 2050 [20]

Alternatively, some studies focus more on hydrogen-based syngas products in certain scenarios, which could lead to a demand of around 200 TWh in the energy sector by 2050 (Fig. 3.8).

3.5 Potential hydrogen demand and the economic situation

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There are various possible routes to decarbonization, whereby the focus ranges from direct electrification to the use of hydrogen, all the way up to a sharp acceleration in utilizing synthetic fuels. These various routes can lead to extreme differences in demand levels. The following sections will discuss the potential demand in the industry, transportation, (building) heat and energy sectors.

3.5.1

Industry sector

In contrast to many other sectors, some branches of industry have already been attempting large-scale hydrogen use for many years and it has now become a standard technology. The chemical industry in particular is already using large quantities of hydrogen to synthesize ammonia and methanol and process crude oil in refineries. Implementing hydrogen-based production technologies in other industry branches will make an important contribution to industrial decarbonization in the future. At present, the industry sector accounts for around 23 percent of emissions [21] and 30 percent of final energy consumption [22] in Germany, which makes it an important instrument for achieving climate targets. Individual industry branches are faced with different challenges here, which stem from factors such as their market structures and production technologies. Green hydrogen produced via electrolysis using electricity from renewable sources is set to play a vital role in the transition to carbon-neutral industrial production. It holds great potential both for use as an energy carrier and as a raw material in a variety of industrial process routes. In principle, CO2 that is produced during industrial processes (Carbon Capture and Usage, CCU) can be combined with green hydrogen in order to produce carbon-based products. It is also possible to avoid CO2 emissions by using hydrogen as a substitute for carbon-based feedstocks such as coal or natural gas (Carbon Direct Avoidance, CDA) (Fig. 3.9).

Current hydrogen demand in industry and hydrogen production At present, hydrogen is primarily used by customers in the chemical and refinery industries. In the chemical industry, hydrogen sees particular use as a source material for the production of ammonia and methanol. At present, the hydrogen required for the production of ammonia is mostly produced from natural gas via steam reforming, which results in high specific CO2 emissions [6]. The hydrogen required is mainly produced in a small number of large, integrated plants in chemical parks and refineries or as a by-product of chemical processes (e.g., chloralkali electrolysis).

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Fig. 3.9 Use of hydrogen to reduce industrial CO2 emissions

Ammonia is already one of our most important inorganic raw materials, and as the world’s population grows, its global importance grows with it. In the future, this significance could increase even further, as in addition to being used in fertilizers, ammonia also has the potential to act as an energy carrier in power plants and engines. It is also relatively easy to transport and store, so it could be used to convey the hydrogen that is chemically bound within its molecules. In the chemical industry, methanol is widely used as an intermediate product for a variety of industrial chemicals. In addition, it has excellent combustion properties, meaning that it can be used as a fuel or fuel additive in vehicles. Increasing our use of methanol as an energy carrier would have the advantage of allowing us to use existing energy supply and chemical industry infrastructures. Hydrogen is used on a large scale in a number of the steps involved in processing crude oil in refineries. A large proportion (78 percent) of the hydrogen required in German refineries is generated as a by-product (e.g., in reformers) during crude oil refining. The remaining 22 percent (5 TWh) is produced on site via steam reforming of natural gas [23]. In the long term, it is expected that a significant proportion of fossil fuels will be replaced by alternative fuels that do not contain CO2 . It is only in aviation and the chemical industry that carbon-based feedstocks will still be needed. In order to achieve decarbonization by 2050, both the basic chemical industry and refineries must replace their current processes involving fossil-based energy carriers with carbon-free or -neutral alternatives. This area is highly pressurized in terms of costs, which means that using green hydrogen will only become economically viable if suitable regulations are put in place for GHG quota accounting and if the RED II is implemented appropriately [24].

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Potential hydrogen applications in emission-free production Switching processes that already use hydrogen to green hydrogen is one possible means of achieving a carbon-neutral industry in the future. However, another important option for emission reduction is to create new, hydrogen-based synthesis routes for producing new raw materials. The production of raw materials using electricity from renewable energy sources is generally referred to a power-to-X (PtX). Most plastic production processes currently rely on steam crackers and generate high emission volumes. A possible means of making them climate neutral would be to produce olefins using methanol as an intermediate product; this is known as the methanol-to-olefins process route (MtO process route). Meanwhile, rather than relying on the blast furnace route, primary steel production could switch to direct reduction using hydrogen (H2 -DRI), which is a promising climate-neutral alternative [25]. The product, which is called sponge iron (also known as direct reduced iron or DRI), is then processed in an electric arc furnace to form steel.

Using hydrogen for emission-free generation of intense heat Hydrogen’s high combustion temperature means that it can be used as an energy source in high-temperature applications, particularly in the glass, ceramics, cement and lime industries. These sectors require temperatures of 1000 °C and higher, which is mainly provided via natural gas at present. While there are already a number of research projects focusing on this subject (HyGlass, HeidelbergCement, burner technologies), the corresponding plants have yet to be constructed.

Hydrogen’s industry potential and climate protection Systematic further development of chemical industry technologies—assuming that use of existing processes continues and cost efficiency increases—will make it possible to replace the gray hydrogen that is currently in use with green hydrogen in the short to medium term. In the medium to long term, green hydrogen could replace natural gas as a raw material and energy carrier in many areas—such as in the MtO process, for example. However, the question of whether hydrogen will be used to produce higher-value PtX products is heavily dependent on demand from other sectors, such as transportation. Because carbon is an indispensable raw material for PtX technologies and many chemical industry processes use carbon as a material, the use of technologies such as CCU and DAC as a CO2 supply will play an important role in any hydrogen economy; as such, this area requires further research. In the long term, the use of hydrogen in PtX products will only help us to achieve a carbon-neutral industry if a circular material cycle is established for CO2 or if CO2 can be obtained via air separation. Many stakeholders in the steel industry are predicting that primary steel

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Table 3.2 Overview of potential hydrogen demand volumes for specific industry processes in TWh, including production volumes for 2018 and an estimate of the technology readiness level [26] Industry sector

Basic chemical

Process

Ammonia Methanol Olefins Crude steel H2 direct reduction Metal processing HT process heat Non-ferrous metals HT process heat Refineries Crude oil refining Glass and ceramics HT process heat Cement and lime HT process heat Paper Steam generation Other Low-temperature process heat Steam generation TOTAL –

Production volume in millions of tons 2.9 1.1 5.2 29.6 32.5 – – 21.2 30.9 39.8 –

Specific Potential TRL H2 demand H2 demand [1–9] in MWh/ta in TWh 5.9 6.3 17.7 3.2 0.6 6.5 – 1.6 0.9 1.6 –

–

–

17 8 76 56 18 14 18 16.5 13–37 20–31 77–105

386–463

8–9 9 8–9 7–8

8 6–7 6–7 6–7

–

a

The specific H2 demand data consists of average values across the industry in question. The demand for individual products and process steps varies within the industry branches.

manufacturing will replace the blast furnace process with direct reduction. Their goal in the medium term is to operate their plants using natural gas blended with green hydrogen initially, while in the long term, they hope to switch entirely to green hydrogen. Table 3.2 provides an overview of potential hydrogen demand in the German industry sector, based on the country’s existing industries and current production volumes. Establishing the right regulatory framework is an important prerequisite for ensuring that carbon-neutral industry production processes based on green hydrogen are economically viable. The regulations that set carbon taxes and CO2 allowance costs essentially determine the price and availability of electricity from renewable energies, as well as the costs of the CO2 -intensive manufacturing routes. The global economy is heavily dependent on the products of the steel and chemical industries, but the current production processes, which use fossil raw materials, result in very high specific CO2 emissions. Consequently, using the available green hydrogen in these industry sectors should be a high priority.

3.5 Potential hydrogen demand and the economic situation

3.5.2

41

Transportation sector

There is a wide range of possible hydrogen applications in the mobility sector. The first small batches of fuel cell vehicles are already being commercially produced for the passenger car market. However, Asian manufacturers currently the only ones offering such models. Fuel cells are already regularly used in the material transportation segment, for forklifts, for example. Furthermore, fleet trials are taking place in Germany in the bus transportation sector (for local and long-distance bus services). There is a great deal of activity focusing on fuel cells in the truck segment, particularly for medium-sized and heavy trucks, with production scheduled to start in the near future. Initial fleet trials are also underway in rail transport, and some announcements have also been issued regarding non-electrified line sections. In the maritime sector, plans are also in place to conduct initial testing of fuel cells in ferries and ocean-going passenger ships (the military sector has already used fuel cells at sea for many years, for example, in submarines). In addition, researchers are exploring whether the technology can be used in aviation. Niche applications also offer future market potential, e.g., highway service vehicles, construction site vehicles and other, comparable specialist vehicles, such as ground handling vehicles at airports or heavy goods vehicles for ports [8]. The possibilities for using fuel cell vehicles are more limited in applications that require very high energy density, such as international aviation and maritime transportation. In these areas, the primary focus is being placed on hydrogen-based synthetic and renewable fuels. Hydrogen and fuel cells are a more realistic option for national aviation and maritime transportation, and initial development and demonstration projects are underway. On the other hand, some applications have comparatively low energy density requirements. Due to questions of economic viability, most solutions in this context currently focus on battery electric vehicles and will most likely continue to do so in the future, e.g., for micromobility, bicycles and small and medium-sized passenger cars. Based on the knowledge currently available, a study by the Hydrogen Council [27] lists the following as the most promising areas of application for hydrogen and fuel cell combinations: medium- and heavy-duty trucks, long-distance buses (including for urban environments), large passenger cars and SUVs that require an extensive range, cab fleets, regional trains and forklifts. At present, fuel cell trucks are set to play an important role in Germany’s National Hydrogen Strategy. Due to European fleet limits and the greenhouse gas reduction targets that have been set for transportation in Germany, the truck sector must find ways of achieving decarbonization. Both fuel cell trucks and electric solutions (battery-powered trucks and trucks with overhead trolley lines) constitute important solutions to this challenge.

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Vehicle manufacturers are responding to this by temporarily halting their efforts to produce fuel cell vehicles in the passenger car sector and directing their attention to fuel cell trucks instead. Fuel cell buses were one of the first hydrogen mobility applications. A number of demonstration and pilot projects are already underway, and some small batches are currently in production [28]. The loss of space and weight is not as significant here as it is in trucks and cars. It has been demonstrated that fuel cells have very long service lives in such applications, because they are operated continuously over long periods of time. A refueling infrastructure has been established through regional bus services, with one refueling station supplying sufficient hydrogen to a small bus fleet operating on a regional basis. Many urban bus fleets are subsidized these days, which means that political decisions could promote early adoption in this segment. Fuel cell buses are also being considered as important contributors to the reduction of local emission pollution in cities. The Hydrogen Council study indicated that they could be a cost-effective means of decarbonizing the long-haul bus segment in particular [27]. In addition to buses and trucks, fuel cell trains will become more prominent in the future, because of technical and economic conditions and the influence that political decision-makers can exert. In 2017, diesel multiple units and trains hauled by diesel locomotives accounted for 242.5 million train-km, which amounts to 36 percent of the total operating performance of Germany’s local passenger rail service [29]. Efforts are underway to replace these, e.g., via the electrification of lines and the use of battery trains—and in recent years, the fuel cell option has also been the subject of increasing activity. According to project scenarios concerning future demand for hydrogen in transportation, demand levels are expected to remain reasonably low until 2030 (depending on the study and scenario in question, as much as optimistic figure of 21 TWh was predicted, with total final energy consumption in transportation ranging between 600 to 700 TWh) [4, 5, 30–33]. Hydrogen-based synthesis products could account for as much as an additional 10 TWh. The EU’s CO2 fleet limits for cars and trucks are driving early adoption here. By contrast, scientists are predicting high potential demand for hydrogen and synthesis products by 2050 (150 to 320 TWh, depending on the study and the projection scenario). International aviation and maritime transportation will undoubtedly have high demand levels. When combined with biogenic fuels, the synthetic products used in those sectors could potentially reach demand levels ranging from 150 and 200 TWh. In road freight transportation, potential demand for hydrogen could reach 40 TWh in 2050 [30], while demand in road passenger transportation could range from over 50 to over 80 TWh [33].

3.5 Potential hydrogen demand and the economic situation

43

3.5.3 Heating sector The extent that hydrogen will be used as an energy carrier to cover the future heating demand will be determined by a variety of factors. One such factor relates to the current structure of the heating market in the building sector. In 2019, the demand for heat amounted to 855 TWh [34]. The most commonly used technologies here are gas boilers (50 percent), followed by oil boilers (25 percent) and district heating (14 percent). This is why Germany has a very extensive natural gas network. In new buildings, heat pumps already account for a share of 30 percent and this share is increasing rapidly [35, 36]. Solutions for the heating transition focus on two basic courses of action, namely switching from fossil fuels to carbon-free energy carriers and reducing heat demand by renovating existing buildings or increasing insulation standards in new builds. The second determining factor relates to the availability of suitable technologies and their economic advantages. The key technologies for heat supply based on renewable energies are heat pumps and what is known as “green district heating.” Heat pumps draw two thirds of their supply from ambient heat and one third from renewable electricity. Low-carbon district heating can be supplied by means of heat pumps, solar thermal energy or biomass. Hydrogen is also an option here, as it can be burned in adapted boilers or converted into heat and electricity in fuel cells. Consequently, the future potential demand for H2 as a source of heat in the building sector can be calculated based on the extent to which demand is reduced and a comparative assessment of renewable energy carriers and conversion technologies. One of the first criteria that must be addressed in this comparison is energy efficiency, i.e., how many kWh of renewable electricity it takes to generate 1 kWh of heat. With an annual coefficient of performance of 3.5 in new or refurbished buildings and 2.8 in unrefurbished buildings, heat pumps are around five times more efficient than burning hydrogen in a boiler. Even if electrolysis with a 54 percent efficiency rate is used and the waste heat from the process is recovered, a heat pump would still be three times more efficient. Manufacturing and transportation costs are another important factor. Although electricity production costs remain the same, lower hydrogen transportation costs can make the use of remote locations with high levels of sunshine or high wind power potential more economically attractive. When it comes to converting gas distribution networks to hydrogen or constructing new networks for that purpose, much clarification is still required in terms of the technical issues and costs involved. Initial estimates assume that gas transportation and distribution costs will double. Nevertheless, this is likely to be somewhat cheaper than building and operating power grids. There is some market

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Fig. 3.10 Comparison of projected final energy consumption for the building (residential and services) sector in 2050 [20]

availability for heat generators that can use H2 , such as fuel cells, for example, although as yet, they are only available as heating appliances with very low power ratings. Significant advancements have been made in the development of hydrogen boilers and the first devices are undergoing in field testing (see Chap. 7; [37]). Different projection scenarios for the development of the German energy system up to the year 2050 give different estimates as regards the demand for hydrogen in the residential and services sectors. All of the scenario analyses indicate that the demand for hydrogen in the year 2030 will either be very low or non-existent (< 1 TWh). The only scenarios that reported higher quantities were those with predetermined demand figures [20]. The model calculations predict very different developments in the demand for hydrogen for 2050. Fig. 3.10 shows the final energy consumption for heating, cooling and electrical devices projected in different studies. The most common energy carriers for the building sector in 2050 are expected to be electricity, ambient heat and district heating. The differences in the total quantities result from the studies’ differing assumptions regarding the extent and quality of the refurbishment measures carried out and the development in spatial demand for living and offices. For hydrogen, synthetic fuels and biomass, a total demand of between 17 to 281 TWh is expected. According to the studies’ calculations, hydrogen demand will range between 0 to 36 TWh, or 0 to

3.5 Potential hydrogen demand and the economic situation

45

9 percent of the final energy consumption in the building sector. Studies that assumed restrictions will be placed on technological competitors such as the direct use of electricity (as in the “Beharrung” (persistence) and “Inakzeptanz” (nonacceptance) scenarios from the ISE’s study on the energy transition) predicted demand levels of 76 TWh, which is around 11 percent of the final energy consumption in the building sector. In general, the studies did not take decentralized, energy-self-sufficient solutions into account [20].

3.5.4

Energy systems sector

While expanding renewable energies will be the main driver in the energy sector, hydrogen will also play a role in reducing CO2 emissions. This gives rise to two basic questions, which are discussed below:  In the long term (i.e., by 2050), how much hydrogen must we convert into electricity to ensure security of supply?  Could the direct use of hydrogen as a fuel instead of natural gas offer an edge in terms of efficiency? And what decisions must we make as regards infrastructure in this context by 2050?

The long-term perspective A publication by Fraunhofer IEE [38] optimized a European zero-emission projection scenario for 2050 to allow for a range of possible hydrogen import prices. The projection is based on the assumption that all gas turbines can run on 100 percent hydrogen, although the study did not include existing gas-fired power plants. In this scenario, Germany’s consumption of electricity from hydrogen reconversion is around 1000 TWh, with large portions of that stemming from onshore wind generation.

Demand for hydrogen-to-electricity conversion In the European Union (including the UK, Norway and Switzerland), demand for the (re)conversion of hydrogen into electricity is expected to range between 70 TWhel [6] and 271 or 293 TWhel [38]. These calculations are based on the assumption that H2 imports will cost either 94 or 79 euros/MWh. If the efficiency rate is 40 percent, this results in H2 demand levels of up to 733 TWh. As Germany has a central location and can easily import electricity from neighboring countries, its need to convert hydrogen into electricity is very low in comparison to the rest

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of the EU. At 31 or 34 TWhel , Germany accounts for only a small portion of the total demand here. These demand ranges are based on scenarios that assume renewable energy will be fed into the electricity market. For the most part, hydrogen will be used for a relatively low number of hours when compared to electricity, and at times where the renewable energy feed-in is very low. This means that, allowing for conversion losses, the European energy sector will be a significant driver of hydrogen demand, although to a lesser extent than the industry sector. Current projection scenarios estimate an installed capacity ranging from 100 GW [6] to 176 or 184 GW [38] for hydrogen-based electricity generators in Europe.

Technologies for hydrogen-to-electricity conversion At a technological level, converting hydrogen into electricity requires flexible systems that can remain economically viable even when operating at a low degree of utilization. New gas turbines that can run on hydrogen constitute a viable option here. In this case, most of the re-conversion activities would take place at CHP plants. Different negative emissions projection scenarios (such as using BECCS wood-fired heating plants for industrial process heat) envision different proportions of the various types of heat generated here, i.e. district heat, process heat, and conventional condensing power plants. In such situations, CHP would represent a relatively low proportion of the heat generation for district and process heat. Large heat pumps and electrode boilers are the prevailing heat generation technologies in these systems. If high-temperature fuel cells that required lower specific investments were to become available, they could also be used to help cover peak load times for the power supply in individual buildings or used in combination in district heating or industrial process heat applications for temperatures of up to 200 °C, depending on the decentralized H2 infrastructure available. Existing gas turbines could remain in use in the future, if run on synthetic natural gas (SNG) derived from hydrogen. If gas networks are completely transformed for hydrogen transportation, it would be possible to transition to an LNG infrastructure so that existing gas turbines can continue to operate. Back-up power plants ensure security of supply for power grids if extreme events occur and are not used in the electricity market. As demonstrated by the EnBW AG grid stability plant, which serves the grid operator TransnetBW in Marbach2 , these plants can be supplied with PtL fuels outside of the infrastructure. If it 2

For more information, see: https://www.enbw.com/unternehmen/konzern/ energieerzeugung/neubau-und-projekte/netzstabilitaetsanlage-marbach/ (German only).

3.5 Potential hydrogen demand and the economic situation

47

is not possible to use or construct large-scale infrastructures such as transport networks for hydrogen supply, the next option to explore is whether it is economically viable to supply and store hydrogen in close proximity to the power generation plants.

Transformation pathways When it comes to operating existing gas turbines, the German Technical and Scientific Association for Gas and Water (DVGW) Code of Practice G 262 (A) sets clear restrictions on H2 content, as this can impact the gas turbine’s the sealing elements in particular and cause problems with flame flashback. Depending on the gas turbine manufacturer, the H2 limits for existing plants range from 1 to 5 vol%. As an alternative, ammonia can be blended into the fossil natural gas, whereby the ammonia is responsible for up to 20 percent of the lower heating value, in order to indirectly increase the hydrogen content in the gas turbine [39, 40]. In Japan, for example, plans are in place to achieve this blending proportion by 20303. Ammonia is produced via the Haber-Bosch process, which is more efficient and less expensive than methanizing synthetic natural gas (SNG). Similarly, using hydrogen directly as part of the transformation pathway results in more efficient renewable energy generation when compared to PtL or PtG. In principle, using hydrogen directly in new, gas-fired power plants is around 30 percent more efficient than synthesizing SNG from green hydrogen (which results in a high degree of loss) for use in conventional gas-fired power plants, although this is dependent on loss during transportation. If a hydrogen network is created at an early stage, this technology can be implemented on a locationspecific basis. For plants with a power rating of less than 100 MW, gas turbines that use pure hydrogen as fuel are already available today. However, they can only be used in certain limited to industry applications. More research is still required in some areas to reduce costs and to design plants that can run on hydrogen even within the largest power rating classes, as well as to increase the tolerance range for hydrogen blending within the plants. Converting Germany’s entire gas network to hydrogen would be a long and laborious process, which gives rise to the question as to whether long-term investments in new, gas turbines that can run on hydrogen will create a lock-in effect. It is possible to blend hydrogen with methane up to a certain percentage. All European turbine manufacturers have made a voluntary commitment to ensure that new 3

For more information, see Japan’s “Green Growth Strategy” from December 2020: https://www.meti.go.jp/english/press/2020/1225_001.html.

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plants can tolerate hydrogen blending of 20 vol% from 2020 and can operate on 100 percent hydrogen by 2030.4 Plans are in place to run the new gas turbines in Leipzig’s district heating system on 30 to 50 vol% hydrogen in just a few years, although they only commenced operations in 2022.5 In spite of this, it must be noted that hydrogen content of 20 vol% only corresponds to 7 to 8 percent of the energy in terms of lower heating value. However, if the hydrogen content is increased to 100 percent, the gas turbine’s combustion chamber must be replaced, which means that costs are incurred for plant retrofitting. For (high-temperature) fuel cells, it may still be necessary to account for lockin effects, as these systems must be designed for either hydrogen or natural gas. Steam reforming of natural gas is (partly) integrated into SOFCs, and takes place as an endothermic partial reaction due to the high operating temperatures in the anode compartment; the stack provides waste heat for the reforming reaction here. If this process were used, the stack would require additional cooling due to the conversion from CH4 to H2 . It remains to be seen whether it would possible to compensate for this additional need afterward, as well as how much this would cost. The natural gas reforming does take place externally in the case of PEMs. However, if a hydrogen conversion is required, the working pressure would have to be adjusted by means of system retrofitting. As it stands, fuel cells have significantly shorter service lives than gas turbines. In addition, fuel cells are operated in distribution networks with low pressure levels, and would only have been converted to hydrogen at a later point than areas of the network where gas turbines are operated. It is also expected that small gaspowered CHP units will not create such a significant lock-in effect, because, as indicated by the DVGW, these can tolerate hydrogen blending up to 20 vol% [41] and they are also likely to have shorter service lives than turbines. Gas-powered CHP units that run entirely on hydrogen are already undergoing testing in pilot plants,6 although some questions must still be resolved before they can commence permanent operations.

4

For more information, see: https://www.euturbines.eu/publications/spotlight-on/spotlighton-turbines-and-renewable-gases.html. 5 For more information, see: https://press.siemens-energy.com/global/en/pressrelease/gasturbines-siemens-energy-are-providing-leipzig-climate-neutral-power-supply. 6 For more information, see: https://www.stwhas.de/pressemitteilungen/hassfurt-nimmtwasserstoff-blockheizkraftwerk-erfolgreich-in-betrieb (German only).

References

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References 1. Eichhammer W., Oberle S., Händel M. et al. (2019): Etude sur les Opportunites et Priorites du “Power-to-X” au Maroc (Study on the opportunities and priorities for “power-to-X” in Morocco). Study sponsored by the BMWK and conducted by Fraunhofer ISI 2. Weichenhain U., Lange, S., Koolen J. et al. (2020): Potenziale der Wasserstoffund Brennstoffzellen-Industrie in Baden-Württemberg (Potential of the hydrogen and fuel cell industry in Baden-Württemberg). https://www.e-mobilbw.de/service/ meldungen-detail/neue-studie-zur-wasserstoff-und-brennstoffzellenindustrie-inbaden-wuerttemberg, last viewed on November 27, 2021 3. NOW (2018): Studie IndWEDe – Industrialisierung der Wasserelektrolyse in Deutschland: Chancen und Herausforderungen für nachhaltigen Wasserstoff für Verkehr, Strom und Wärme (IndWEDe study—industrialization of water electrolysis in Germany: opportunities and challenges for sustainable hydrogen for transportation, electricity and heat). https://www.ipa.fraunhofer.de/content/dam/ipa/de/documents/Publikationen/ Studien/Studie-IndWEDe.pdf, last viewed on November 27, 2021 4. BDI, BCG, prognos (2018): Klimapfade für Deutschland. Studie (Climate pathways for Germany, study). https://bdi.eu/publication/news/klimapfade-fuer-deutschland/, last viewed on November 27, 2021 5. German Energy Agency (2018): dena Study Integrated Energy Transition. https://www. dena.de/en/topics-projects/projects/energy-systems/dena-study-integrated-energytransition/, last viewed on November 27, 2021 6. Hebling C., Ragwitz M., Fleiter T. et al. (2019): A hydrogen roadmap for Germany. Fraunhofer ISI & ISE, Karlsruhe and Freiburg 7. BMWK (2020): Wegbereiter für die Energieträger der Zukunft. Die nationale Wasserstoffstrategie – eine Weiterentwicklung der Energiewende (Paving the way for the energy carriers of the future. The national hydrogen strategy—a further development of the energy transition). In: BMWK (ed.): Schlaglichter der Wirtschaftspolitik (Industry policy highlights). August 2020. Berlin, 64 p. 1 8. Weichenhain U., Lange, S., Koolen J. et al. (2020): Potenziale der Wasserstoff- und Brennstoffzellen-Industrie in Baden-Württemberg (Potential of the hydrogen and fuel cell industry in Baden-Württemberg). Roland Berger GmbH, Munich. 150 p. 9. BMWK (2020): The National Hydrogen Strategy. Berlin, 32 p. 1 10. Fuel Cells and Hydrogen Joint Undertaking (2019): Hydrogen Roadmap Europe. A sustainable pathway for the European energy transition. https://www.fch.europa.eu/sites/ default/files/Hydrogen%20Roadmap%20Europe_Report.pdf, last viewed on January 21, 2019 11. DWV (2018): Grüne Wasserstoff-Industrie – Lösung für den Strukturwandel? (A green hydrogen industry—a solution for the structural transformation?). https://www.dwvinfo.de/wp-content/uploads/2015/06/20181128-Pos.-Papier-zu-Strukturwandel-final. pdf, last viewed on November 27, 2021 12. Spath D., Bauer W., Voigt S. et al. (2012): Elektromobilität und Beschäftigung – Wirkungen der Elektrifizierung des Antriebsstrangs auf Beschäftigung und Standortumgebung (ELAB) (Electromobility and employment—effects of powertrain electrification on em-

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The potential of a hydrogen economy: an economic and social perspective

ployment and the site environment (ELAB)). Fraunhofer Verlag (publishing house), Stuttgart Hydrogen Council (2017): Hydrogen scaling up—A sustainable pathway for the global energy transition. https://hydrogencouncil.com/wp-content/uploads/2017/11/HydrogenScaling-up_Hydrogen-Council_2017.compressed.pdf Lozanovski A., Schuller O., Faltenbacher M. et al. (2013): Guidance document for performing LCA on hydrogen production systems. Fraunhofer Verlag (publishing house), Stuttgart Sphera Solutions GmbH (1992): GaBi Software System and Database for Life Cycle Engineering. Leinfelden-Echterdingen Upham P., Oltra C., Bosoc À. (2015): Towards a cross-paradigmatic framework of the social acceptance of energy systems. Energy Research & Social Science 8: 100–112 Schneider U., Dütschke E., Oltra C. et al. (2017): Wasserstoff als neuer Energieträger (Hydrogen as a new energy carrier). HYACINTH: Europaweite Akzeptanzbefragungen (HYACINTH: Europe-wide support surveys). HZwei. Das Magazin für Wasserstoff und Brennstoffzellen (HTwo. The magazine for hydrogen and fuel cells). 17 (1): 31–32 Bögel P.M., Oltra C., Sala R. et al. (2018): The role of attitudes in technology acceptance management. Reflections on the case of hydrogen fuel cells in Europe. Journal of Cleaner Production 188: 125–135. https://doi.org/10.1016/j.jclepro.2018.03.266 Upham P., Dütschk, E., Schneide, U. et al. (2018): Agency and structure in a sociotechnical transition. Hydrogen fuel cells, conjunctural knowledge and structuration in Europe. Energy Research & Social Science 37: 163–174. https://doi.org/10.1016/j.erss.2017.09. 040 Wietschel M., Hebling, C., Ragwitz M. et al. (2021): Metastudie Wasserstoff – Auswertung von Energiesystemstudien (Hydrogen metastudy—evaluation of energy system studies). Study commissioned by the German National Hydrogen Council. Karlsruhe, Freiburg, Cottbus: Fraunhofer ISI, Fraunhofer ISE, Fraunhofer IEG (eds.). BMU (2018): Klimaschutz in Zahlen (2018) – Fakten, Trends und Impulse deutscher Klimapolitik (Climate protection in figures (2018)—facts, trends and motivating factors in German climate policy). AGEB (2020): Auswertungstabellen zur Energiebilanz Deutschland (Evaluation tables for the German energy audit). 1990 to 2018. Arbeitsgemeinschaft Energiebilanzen e. V. (Association for energy auditing). German Energy Agency (2018): dena – Factsheet Erdölraffinerie (Crude oil refinery fact sheet) European Parliament (2018): Renewable Energy Directive. Official Journal of the European Union (61). http://data.europa.eu/eli/dir/2018/2001/2018-12-21 Herz G., Müller N., Adam P. et al. (2020): Grüner Wasserstoff in der Rohstahlerzeugung (Green hydrogen in crude steel production). Stahl und Eisen (Steel and iron) 140: 14–18 Neuwirth, M. et al. (2022): The future potential hydrogen demand in energy-intensive industries—a site-specific approach applied to Germany. Energy Conversion and Management 252: 115052. https://doi.org/10.1016/j.enconman.2021.115052 Hydrogen Council (2020): Path to hydrogen competitiveness—A cost perspective Ehret O. (2020): Wasserstoffmobilität – Stand, Trends, Perspektiven (Hydrogen mobility—status, trends, outlook). Study by Center of Automotive Management (CAM). Bonn, 112 p.

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29. NOW GmbH (2020): Marktanalyse alternativer Antriebe im deutschen Schienenpersonennahverkehr (Market analysis of alternative drive systems in German local rail passenger transport). Berlin, 19 p. 30. Prognos, Öko-Institut, Wuppertal-Institut (2020): Klimaneutrales Deutschland: In drei Schritten zu null Treibhausgasen bis 2050 über ein Zwischenziel von 65% im Jahr 2030 als Teil des EU-Green-Deals (Climate-neutral Germany: Three steps to zero greenhouse gases by 2050, with an interim target of 65 percent in 2030 under the EU Green Deal) 31. German Environment Agency (2019): Wege in eine ressourcenschonende Treibhausgasneutralität. RESCUE-Studie (Pathways to resource-efficient climate neutrality. RESCUE study). Dessau 32. Sterchele P., Brandes J., Heilig J. et al. (2020): Wege zu einem klimaneutralen Energiesystem – Die Deutsche Energiewende im Kontext gesellschaftlicher Verhaltensweisen (Pathways to a climate-neutral energy system—the German energy transition in the context of social behavior). Fraunhofer ISE, Freiburg 33. Robinius M., Markewitz P., Lopion P. et al. (2020): Wege für die Energiewende. Kosteneffiziente und klimagerechte Transformationsstrategien für das deutsche Energiesystem bis zum Jahr 2050 (Pathways for the energy transition. Cost-efficient and climatefriendly transformation strategies for the German energy system up to the year 2050). 34. BMWK (2021): Die Energie der Zukunft. 8. Monitoring-Bericht zur Energiewende – Berichtsjahre 2018 und 2019 (The energy of the future. Monitoring report on the energy transition—reporting years 2018 and 2019). Berlin 35. BDEW (2020): Beheizungsstruktur des Wohnungsbestandes 2019 (Heating structure of existing housing stock 2019). Bundesverband der Energie- und Wasserwirtschaft e. V. (German Association of Energy and Water Industries). 36. BDEW (2020): Beheizungsstruktur des Wohnungsneubaus 2019 (Heating structure of residential new builds in 2019). Bundesverband der Energie- und Wasserwirtschaft e. V. (German Association of Energy and Water Industries). 37. Meyer R., Herkel S., Kost C. (2021): Die Rolle von Wasserstoff im Gebäudesektor: Vergleich technischer Möglichkeiten und Kosten defossilisierter Optionen der Wärmeerzeugung (The role of hydrogen in the building sector: comparison of technical possibilities and the costs of options for defossilized heat generation). Ariadne analysis, https://ariadneprojekt.de/media/2021/09/Ariadne-Analyse_ WasserstoffGebaeudesektor_September2021.pdf 38. Frischmuth F., Härtel P. (2022): Hydrogen sourcing strategies and cross-sectoral flexibility trade-offs in net-neutral energy scenarios for Europe. Energy 238, Part B: 121598. https://doi.org/10.1016/j.energy.2021.121598 39. Ito S., Uchida M., Onishi S. et al. (2018): Performance of Ammonia-Natural Gas CoFired Gas Turbine for Power Generation. 15th Annual NH3 Fuel Conference, Pittsburgh 40. Ayaz, S.K., Altuntas, O., Caliskan, H. (2018): Effect of ammonia fuel fraction on the exergetic performance of a gas turbine. Energy Procedia (144): 150–156. https://doi.org/ 10.1016/j.egypro.2018.06.020, last viewed on March 22, 2021 41. DVGW (2013): Entwicklung von modularen Konzepten zur Erzeugung, Speicherung und Einspeisung von Wasserstoff und Methan ins Erdgasnetz (Developing modular concepts for the production, storage and injection of hydrogen and methane into the natural gas grid)

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Hydrogen technologies in energy systems

Jochen Bard  Norman Gerhardt  Marie Plaisir  Ramona Schröer Fraunhofer Institute for Energy Economics and Energy System Technology IEE Anne Held Fraunhofer Institute for Systems and Innovation Research ISI Hans-Martin Henning  Christoph Kost Fraunhofer Institute for Solar Energy Systems ISE Benjamin Pfluger  Mario Ragwitz Fraunhofer Research Institution for Energy Infrastructures and Geothermal Systems IEG Andreas Reuter Fraunhofer Institute for Wind Energy Systems IWES Abstract

This chapter compares the role of hydrogen and synthetic energy carriers in energy systems and discusses certain aspects of them. To this end, we have examined systemic studies that consider the existing interactions between demand, production, facility locations and the construction and use of power, gas and heating networks.

© Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_4

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4.1

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Introduction

Our current energy system is dominated by the use of fossil fuels—coal, oil and gas. These energy carriers supply over 80 percent of the global primary energy supply [1]. The goal of completely defossilizing the energy system by the middle of this century raises the question of the role that hydrogen and hydrogen-based synthetic energy carriers will play. The main objective of increasing the use of hydrogen in the energy system is to replace fossil fuels with climate-neutral energy carriers, particularly where the direct use of renewable energies for electricity or heat is only possible to a limited extent, or not possible at all. In addition to producing hydrogen using electrolysis processes powered by electricity generated from renewable sources (“green hydrogen”), it can also be produced in a climatefriendly manner through steam reforming using natural gas in combination with capturing and storing CO2 (“blue hydrogen”). In the future, there may be additional, low-carbon technological options for producing hydrogen from methane via pyrolysis processes that produce solid carbon (“turquoise hydrogen”). Hydrogen, in addition to serving as an energy source itself, can help to integrate renewable energies into the energy system. This is because it and its derivative products can easily be stored, which provides a degree of flexibility. Current studies show that very substantial reductions in greenhouse gas emissions create a high demand for hydrogen and synthetic energy carriers. However, in previous initiatives for reducing greenhouse gas, hydrogen and synthetic energy carriers have only played a minor role due to their higher costs, as other options were more economical. There are many factors that influence how large the reduction target must be before significant quantities of hydrogen and synthetic energy carriers are needed. These factors include the economic structure and seasonal energy trends, as well as the cost developments for the necessary technologies for production and transportation. The question of the role and importance of hydrogen technologies in creating a climate-neutral energy system will be investigated in this chapter. As a basic system for comparing different methods and technologies for planning transformation pathways, Wietschel et al. defined a governance structure with four steps for transforming energy systems, which essentially comprises a list of the respective CO2 avoidance costs [2]. In the first step, priority is given to achieving a reduction in the demand for energy using the principle that energy efficiency should come first. The second step focuses on defossilizing the energy sector using renewable energies. Step three involves direct use of hydrogen to generate electricity and the direct use of sustainable biomass/biofuels/biogas (e.g. electromobility),

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taking into account their limited availability. Only then can hydrogen and synthetic energy carriers be brought into use for applications that are not addressed in any of the first three steps. These applications include air travel, heavy-goods transportation and international shipping as well as industrial applications such as steel production or chemical raw materials (using carbon from CO2 ) [3]. On a political level, the EU recognized the role of hydrogen as part of its Hydrogen Strategy, which it passed in July 2020 [4]. Its aim is to prioritize green hydrogen and promote its use in the long term; however, in the short to medium term, hydrogen that produces less CO2 (e.g., blue hydrogen) may be used. In terms of expansion, the EU specifically aims to achieve electrolysis capacity of at least 6 GW by 2024, and to increase this to at least 40 GW by 2030. The hydrogen strategy also sets out plans for collaboration with neighboring regions, such as the MENA region or Ukraine, and contains estimates for an electrolysis capacity of approx. 40 GW in the EU’s eastern and southern neighbors. In summer of 2020, Germany also published a National Hydrogen Strategy (NWS), which recognized the important role of hydrogen for defossilizing energy systems and set out a framework for investing in carbon-neutral hydrogen [5]. There are several conceivable paths that could be taken to achieve defossilization, using different proportions of hydrogen and synthetic energy carriers in energy systems. For example, these could either be based on large amounts of direct electrification, focusing on the use of hydrogen or accelerating the use of synthetic energy carriers; these pathways will lead to very different levels of demand. This means there is a huge amount of uncertainty around the development of demand for hydrogen and synthetic energy carriers based on hydrogen. Current studies show a wide range of demand levels (see Sect. 3.5), which has a major effect on the role of hydrogen and synthetic energy carriers in energy systems. However, the vast majority of the scenarios show that hydrogen plays an important role in energy systems when it comes to achieving greenhouse gas reduction targets of around 80 percent in comparison to the year 1990. This context gives rise to certain questions that relate to demand; these will be discussed in this chapter:  The role hydrogen and synthetic energy carriers will have in greenhouse-gasneutral energy systems: First, there is the question of how and where the required amounts of hydrogen and synthetic energy carriers will be produced. This section will also investigate which fields of application and sectors will need hydrogen and synthetic energy carriers, as well as exploring what quantities will be required and how they will be used.

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 Location analysis: A key question regarding the role of hydrogen in energy systems is where the electrolysis systems will be located. It can be beneficial to position these close to the potential locations where renewable energy may be generated, or in closer proximity to the load center, i.e., in the area where the energy will be used. These options will be discussed and explained in Sect. 4.3.  Direct hydrogen production from offshore wind energy: Finally, the question will be examined of whether it is technically possible to produce hydrogen directly using offshore wind energy, and whether this presents an economically competitive option for producing the required amounts of green hydrogen.  Infrastructure requirements: When it comes to using hydrogen in the future, a necessary expansion of infrastructure is a key issue that must be considered. This raises questions such as: Is the transmission grid a possible bottleneck in the context of increased power feed-in from (offshore) wind farms? And what amount of offshore energy can be directly integrated into the energy system? This, in turn, again raises the question of which location is most suitable for the electrolyzers, in order to relieve the load on the grid. It must be asked whether electrolyzers can be used for redispatching power—and if so, how curtailing renewable energy can be avoided.

4.2

The role of hydrogen and synthetic energy carriers in energy systems by 2050

What would a greenhouse-gas-neutral, consistent energy system for Germany look like in 2050, if hydrogen and synthetic energy carriers were key components? Further questions must be answered for this:  How and where can the necessary amounts of energy be produced?  How much energy is used in which applications? This section will give some initial answers to these questions; however, the following sections will further discuss these issues in terms of systemic impact. To visualize targets such as this, system analyses are conducted at Fraunhofer ISE using the energy system model REMod. REMod calculates the quantitative cost structure for an energy system that is climate-neutral, or almost climateneutral, and compares possible transformation pathways that could be taken between now and the year 2050. With regard to the energy system as a whole in 2050, it must be noted that hydrogen and synthetic fuels will only cover part of the final energy demand. The

4.2 The role of hydrogen and synthetic energy carriers in energy systems by 2050

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Fig. 4.1 Energy flow diagram (Sankey diagram) for a potential German energy system in the year 2050 (annual energy flow in TWh). (Fraunhofer ISE)

energy flow diagram in Fig. 4.1 shows the energy flow from primary energy to final energy in a potential energy system in 2050. The high proportion of electric energy from wind power and photovoltaics forms the backbone of the energy system. Electricity will be used as the main energy carrier for numerous direct applications in the final energy sector, such as electromobility and heat pumps for space heating as well as many applications in industry. However, when taking a closer look at the center of the energy flow diagram, it becomes apparent that a significant portion of the electricity generated in Germany is used to produce hydrogen and synthetic energy carriers. Of the hydrogen produced, a large amount is used in transportation and industry, while a smaller proportion is used for heating in buildings. Reconverting hydrogen also plays an important role in making the energy system secure. However, the amounts of energy needed for the reconversion process are relatively low. Here, the capacity of the hydrogen turbines is crucial to ensuring the security of the system for a few hours. Nevertheless, the depicted scenario shows that a large proportion of synthetic energy carriers from outside Germany flow through to the transportation sector. With regard to the installed capacity of renewable energy, we see that a total capacity of around 400 GW from photovoltaics and 250 GW from wind power is needed to supply this kind of system. However, this means such systems generate huge amounts of energy that must be integrated into the system and must also be partially stored. There are several options here. First of all, energy can be stored using stationary energy storage systems, but also through flexible opera-

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tion or charging for heat pumps (and their thermal storage systems) and electric cars. Second, renewable electricity can be used to produce hydrogen and synthetic energy carriers, which can also be stored for long periods of time until use. This makes it possible to separate energy generation and consumption in the system, and also prevents curtailment of renewable energies during periods with low electricity demand. Different scenarios will be compared below, all of which assume that Germany has a remaining budget of 9 Gt for energy-related greenhouse gas emissions. Each scenario used REMod to conduct model calculations for a climate-neutral Germany in 2050. Depending on the scenario, these calculations predicted that demand for hydrogen and synthetic energy carriers would range from 300 to 800 TWh annually (Fig. 4.2). The scenarios focus on using a balance of technologies (Bal), increased use of electricity (Elec), increased use of hydrogen (H2 ) and on using synthetic energy carriers (SynF). The amount of energy coming from synthetic energy carriers in 2020 was under 50 TWh, with the majority being used as biomass blended in fuels in the transportation sector or biogas in power plants. This amount will increase to between 100 and 200 TWh by 2030, depending on the scenario. In 2030, increasing the use of biomass produced in Germany (by continuing to blend it with fuels) will play a crucial role in the transportation sector. The first large-scale production of hydrogen in electrolyzers is expected to take place in Germany. This production of new green or carbon-free fuel options will be supplemented with imported synthetic liquid fuels and hydrogen. The further the energy transition advances, the more synthetic energy carriers will be required to replace the conventional energy carriers of oil and gas in many applications. By 2050, the amounts needed will increase to between 300 and 900 TWh per year; in the scenarios addressed here, the amount is 500 to 900 TWh, up to 60 percent of which could be imported. This means that domestic production of synthetic energy carriers and the use of biomass will also increase to between 300 and 500 TWh. However, the four different scenarios also illustrate that the range of potential quantities can vary hugely. In 2050, a “balanced” energy sector will spread the demand across hydrogen, liquid synthetic energy carriers and gaseous energy carriers based on methane (or natural gas). In a world relying heavily on electricity, the use of synthetic energy carriers would decrease to around 500 TWh per year, as the direct use of electricity would be given preference. If import prices are inexpensive or there are high volumes of imported energy available from outside Germany, the required amounts of pure hydrogen and synthetic liquid energy carriers could both increase to between 300 and 400 TWh. Scenarios such as this rely heavily on the existing hydrogen transportation options and the application technologies that are used. This means that it will be

4.2 The role of hydrogen and synthetic energy carriers in energy systems by 2050

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Fig. 4.2 Synthetic energy carriers including use of biomass in fuels in different scenarios (with varied CO2 targets and assumed price (O = optimistic import price)). 9 Gt is used as the budget for energy-related CO2 emissions for Germany until 2050. Bal = balance of technologies, Elec = heavy focus on electricity, H2 = focus on using hydrogen in many applications, SynF = focus on liquid synthetic energy carriers

crucially important to further develop the competing technologies that use hydrogen or synthetic energy carriers, both at a technical and economic level. In comparison to scenarios with high use of pure hydrogen in fuel cell applications or in industrial sectors, the possibility of cheaply importing liquid synthetic energy carriers (methanol, ammonia) allows the system to continue using conventional combustion engines or closely related technologies in heavy-goods transportation, aviation or even passenger transportation to some extent. On the other hand, this means these fields of application will not need to use any new technologies, which are often electricity-based. As Fig. 4.2 shows, importing liquid synthetic energy carriers is given preference due to their transportability and low costs. The reason for this is that locally produced hydrogen can easily be provided in Germany if it can be fed directly into hydrogen grids without being liquefied for transportation. To produce the hydrogen, the energy system requires electrolyzers with high capacity and further generation units for the synthetic energy carriers (such as separation and liquefaction systems). Fig. 4.3 shows the required electrolyzer capacity in different scenarios for the year 2050. If there are still a few gigawatts of

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Fig. 4.3 The capacity of electrolyzers in Germany in the year 2050. (Fraunhofer ISE)

electrolyzer capacity used to produce hydrogen in 2030, the capacity in 2050 will increase to around 40 GW to 90 GW. The decisive factors influencing this capacity are the demand for synthetic energy carriers and the competitiveness of Germany as a location for operating electrolyzers. In the scenarios shown here, the high capacity of the hydrogen scenario (9GT_H2) stands out. This scenario assumes that the applied technologies in industry, transportation and heating in buildings will primarily be based on conventional combustion technologies. That means in 2050, there will still be a high demand for synthetic energy carriers to be burned in these systems. From this study, it is important to note that the overall costs of this type of solution are higher in the balanced scenario (9GT_Bal), for example, where hydrogen and synthetic fuels are used to a lesser extent. However, even these amounts of use would require extremely intensive marketing activities to complete electrolyzer rollout in the coming years. Using flexible energy demand units, and hydrogen and synthetic gaseous and liquid energy carriers, it is possible to ensure that renewable power generation and the direct and indirect use of energy interact with extreme efficiency. To illustrate this, the diagram shows electricity generation (Fig. 4.4 above) and electricity use (Fig. 4.4 below) in a potential energy system in the year 2050 for a given week in which a high amount of solar and wind power is generated.

4.3 Regional factors in supply and demand

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Fig. 4.4 Electricity generation and use in the year 2050 [6]

It is clear that, although there are other options for making the system more flexible, electrolyzers are operated in such a way that feed-in peaks from renewable energies can be used to convert renewable energy to hydrogen and synthetic energy carriers when there is no other possible alternative use in the system.

4.3

Regional factors in supply and demand: possible locations for electrolyzers and renewable power generation

The following section will investigate which locations in Germany are suitable for electrolyzers. Hydrogen is currently being discussed as an option for different fields of application and for use as an energy carrier and in defossilization. This means that in the currently published scenarios, the use of hydrogen varies significantly in some cases:

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There is much scientific, political and public debate around whether hydrogen, or energy carriers produced from hydrogen, should be used in transportation or in heating for buildings, and if so, to what extent. On the other hand, we can be relatively certain that there will be demand for hydrogen in certain industry sectors. These include four processes in particular: Ammonia and ethylene production, primary steelmaking and desulfurizing fuels in refineries. Based on current knowledge, in principle, the first three of these processes can only be defossilized using hydrogen.1 Hydrogen is already being used today in the production of ammonia and ethylene; however, the hydrogen used either comes from blast furnace gas from other processes, e.g., in refineries, or is produced from natural gas through steam reforming. However, there is also discussion of whether these industrial sectors can remain in Germany in the long term, or whether (intermediate) products can start being produced in power-to-X export regions. In addition to industrial and political issues and questions of competitiveness, when it comes to ethylene, there is also the question of the long-term availability of climate-neutral CO2 sources in Germany. There is further uncertainty in regard to selecting locations for new hydrogen-based production processes. In addition to the needs of industry, it is believed that the conversion sector—particularly in the area of hydrogen-based power generation—is very likely or almost certain to create a considerable demand in the long-term. When compared to the use of synthetic methane or power-to-liquid in conventional gas turbines, the direct use of hydrogen in new H2 gas turbines or high-temperature fuel cells offers high efficiency and cost advantages. These advantages are due to the reduced losses in generation. There is also some uncertainty here regarding the use of hydrogen in condensing power plants, primarily for the purpose of relieving the strain on power grids, or in combination with the cogeneration of heat and power in heat sinks in industrial and commercial heating systems. From a current perspective, it appears that using cogeneration plants is only economically viable if hydrogen is available at a very low cost.

4.3.1 Discussions surrounding the location of hydrogen supply and demand Despite this uncertainty regarding the required amount of energy and specific locations, scenarios adapted to particular regions consistently show a clear distinction between the areas that produce hydrogen and those with a demand for hydro1

The balance and interactions within the power grid will also be discussed in Sect. 4.5.

4.3 Regional factors in supply and demand

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Fig. 4.5 Regional distribution of hydrogen demand in industry (left) and illustration of the demand and the resulting supply (in TWh) in the scenario focusing on electricity and green hydrogen (right) [8]

gen. In these scenarios, production tends to be mainly concentrated in the north of Germany, close to the wind energy that can potentially be obtained on land and offshore. This, among other things, is illustrated in the scenario focusing on electricity and green hydrogen, one of the long-term scenarios commissioned by the German Federal Ministry for Economic Affairs and Climate Action (BMWK) [7]. The investigations in this study also showed that obtaining hydrogen entirely through local sources is not really a viable option for fulfilling large industrial demands. In areas such as the Ruhr region, supplying electricity locally using on-site electrolyzers would require significant power grid expansion and large volumes of stored energy. Without the use of geological storage options (see Chap. 8), this would be virtually infeasible from a financial perspective. As outlined in the previous section, in order to meet the substantial demand for hydrogen, a hydrogen grid infrastructure is an absolute necessity. If the current production locations remain the same, hydrogen demand from the abovementioned industries will stem from around 25 locations; some of these are situated in close proximity to each other (Fig. 4.5). In this scenario, the H2 reconversion plants are predominantly located in the south of Germany. How far the future hydrogen grid will extend depends on which approach is taken—either expanding the power grid2 or expanding and converting the gas network. This means 2

The balance and interactions within the power grid will also be discussed in Sect. 4.5.

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that in addition to economic factors, public support will also be important here. The idea of creating a hydrogen grid that connects these locations (which are very few when compared to the number of exit points in the current natural gas network) appears to be reasonable and feasible. It can be at least partially created by converting the current natural gas network, and the overall costs are reasonably low when compared to other investments into the energy transition.

4.4

Direct hydrogen production from offshore wind energy from a European perspective

One option for producing hydrogen is to produce it directly using offshore wind energy. This section will discuss whether this option presents a technically feasible and economically viable method of producing the required amounts of green hydrogen. There is significant offshore wind potential in Germany and the EU, which could make a huge contribution to defossilizing the entire European energy system. However, from an economic standpoint, only some of this potential can be integrated into electrical grids, and the required grid expansion on land does limit the amount of electricity from offshore wind that can be used directly. On the other hand, producing hydrogen offshore creates the opportunity to use a significantly larger amount of the wind potential, as the produced hydrogen will be transported to shore via a pipeline and fed into pipeline-based transportation infrastructure in the future. In Northwestern Europe in particular, several factors come together: there is huge offshore wind potential and high demand for hydrogen in industry; part of the infrastructure needed for transportation and geological storage already exists; and there are harbors that could potentially be used for hydrogen imports. This creates considerable market prospects for the European offshore wind and hydrogen industries, increases their share of the total value chain compared to imports and reduces Europe’s dependence on imports for obtaining sustainably produced hydrogen.

4.4.1

Discussion of the quantities involved

The EU has set itself the target of increasing offshore wind capacity to between 300 and 450 GW by the year 2050. The current European energy scenarios show that it is economically viable to integrate around 200 GW of offshore wind capacity

4.4 Direct hydrogen production from offshore wind energy from a European perspective65

into the power grid for direct use in electricity. It can therefore be deduced that in the long term, between 25 and 50 percent of the offshore wind capacity can be used for producing hydrogen. 4500 full-load hours would produce around 450 to 700 TWh/a of hydrogen. It is assumed that hydrogen from onshore renewable energy has the potential to generate similar quantities of energy. However, there are major differences across the individual EU member states:  It is expected that the United Kingdom will have offshore wind capacity of between 75 and 100 GW for direct use in electricity—yet it has the potential to generate at least 600 GW. The UK could therefore become the largest exporter of hydrogen in Europe [8].  The Netherlands has offshore wind potential of around 68 GW. Assuming that the available grid capacity for integrating offshore wind is around 26 GW, this means there is an electrolysis capacity of around 30 GW that can be used in combination with offshore wind generation. The amount of hydrogen that can be produced—around 100 TWh—therefore exceeds the hydrogen demand expected in the long-term for direct use in the Netherlands.  In Germany, the offshore wind potential in the exclusive economic zone of the North Sea is around 53 GW; almost half of this can be integrated into the power grid in the long term (see Sect. 4.5). The areas situated far away from the coast (zones 4 and 5) are suitable for offshore hydrogen production with capacities of around 21 GW and 66 TWh/a. This corresponds to about a third of the estimated required quantity of direct hydrogen, which amounts to 200 TWh. Overall, it is expected that around 220 TWh will need to be imported for the EU (including the United Kingdom) from non-EU countries to cover direct hydrogen requirements. In the long term, a suitable method for transporting hydrogen within Europe would be converting existing natural gas infrastructures for transportation and storage, as well as slightly expanding the grid. In the long term, the European transmission system operators’ vision for a “European Hydrogen Backbone” also includes creating a connection to the MENA region. When compared with constructing an entirely new infrastructure, this would result in significant cost savings. In addition, it is also expected to create global trade in sustainable hydrogen and its derivative products. When it comes to fulfilling the demand for hydrogen in Europe, one possible option is to import liquid hydrogen by ship. Technical and economic synergies can be identified here in terms of sharing the necessary transportation and storage infrastructure with offshore hydrogen production facilities.

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System comparison

Different system configurations must be taken into consideration when it comes to producing hydrogen using offshore wind energy. One option is to electrically link offshore wind farms to hydrogen production facilities built in coastal regions; alternatively, hydrogen can also be produced directly offshore and transported to the coast via pipelines. Establishing large-scale electrolysis capacity along the coast is not technologically different from the system configuration outlined in Chap. 9. However, this must cover considerable amounts of wind power in the double-digit gigawatt range. This will require additional industrial space for hydrogen production, storage and transportation along the coast, as well as a source for the required quantities of fresh water. If the electrolysis sites are distributed along the coast, as becomes necessary when efforts are made to shorten offshore power lines, additional hydrogen pipelines will need to be built. To the greatest extent possible, the hydrogen production method must be adapted to the offshore wind supply. Remote offshore wind farms must also be electrically connected to the coast. This will require land for cable routes and numerous large offshore substations. There are also different possible approaches to offshore electrolysis. However, it is always necessary to carry out processes such as desalinating the sea water using downstream deionization—in contrast to electrolysis systems on land that have a fresh water supply. Furthermore, the incoming air must be filtered or dried and the cooling process needs to be adapted. Due to the higher maintenance costs for offshore installations, it makes economic sense to use redundant components to provide higher technical availability, for example, and longer maintenance intervals than are used with land-based systems. Overall, adapting systems to suit offshore operations will result in higher investment and maintenance costs for electrolysis. In terms of the system size, there are three different approaches that can be taken:

Electrolysis systems At the lower end of the power output spectrum, up to approx. 15 MW, electrolysis systems are designed for installation in individual wind turbine platforms. This enables the easiest possible structural integration of the electrolysis systems, which are designed specifically for the wind turbines’ outputs. The electrolysis output increases along with the wind energy capacity; however, a transportation solution for the hydrogen is required at the facility level. As the turbines are directly linked to the electrolyzers, electric power line connections are not needed—this creates new

4.4 Direct hydrogen production from offshore wind energy from a European perspective67

Fig. 4.6 Comparison of wind electrolysis system topologies

requirements for designing wind turbines. To date, wind turbines have been designed for grid-parallel operation, with the focus on achieving the lowest possible cost per kilowatt-hour and contributing to grid stability. This results in topologies with complex power electronics, which can achieve the desired targets when they are combined with rotor diameters that are very large when compared to the generator output. Operating electrolyzers independently of the grid allows for other approaches: there is usually a DC link available, and so the issue of electrical coupling can be addressed with much less effort. This results in cost reductions and increases in reliability due to the lower number of sensitive power electronics components involved. The design of the wind turbine itself and the optimal ratio of the rotor diameter to the size of the generator or electrolyzer, including the additional infrastructure—such as for water treatment—must now be thought of as one system up to the point that hydrogen is produced. This will allow the waste heat from the turbines to be used for purposes such as desalinating sea water. Depending on the

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respective requirements of the electrolyzers and their sensitivity to the fluctuating output levels from the wind turbines, the most economic setup must be found that is certain to create different results than classic turbines—for example, using even larger rotors in order to operate without causing large fluctuations in performance. When wind energy facilities for producing hydrogen are operated in island mode, a completely different approach is required in terms of the control technology and electronics. New operational models are needed, as grid stability must also be ensured in configurations where systems are linked directly, and the combination of wind turbines and electrolyzers must be operated at the optimum operating points depending on the respective wind speed.

Offshore platforms Another approach is based on installing offshore platforms that can handle large electrolysis capacities of a few hundred megawatts. In this case, similarly to the transformer platforms, each wind turbine has an individual electrical connection to the offshore platform. From each of these platforms, the hydrogen is transported via a pipeline first to a larger manifold and then to shore. As with onshore facilities, the size of the electrolysis systems enables cost reductions in relation to the peripheral system components such as water treatment systems, cooling systems, compressors, etc. However, the additional costs incurred for the platform must be taken into account. The expansion of the electrolysis systems occurs on the basis of individual facilities, as the wind capacity at each facility is increased. The electrolysis output is determined by the maximum power the wind farm can generate. Island mode solutions without power grid connections must be implemented on an individual facility basis.

Hydrogen hubs Finally, the concept of constructing large offshore hydrogen hubs is also being explored. This means that in areas where there are no natural offshore islands, large artificial islands will be built that can handle electrolysis output in the GW range. Further upscaling will lead to additional cost reductions here. Instead of the cost of the individual platforms, the costs incurred here will relate to constructing the island or expanding the hydrogen production plants and the associated infrastructure. As electrolysis output is concentrated in one area, the infrastructure costs for storage and transportation will be very low. In addition, other process steps such as syntheses for producing ammonia, methanol or power-to-liquid fuels are economically viable due to the high number of full-load hours that can be achieved on the hub islands.

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If the wind farms are situated far away from the coast, it is significantly cheaper to transport large quantities of hydrogen to shore via pipelines than comparable amounts of electricity. On the other hand, as in the case of the manifold mentioned above, having to make investments into infrastructure at an early stage creates an economic challenge for the expansion of such facilities—particularly as the infrastructure is only put into use gradually as wind capacities increase.

4.4.3 Economic assessment and comparison Depending on the system configurations and methods of operation that are used, the possible full-load hours range from 5000 h in the United Kingdom to around 4500 in the German Exclusive Economic Zone in the North Sea and around 4000 h in the Netherlands. Taking into account the location-specific costs of generating power (including distance and water depth and time taken for expansion), hydrogen costs amount to between 4 and 5 C/kg, including the costs of transportation to the shore. Some studies make optimistic assumptions regarding cost reductions for offshore wind and electrolysis, estimating that in the cheapest locations, hydrogen costs will be as low as around 2 C/kg by 2050. However, these do not take the costs of transportation, storage and distribution into account.

4.5

Requirements for the transmission grid in Germany

This raises the question of whether the transmission grid is fit to integrate the required quantities of renewable energy—particularly wind energy from northern Germany—or whether it will present a bottleneck. Specifically, research is being conducted in this regard to determine how much offshore wind energy can be directly integrated into the system as electricity via the power grid. In addition, possible locations are being sought for electrolyzers that could be used in the power market to reduce the load on the grid. Finally, the use of electrolyzers in redispatch to help avoid curtailing renewable energy is also being discussed. As a rule, where direct electricity use is possible and reasonable in terms of the space available and the timelines involved, it is the most efficient option and should be prioritized. However, this use can be limited due to infrastructure problems. It is also possible that the generation of this additional renewable electricity may occur when the direct electricity demand is already being met from other sources. As explained previously, the regional distribution of electricity from renewable energy

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and hydrogen demand in Germany is placing a great deal of stress on the infrastructure. The transmission grid in particular represents a bottleneck, both due to the technical issues involved in electrically connecting the power generated offshore to the power grid, and the time required to obtain public endorsement of new power lines. Taking the example of a calculation by Fraunhofer IEE as part of the DeVKopSys project, the correlations will be explored, and conclusions will be reached regarding the use of hydrogen [9]. As part of the DeVKopSys project, plans for a power grid for 2050 were outlined, taking into account different vulnerabilities involved in designing an electromobility. The basic scenario from the project will be used below to explore issues around the production of hydrogen. In this example scenario for 2050, Germany (considered as a part of Europe’s energy system) is modeled using the SOCOPE SD (scenario development) energy system model (Fig. 4.7). The scenario assumes that power consumption will increase to around 900 TWh in Germany by 2050. Wind and solar energy will become the main generators of power across Europe. In the Alpine region and Scandinavia, hydropower has great potential for flexibility. Due to their age and the political strategies of European countries, nuclear power plants account for only a very small proportion of production. The high connection capacity at Germany’s borders for electricity trading, in addition to Germany’s north-south power highway, places high additional demands on the domestic grid. As such, a conservative scenario for the European transmission grid expansion has deliberately been chosen. This enabled the Ten-Year Network Development Plan (TYNDP) and the German Grid Development Plan to set out a target grid for 2030/35. For Germany, this means the amount of power that can be transmitted in this way can be doubled in comparison to the year 2010, to reach 40 GW (Fig. 4.8). The projects in the Grid Development Plan are taken as a basis for the power grid within Germany and are further developed in line with the scenario requirements in the most economical way possible using the Fraunhofer IEE grid planning model. However, although the Grid Development Plan assumes a significantly smaller proportion of new, fundamentally flexible consumers when it comes to expanding the grid, the 2050 scenario is projecting lower conventional power consumption than the Grid Development Plan (Fig. 4.9). At the same time, half of the power consumption will go to sector coupling technologies such as heat pumps and electric vehicles, which will increase in use in the future. In the model, these are presented as flexibility options, both in the power market and for large consumers in redispatch.

4.5 Requirements for the transmission grid in Germany

Fig. 4.7 Scenario for Europe in 2050 from the DeVKopSys project Fig. 4.8 Development of European grid capacities for electricity trading

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Fig. 4.9 Comparison of consumption development: DeVKopSys vs. the Grid Development Plan

Fig. 4.10 Comparison of power output growth: DeVKopSys vs. the Grid Development Plan

The installed capacities for the key production and storage technologies are shown below (Fig. 4.10). When compared to the Grid Development Plan, it is clear that wind power and photovoltaics in particular will undergo significant expansion, resulting in increased demand on the grid. For this reason, 10 GW of electrolyzers will be used in the power market (2 GW H2 and 8 GW CH4 —here power-to-gas). However, an additional 20 GW of offshore power (here electrolysis) is directly converted to H2 without an electrical connection. When compared to the situation in 2018, the geographical distribution of power output across the German federal states shows that there has been a significant increase, and how heterogeneous the geographic distribution of the power output is (Fig. 4.11). The scenario shows high demand for the transportation of offshore wind energy in northern Germany in particular, especially Lower Saxony. The time series of the power market simulation with hourly resolution for the year 2012 (which experienced extraordinary weather) were assigned to the individual network nodes, and the grid expansion and the redispatch measures required to manage the remaining bottlenecks were identified. In this context, in addition to energy storage facilities, disconnectable large consumers (large heat pumps, elec-

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Fig. 4.11 Map of projected capacity growth for onshore wind and photovoltaics

trode boilers) and connectable or disconnectable (HVDC lines) will be built across Germany, since they will not meet public approval. We assume that the existing alternating-current (AC) lines will be extended or replaced instead (e.g., a twocircuit transmission line with 220 kV or 380 kV voltage will be replaced with a four-circuit transmission line with 380 kV voltage). Only 2 to 3 GW can be connected to the individual transmission grid nodes for technical reasons. There are two key factors here: first, the assumed level of technological advancement for HVDC stations and cables, which are generally not built to be larger than 2 GW, and second, the AC line technology connected to these stations and its meshing with the transmission grid nodes where the HVDC lines

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Fig. 4.12 Grid model created by Fraunhofer IEE

arrive. If the AC lines are unable to transport sufficient quantities of power (e.g., 2 GW of offshore wind power arrives at the HVDC, but the AC transmission grid can only transport a maximum of 1 GW), the transmission grid will be overloaded as a result. For example, this means large AC lines with 380 kV and four-circuit transmission lines with 100 percent capacity can transport 1.4 to 1.5 GW. Due to the .n  1/ supply security requirement, meshing and the resulting power flows through the substations/busbars, this figure must be set lower. This means it will become increasingly difficult to find points in the existing grid where an electrical connection for offshore wind power can be established. Fig. 4.13 shows the connection of a total of 20 GW offshore power in the North Sea and Baltic Sea, taking into account connection points as far away as southern Lower Saxony.3 It was assumed that all other wind farms would need to be directly 3

Based on transmission system operators 2019: Grid Development Plan 2030.

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Fig. 4.13 Electrically connected offshore wind farms in the North Sea (blue) and Baltic Sea (red). (Y. Harms/Fraunhofer IEE)

connected to an electrolyzer. If necessary, a few more electrical connections can be made. However, assuming that the grid is expanded as shown above, more than half of the 53 GW of offshore wind power that could potentially be produced in Germany cannot be technically connected to the transmission grid. Alternatively, extensive routes would need to be found for additional HVDC lines. To integrate large quantities of wind and photovoltaic power, the transmission grid will need to be significantly expanded by 2050. Apart from the planned HVDC routes, it will not be strictly necessary to build any other new routes as part of this expansion. However, an existing two-circuit transmission system often needs to be replaced with a four-circuit system, particularly with routes running from north to south. Fig. 4.14 shows a possible target grid for 2050, created using Fraunhofer IEE’s transmission grid model. As only 20 GW of offshore power can be connected to the grid due to technical requirements, the additional onshore electrolyzers must be set up at the onshore

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Fig. 4.14 Grid expansion measures planned for 2050 and the Grid Development Plan’s basic grid for 2035. (Y. Harms/Fraunhofer IEE)

landing point to reduce the load on the transmission grid as much as possible. The electrolyzer facilities are connected in the power grid and the dispatch is according to market price signals, which results in a basic correlation between market use and reduction of strain on the grid. Despite significant expansion to the grid, the need for dispatch remains comparable to the levels seen today. Fig. 4.16 shows redispatch during a period in which a large amount of wind power was fed into the power grid. During this period, production at renewable energy facilities must be partially curtailed (purple), which can be compensated for in part by connecting electrolyzers (green). In western and southern Germany, however, further flexible loads must be switched off (red) and, to a limited extent, additional gas-fired power plants can be switched on (blue). In addition to their use in the electricity market, electrolyzers are also used to help reduce grid congestion; this further increases the potential for efficient hydrogen production.

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Fig. 4.15 Additional electrolysis output (used in the power market) at the electrical grid connection points for offshore wind farms in the North Sea (blue) and Baltic Sea (red). (Y. Harms/Fraunhofer IEE)

4.6

Conclusion

This chapter compared the role of hydrogen and synthetic energy carriers in energy systems and discussed certain aspects of the two. For this reason, system studies that consider the existing interactions between demand, production, the facility locations and the construction and use of power, gas and heating network infrastructures were examined. The studies showed that there will be a wide range of uses for hydrogen and power-to-X in Germany’s energy system in the future. In order to achieve the defossilization of the energy system, the use of hydrogen-based energy carriers is required for selected sectors and applications (e.g., in the steel industry); however, it is recommended to use hydrogen and synthetic energy carriers directly for electricity in other areas (e.g., heat pumps and electromobility), as this results in a lower overall system cost.

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Fig. 4.16 Additional electrolysis output (used in the power market) at the electrical grid connection points for offshore wind farms in the North Sea (blue) and Baltic Sea (red). (Y. Harms/Fraunhofer IEE)

Similar to other studies, the Fraunhofer REMod model shows the demand for hydrogen and synthetic energy carriers in 2050 could amount to between 300 and 800 TWh. As high electrolysis capacities (50 to 80 GW by 2050) will be needed, even taking possible imports into account, increased upscaling of electrolysis capacities in Germany will be required around the year 2030. Great efforts must therefore be made at all levels to roll out electrolyzers in the coming years. A further key aspect is the geographical separation of the renewable electricity supply and the demand for hydrogen or synthetic fuels. While large quantities of offshore wind power are fed into the grid in northern Germany, there is a high demand for energy in areas far from the coast, such as the Ruhr region. This raises the question of whether the electrolyzers should be located close to areas of production or consumption. Thus a supply based on entirely local electrolyzers, e.g. in the Ruhr region itself, creates a significant demand for power grid expansion and, at the same time, for

References

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local energy storages, which are not economically viable. It is therefore necessary to establish hydrogen infrastructures in the medium term. Producing hydrogen directly from offshore wind energy represents a possible way of relieving the load on the power transmission grid. Different system configurations are possible, namely offshore hydrogen production and situating electrolysis systems on the coast. If the electrolysis systems were located offshore, this would create higher operating and maintenance costs, and seawater desalination processes would be required to provide fresh water. It is hugely important to consider the infrastructure at this point, as it tends to be much cheaper to transport large amounts of hydrogen via pipelines than to transport comparable amounts of electricity. Hydrogen production costs depend greatly on the cost of renewable energy. When it comes to offshore wind power, this cost is influenced by water depth and full-load hours, among other things. In the long term, it is estimated that hydrogen costs will be around 4 C/kg, including the cost of transporting the hydrogen to the shore. This raises the question of its competitiveness when compared with the prices of imported “green” or “blue” hydrogen. The analyses of requirements for the electricity transmission grid show that integrating very large quantities of renewable electricity over the long term will be a challenge. It appears this issue can be resolved by (significantly) expanding existing lines, rather than building additional high-voltage lines. In the scenario studied, only 20 GW of offshore power output is connected to the grid, while the potential additional power generated offshore is used in electrolyzers; this then reduces the load on the electricity transmission grid. The alternative of laying additional power lines would certainly be feasible from a technical standpoint; however, it would likely face serious problems in terms of public approval.

References 1. IEA (2020): World Energy Balances database, 2020 edition. https://www.iea.org/dataand-statistics, last viewed on November 15, 2021 2. Wietschel M., Bekk A., Breitschopf B. et al. (2020): Opportunities and challenges when importing green hydrogen and synthesis products. Policy Brief 03/2020. Karlsruhe 3. Fraunhofer Cluster of Excellence Integrated Energy Systems—CINES (2020): 13 Thesen: Wie die deutsche Energiewende gelingen kann (13 theses: how the German energy transition can succeed). https://www.ise.fraunhofer.de/content/dam/ise/de/documents/ publications/studies/Fraunhofer-CINES-13-Thesen-Wie-die-Energiewende-gelingenkann.pdf, last viewed on November 15, 2021 4. EUR-Lex (2020): Document 52020DC0301. COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL COMMITTEE AND THE COMMITTEE OF THE RE-

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GIONS A hydrogen strategy for a climate-neutral Europe. https://eur-lex.europa.eu/legalcontent/EN/TXT/?uri=CELEX:52020DC0301, last viewed on March 29, 2021 BMWK (2020): The National Hydrogen Strategy. https://www.bmwk.de/Redaktion/EN/ Publikationen/Energie/the-national-hydrogen-strategy.html, last viewed on March 29, 2021 Fraunhofer ISE (2020): Paths to a climate-neutral energy system 2050, https://www.ise. fraunhofer.de/en/publications/studies/paths-to-a-climate-neutral-energy-system.html, last viewed on July 27, 2022. Pluger B., Tersteegen B., Franke B. et al. (2021): Modul 10.b: Langfristszenarien und Strategien für den Ausbau Erneuerbarer Energien in Deutschland 95%-Szenarien (Module 10.b: Long-term scenarios and strategies for the expansion of renewable energies in Germany—95% scenarios) ORE Catapult (2020): Offshore Wind and Hydrogen: Solving the Integration Challenge. https://ore.catapult.org.uk/wp-content/uploads/2020/09/Solving-the-IntegrationChallenge-ORE-Catapultr.pdf, last viewed on November 15, 2021 https://www.iee.fraunhofer.de/de/projekte/suche/laufende/DeVKopSys.html, last viewed on November 15, 2021

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Matthias Jahn  Gregor Herz Fraunhofer Institute for Ceramic Technologies and Systems IKTS Görge Deerberg  Christoph Glasner  Axel Kraft  Andreas Menne  Torsten Müller  Ulrich Seifert  Esther Stahl Fraunhofer Institute for Environmental, Safety and Energy Technology UMSICHT Klemens Ilse  Uwe Spohn Fraunhofer Institute for Microstructure of Materials and Systems IMWS Sylvia Schattauer  Marcus Tümmler Fraunhofer Institute for Wind Energy Systems IWES Abstract

Hydrogen produced by electrolysis of water with electricity from renewable sources of energy, e.g., wind, water and solar power, can be used both as such and as a universal energy source. Therefore, it will significantly contribute to the reduction of industrial greenhouse gases, especially carbon dioxide. In the chemical industry, large amounts of hydrogen are used to hydrogenate of oxygen, sulfur and other heteroatoms in mineral oil fractions for their removal. Hydrogen is needed for hydrocracking and to synthesize ammonia and methanol. The methanol and the Fischer–Tropsch synthesis open up the way to produce ethylene, propylene and many other basic substances independent of fossil carbon and hydrocarbons. The use of carbon oxides from other processes, e.g., the

© Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_5

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production of steel and cement, can reduce its emission in additional industrial sectors. Following purification and conditioning, e.g., by the admixing of green hydrogen, smelting gases could be used to synthesize methanol and hydrocarbons. The steel industry is also making efforts to use hydrogen for the reduction of oxide ores and for heating. However, in the near future, the use of hydrogen combustion in industry will likely be limited to high-temperature applications in, for example, the glass, ceramic and metal industries.

5.1

Hydrogen as a material: steel industry

In Germany, around 21 percent of CO2 emissions are caused by the industry [1], with around 30 percent, i.e., 58.4 MtCO2 from the steel industry [2]. It is necessary to distinguish between energy- and process-related emissions here: While the former can be avoided by making the comparatively straightforward switch to renewably sourced electricity or sustainably generated fuels, it is far more difficult to reduce process-related emissions. In steel production, carbon-based substances such as coke are integrated into the process chain as a reducing agent and product component. This means that the integrated blast furnace route for producing crude steel releases considerable quantities of process-related CO2 emissions [3, 4]. This production route is also known as the BF-BOF route, as in this instance, the blast furnace (BF) is paired with a basic oxygen furnace (BOF). Steel is of high strategic importance in industry and economy. As such, when considering the possibility of using hydrogen, rather than carbon, as a reducing agent and energy source in order to reach the emission reduction targets outlined in the Paris Agreement (95 percent by 2050), it is necessary to take both environmental and economic factors into account. Researchers are already testing and studying solutions that just achieved a sufficiently high technology readiness level (TRL). These include the direct use of hydrogen as reducing agent for crude steel production, thereby avoiding emissions, as well as downstream processes, during which the CO2 produced is harnessed and react with hydrogen. Hydrogen plays a central role in all these strategies. However, since the electrolysis of water is the only path for generating large quantities of carbon-neutral hydrogen, the increasing demand of electrical energy is a further important factor to be taken into account along with the reduction of CO2 emissions.

5.1 Hydrogen as a material: steel industry

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The first strategy is based on substituting hydrogen for carbon as reducing agent. In addition to acting as a chemical reducing agent for the iron ore, hydrogen also provides the necessary process heat when burned. However, this results in substantial changes to the way the process is managed. As the various processes can result in the prevention of carbon dioxide emissions to varying degrees, this strategy can also be classified under carbon direct avoidance (CDA). There are two options here.

Option 1: using hydrogen directly in blast furnaces (H2 BF-BOF) Scientists have already studied the direct use of hydrogen in blast furnaces using models [5, 6]. The process corresponds to the simplified flowchart shown in Fig. 5.1 and involves feeding hydrogen into the lower area of the blast furnace (BF). The molten iron is then transferred from the blast furnace to a basic oxygen furnace (BOF) for crude steel production. This process route is referred to as the H2 BF-BOF route below. Calculations have demonstrated that if hydrogen is used as a reducing agent instead of pulverized coal, CO2 emissions could be reduced by 21.4 percent in the region in scope for the carbon footprint assessment, provided the hydrogen is consumed to the maximum extent in the reaction [6]. Providing pure oxygen for the BOF via electrolysis can also be beneficial. A large-scale study by thyssenkrupp AG has confirmed that this method is feasible in principle [7]. At present, however, the high costs of supplying the necessary amounts of green hydrogen are critical. For this study, hydrogen was sourced via solid oxide electrolysis (SOEL). In the carbon footprint calculations, the scope was expanded to include peripheral processes in the coking plant, sintering plant, regenerative heat exchanger and power

Scrap metal Coke, coal Furnace gas (peripheral utilzation)

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Fig. 5.1 Flowchart of the process model for feeding hydrogen directly into a blast furnace [8]

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plant. This made it possible to assess what impact the introduction of hydrogen into the system had on overall material recovery during crude steel production. The process was able to reproduce the trend already demonstrated by Yilmaz et al. [5], whereby the hydrogen was consumed to a lesser degree than carbon monoxide, which is currently the most commonly used reducing agent, with large portions of hydrogen remaining in the blast furnace gas. Since this only involves changing the energy demands of the peripheral process steps to a limited extent, a significant proportion of the hydrogen used in these processes is converted back into electricity at the power plant, leading to a high specific energy demand for emissions reduction. In addition, the possible impact of the altered composition and quantity of the fuel gas on the power plant must be taken into account. Further study may be required in this area.

Option 2: direct reduction of iron ore with hydrogen (H2 DR-EAF) This process, as employed by Swedish Steel AB (the HYBRIT process) and Salzgitter AG (SALCOS), involves reducing pellets of iron ore with hydrogen in an autothermal direct reduction plant, where the heat required for the process can be provided by the partial combustion of hydrogen, using oxygen from the upstream electrolysis step. The term H2 DR-EAF comes from the use of hydrogen in the direct reduction (DR) process. Following a process of direct reduction, the iron is fed into an electric arc furnace (EAF). As carbon is an essential component of crude steel, it cannot be entirely eliminated from the process. However, in this process, it is added solely for the purposes of carburization and residual reduction in the electric arc furnace, so that CO2 is only generated at this stage. Researchers have demonstrated the use of pure hydrogen to reduce iron ore pellets on an experimental basis [9, 10], thus proving that it is possible to implement this kind of process at a technical level. However, at the time of publication, it is not feasible to supply sufficient quantities of hydrogen from neither a technical nor a financial perspective. As an interim solution, natural gas can be used instead of hydrogen for the reduction process. This method also promises a significant decrease in CO2 emissions, at up to 67 percent when compared to conventional crude steel production in integrated mills [11]. Depending on the availability of renewable electricity, it is possible to run a plant partially or entirely on natural gas when using the direct reduction process. In this process, natural gas is internally reformed to produce the primary reducing agents, CO and H2 . To achieve the emission reduction targets, the electrical energy for the arc furnace must be supplied via renewable energy sources in all cases. In contrast to the blast furnace route, this process allows for avoidance of CO2 emissions even when using natural gas, meaning that it can also be classified under the term carbon direct avoidance

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Fig. 5.2 Process flowchart for hydrogen-based direct reduction (H2 -DR-EAF) [8]

(CDA). Similar to hydrogen-based direct reduction, this process is known as NG DR-EAF, where “NG” stands for natural gas.

Process comparison These options differ dramatically in terms of their potential to reduce emissions when compared to the integrated blast furnace route. Fig. 5.3 shows the CO2 avoidance potential ˚CO2 D

CO2 emissionsBF=BOF  CO2 emissionsCDA CO2 emissionsBF=BOF

for the two alternative processes described here as compared with the integrated blast furnace route. The direct use of hydrogen in blast furnaces (H2 -BF-BOF) offers the least potential for emissions reduction, at 24 percent, as only the pulverized coal used in the blast furnace can be replaced in that route. Due to the mechanical function of coke in the blast furnace, it cannot be replaced. The natural gas direct reduction route (NG DR-EAF) offers both better reduction potential, at 67 percent, and a higher technology readiness level of 9. Hydrogen-based direct reduction has the highest CO2 avoidance potential at 97 percent; however, this is dependent on the electrolysis technology used for the process. Using hydrogen from electrolysis in steel production and electric arc furnaces requires large quantities of electrical energy. Due to the high cost of electricity in comparison to the fossil-based energy carriers currently used in steel production, electrical energy demands are the most essential factor influencing economically viable, low-emission steel production. Fig. 5.4 shows the specific energy demand

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for CO2 avoidance "CO2 D

Energy demandCDA CO2 emissionsBF=BOF  CO2 emissionsCDA

The direct use of hydrogen in blast furnaces also performs comparatively poor here. The specific electrical energy demand for this process depends on the quantity of CO2 avoided, giving a figure of "CO2 D 18:4 GJ=tCO2 . The low chemical conversion rate for hydrogen and the ensuing reconversion of the gas into electricity mean that it takes enormous quantities of hydrogen to replace pulverized coal. The natural-gas-based direct reduction process has a lower specific energy demand. However, both options are still dependent on chemical energy carriers from fossil sources. Only electric arc furnaces (EAF) offer the possibility of using renewable energy, based on its electrical energy demand in the case of the NG DR/EAF route. Hydrogen-based direct reduction offers the lowest specific energy demand, with a figure of "CO2 D 8:1 GJ=tCO2 . As the direct reduction plant is designed to run on a closed-loop basis, the greater part of the hydrogen is consumed in the reactions. With the exception of the carbon, the energy used for carburization in EAFs is provided in the form of electricity. As a result, there is a high potential for integrating renewable energy into the process. If the waste heat is also used for high-temperature electrolysis in a waste heat recovery (WHR) process, the rate of energy efficiency increases while the electricity demand decreases (Fig. 5.4). The comparative economic analysis is based on the specific emission reduction cost value CO2 D

NPCconsidered route  NPCBF=BOF route CO2 emissionsBF=BOF  CO2 emissionsCDA

whereby the difference between the net production costs (NPC) of the various routes explored in the study and of the blast furnace route, which serves as a reference for comparison, is divided by the amount of CO2 saved. Fig. 5.5 shows the specific emission reduction costs CO2 of the production routes in the study. To enable an unbiased technical comparison, government incentives were ruled out for all routes. The net production costs associated with the natural-gas-based direct reduction route were close to the costs of the coalbased BF-BOF route (which by definition, has a CO2 value of 0), which is quite reasonable for a competitive technology that has already been implemented on an industrial scale. Because it utilizes the reducing agent more efficiently, hydrogen-based direct reduction has comparatively low emission reduction costs. The choice of elec-

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Fig. 5.5 Specific costs for emission reduction in the processes covered by the study, differentiated by hydrogen source (PEMEL: low-temperature polymer electrolyte membrane electrolysis, SOEL: high-temperature solid oxide electrolysis)

trolysis technology does not have a significant impact on crude steel production. However, heat can be recovered in solid oxide electrolysis (SOEL), which would make it possible to further reduce energy demands, and consequently also production costs. The emission reduction costs associated with feeding hydrogen into the blast furnace are greater than those associated with direct reduction by a factor of ten. Both for this reason, and because of the above-mentioned limited emission reduction potential and high specific energy demand, this process is not viewed as viable in the long term or as an interim solution. In the context of crude steel production, hydrogen-based direct reduction offers the highest emission reduction potential and the lowest specific energy demand, together with comparatively low avoidance costs; as such, this process should be given preference. Using natural gas is cheaper, but it reduces CO2 emissions at steel plants to a lesser extent. There are also emissions at earlier stages in the process chain that were not taken into account for the calculations. However, the specific emission avoidance costs value CO2 are positive, which means that the technology cannot compete with the conventional blast furnace route at an economic level. Consequently, examples of legislative tools aimed at helping sustainable technolo-

5.1 Hydrogen as a material: steel industry

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Fig. 5.6 Influence of legislative measures on the financial viability of the hydrogen-based direct reduction route for the 2050 scenario

gies to become established were compiled and applied to the specific scenario of hydrogen-based direct reduction of iron ore. The results are shown in Fig. 5.6. It is essential to take the costs of CO2 allowances into account, as they represent a well-established climate-policy instrument. The allowance costs for the 2050 scenario were calculated based on data from the relevant literature and the available forecasts. It was assumed that the cost of CO2 allowances would rise from approximately 25 C2020 /tCO2 to around 82 C2020 /tCO2 [12, 13]. Assuming that the CO2 emissions per ton of crude steel (cs) will decrease by approx. 1.6 tCO2 /tCS as calculated, the SOEL DR-EAF route would offer a cost advantage of approx. 132 C2020 /tCS when compared to the BF-BOF route. The allowance costs were taken into account for the calculations based on the assumption that certificates will have to be actively purchased. The possibility of freely allocated allowances [14], which are possible in the SOEL-DR-EAF route, was not considered. The introduction of a carbon tax paid by consumers is the subject of much debate at present. In an initial step, legislators introduced a carbon tax on heating and mobility in Germany in 2021, with the aim of reducing dependency on fossil-

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based resources [15]. As a regulation of this kind would also apply to the metals sector to a certain extent, it was also used as an example of a legislative instrument in this study. A price of 25 C2020/tCO2 was established for 2021; this price is set to rise to 55 C2020 /tCO2 by 2025. As the price is determined by a legislative process rather than through market trading, it is not possible to make a plausible forecast here. As such, the value for 2025 was used as an example for the 2050 scenario in this study. In 2050, economically viable production will not be possible without government support. The net production costs of crude steel if produced via hydrogenbased direct reduction exceed the costs of the conventional blast furnace route by a factor of 1.5. If the abovementioned instruments are put into practice and the lowest possible industrial electricity tariff is used, it is possible to not only close the gap of 175 C2020 /tCS , but to actually undercut it by roughly 89 C2020 /tCS , based on the assumption that sustainable raw materials will generate higher revenues. The most effective instruments for this were identified as CO2 allowances and a carbon tax. Based on this study, the conclusion can be drawn that when using hydrogen for crude steel production, direct reduction is more technically and economically efficient than the blast furnace process.

5.1.2

Smelting gases as a chemical resource (CCU)

In the second strategy, carbon from steel industry process gases is used as a chemical resource in combination with green hydrogen. This strategy forms part of the measures outlined in the German federal government’s “Steel Action Concept” [16], which are aimed at implementing the climate resolutions and improving competitive conditions in the steel industry. Carbon capture and utilization (CCU) solutions open the door to the possibility of using the carbon from smelting process gases as a resource for the chemical industry, thus reducing the overall use of fossil-based carbon. There are many processes in the chemical industry that require carbon, such as the synthesis of methanol and urea, the Fischer-Tropsch synthesis and the production of polycarbonates and polyurethane (see also Sect. 5.2). This carbon can be obtained from the carbon monoxide and carbon dioxide in smelting gases. In this context, the term “smelting gases” covers all the process gases produced in smelting mills. Generally, for an integrated mill, these will consist of coke oven gas (COG) from the coking plant, blast furnace gas (BFG) from the blast furnace and basic oxygen furnace gas (BOFG). These smelting gases contain very differ-

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Table 5.1 Distribution of the primary components of the different smelting gases in vol% [17]

Nitrogen (N2 ) Hydrogen (H2 ) Carbon monoxide (CO) Carbon dioxide (CO2 ) Miscellaneous

Coke oven gas [%] 5 61 6 2 26

Blast furnace gas [%] 49 4 25 23 > 0.1

Basic oxygen furnace gas [%] 14 4 65 17 > 0.1

ent ratios of the basic components: hydrogen (H2 ), carbon monoxide (CO), carbon dioxide (CO2 ) and nitrogen (N2 ) (Table 5.1). Conventional steel production, which serves as a reference for comparison here, starts with the production of pig iron from iron ore in a blast furnace. The pig iron is then converted to crude steel (Fig. 5.7). Coke, coal, petroleum and natural gas are used as energy carriers and reducing agents in the reduction of iron ore. In an integrated mill, the coke is produced in a coking plant from hard coal. Integrated mills use the resulting process gases as an energy source to provide heat, steam and electricity, which makes them self-sufficient in terms of energy. They also sometimes feed power into public grids. In addition to the steel, large quantities of by-products such as slag also result from the process. Slag is an important feedstock in the cement industry, where it is used in the slag sand and helps to reduce carbon dioxide emissions. In addition to steel production, the chemical industry also manufactures products such as methanol, fertilizer and fuels using fossil-based raw materials.

Fig. 5.7 Steel and chemical production as separate processes

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Fig. 5.8 A cross-sector network consisting of steel and chemistry production

An important aspect of CCU solutions is the ability to retain existing processes in smelting mills. The smelting gases are processed after the existing processes in the coking plant, blast furnace and basic oxygen furnace have been completed (Fig. 5.8). The process gases are subsequently used to manufacture chemical products within the existing processes, which must be adapted for that purpose. This means that CCU strategies can be implemented on the basis of existing technology in the near term, thus contributing to reducing CO2 emissions from steel production in the near future. In this context, it is firstly necessary to ensure that CCU solutions are firmly established in the industry. At the same time, continued efforts must be made to complete steel production’s climate-neutral transformation by 2045. If the internal smelting mill processes were to be continued without any other changes, 60 to 80 percent of the smelting gases could be used for chemical production, meaning that they would no longer be emitted at the mill (Fig. 5.8). Around 20 percent of smelting gases would still be available as an energy source. Each mill must determine individually whether this can be replaced in some way, e.g., by electricity. Depending on the carbon content of the processed smelting gases, the chemical industry can use them to avoid fossil-based raw materials and the associated CO2 emissions. This would result in a carbon footprint reduction of around 50 percent across the entire cross-sector network of the steel and chemical industries. Due to their higher H2, CO2 and CO content, it is more efficient to collect and process smelting gases from steel production than process gases (such as CO2 and N2 ) from other industry sectors, e.g., cement production or waste incineration, to serve as a carbon source for chemical processes. Synthesizing many chemical products requires both CO and CO2 from the smelting gases in addition to hydrogen,

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in order to provide a synthesis gas for chemical production. Some of this hydrogen can be obtained from coke oven and blast furnace gas, but large quantities of green hydrogen will be needed to compensate the deficit. This can be supplied via water electrolysis powered by renewable energy, for example. Most of the technologies required for gas purification, the supply of hydrogen and chemical synthesis have undergone commercial testing on an industrial scale. Various projects such as the joint project Carbon2Chem® have shown that there are no technical obstacles standing in the way of using smelting gas rather than fossil-based raw materials in existing technologies. This concept appears to be economically viable in the short term and would prevent significant amounts of CO2 emissions. Steel production can continue to operate using existing, established technologies. However, establishing the proposed connection between the steel and chemical industries will require additional investments in the areas of gas processing, hydrogen supply and the necessary infrastructure.

Using hydrogen Unlike the carbon direct avoidance (CDA) process (Sect. 5.1.1), the quantities of hydrogen necessary to avoid generating CO2 are not being used in steel production. Green hydrogen is used as a key substance to link steel production with chemical processes, whereby it is combined with smelting gases to form a synthesis gas needed in the chemical industry. The purification and processing of the smelting gases from steel production are essential factors in ensuring that the synthesis gas fulfills the necessary specifications for an input gas. While CDA processes are focused on reaching climate neutrality in the steel sector, CCU processes also have a significant impact on climate goals in the chemical industry since they provide a source of carbon and thus eliminate fossil-based raw materials and contribute to process defossilization. Comparing the two reveals that the annual reduction in CO2 emissions in complete CCU systems (steel and chemical production) falls just below the potential 50 percent reduction associated with CDA processes, provided that a suitable chemical production process is included in the carbon footprint calculations. Particularly during the phase of transition, before alternative solutions reach technological maturity, it is preferable that the limited quantities of green hydrogen that are available be used to achieve emission reduction in the steel and chemical sectors. While some carbon dioxide is still produced in CDA processes, e.g., in the production of special types of steel, using CDA and CCU strategies in combination makes it possible to harness that CO2 and create value as described above. This also enables more hydrogen to be extracted from smelting gases, reducing the need for extra hydrogen from water electrolysis.

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Research and development Even when CCU strategies build on existing technologies, there is still a need for research and development work. Linking steel and chemical production systems into one network will require a new kind of system optimization. The properties of the smelting gases may make it necessary to adapt existing synthesis routes when these gases are to be used as a resource for chemical production. Studies on long-term operation or industrial-scale implementation of CCU strategies will be needed, especially as regards processing of the smelting gases, the dynamics of the production processes, translation of the process models to other fields of application and further optimization measures, particularly in relation to economic factors.  Gas processing: The process gases from the steel industry vary in terms of the trace components they contain. These components can still negatively impact chemical processes due to the enormous volumes of gas involved. As such, an intermediate step is needed to process the gas properly, but this step must be sufficiently robust and stable to cope with fluctuations. As gas processing is the core element of CCU strategies, it has a significant impact on the cost of the process.  Dynamics: The hydrogen used in the process must have the lowest possible carbon footprint, so that the process changes described here produce the desired results. Consequently, electricity from renewable energy sources must be used when supplying green hydrogen via water electrolysis. However, this means the volatility of renewable energies is transferred to the process chain. Hydrogen imports and a flexible infrastructure will be needed to ensure a continuous supply for synthesis gas production. The quantity and composition of the smelting gases are also subject to production-related fluctuations that must be taken into account in a system of this kind. In methanol synthesis, for example, it is possible to adopt a dynamic mode of operation as far as certain fluctuations in the input gas are concerned. By contrast, in ammonia or polymer synthesis, extensive gas processing and a continuous gas supply are an absolute necessity.  Translation and technology exportation: The pressure of climate change is creating a worldwide demand for technologies, which can be met using the innovative findings from ongoing research and development projects. For Germany, this opens up the possibility of exporting these technologies. In addition to supplying CCU solutions for the steel industry, researchers are also working to translate them to other industries, such as the cement and chalk industries, which also produce large quantities of process-related carbon dioxide emissions.

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 Economic viability and process optimization: In contrast to CDA processes, the additional costs incurred in CCU processes are spread over the entire system and do not only place a burden on the steel sector. Nevertheless, the production costs are higher than those of the conventional processes which use fossil-based raw materials. In addition to the necessary technological changes, the relevant legislation has a major impact on the costs involved in CCU processes. Since process gases are used as a carbon source for the chemical industry, smelting mills will need to acquire climate-neutral energy from external sources in the future. Suitable solutions must be developed to meet this need, taking into account the incorporation of renewable energy, biomass as an energy carrier and the use of waste heat from chemical processes.

Conclusion In coming years, steel will continue to play a key role as a basic material, since it is needed to expand the generation of renewable energy, among other things. This process of expansion is in turn necessary for supplying green hydrogen. In order to transform steel into a carbon-neutral or CO2 -free product by 2045, various technology options must undergo commercial testing and then be put into practical applications as quickly as possible. CCU processes enable cross-sector networks to be systemically formed based on existing processes. As such, they can be put into practice in the near term. When used in combination with other industrial carbon sources, CCU processes can be implemented in parallel with the transformation of steel into a climate-neutral industry, thus contributing to a cross-sector reduction in CO2 emissions and the defossilization of the chemical industry [18]. Corresponding ecological evaluations (environmental analyses) have shown that it is possible to reach the desired (established) targets [19] by relying on green hydrogen. Consequently, hydrogen supply costs have a fundamental impact on the economic viability of cross-sectorial networks. As with the CDA processes, supplying the necessary hydrogen will require a suitable infrastructure and a regulatory framework that do not currently exist. While the CCU strategy does not actually decarbonize the steel industry’s production processes, the by-products (such as slag sand) and process gases can make an important contribution to achieving climate neutrality in other sectors. Consequently, while CCU processes cannot provide the only solution for the sectors such as the steel industry, they do represent an important building block in achieving industrial transformation by 2045.

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Joint project Carbon2Chem®

The project participants are working on solutions for reducing CO2 emissions in the basic materials industry and defossilizing processes in the chemical industry by forming cross-sectorial networks. In the future, the chemical industry’s carbon demands will be covered by linking production processes across sectors. Plans are in place to bring a CCU strategy into commercial application as part of Carbon2Chem® within a ten-year period. Within the first four years, the participants successfully demonstrated that products such as methanol, urea, higher alcohols and polymers can be produced from the smelting gases. The researchers were able to demonstrate the technical feasibility, economic viability and sustainability of all the products via experiments and simulations. In the project’s dedicated technical center, the team have also successfully produced methanol and ammonia from the real gases of a neighboring smelting mill. Consortium:

Clariant, Covestro, ESK, Evonik, Fraunhofer ISE, Fraunhofer UMSICHT, GMVA, Lhoist, Linde, Max Planck Institute for Chemical Energy Conversion, Max-Planck-Institut für Kohlenforschung, Nobian, Remondis, Ruhr-Universität Bochum, RWTH Aachen University, Siemens AG, Siemens Energy, thyssenkrupp, Thyssen Vermögensverwaltung Duration: 2016–2024 Funding volume: approx. 135 million euros Grant number: 2016–2020: 03EK3037-03EK3043; 2020–2024: 03EW0003-03EW0008 Project funded by: German Federal Ministry of Education and Research (BMBF) Contact: Project office Carbon2Chem® Email: [email protected]

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Hydrogen in the chemical industry Green hydrogen overview: demand and potential

In light of the German goal of becoming climate neutral by 2045, the chemical sector is also striving to achieve net zero greenhouse gas emissions. This sector is of vital importance here, as it functions as the starting point for numerous important value chains that can only reach their GHG targets if their (source materials) feedstocks are climate neutral. Most fields of the German chemical and refinery industry and their current processes generally require a continuous hydrogen supply amounting to more than 1.1 million t/a [17, 20]. As such, green hydrogen is indispensable in these processes. At present, however, a major part of this hydrogen is obtained by reforming methane from fossil sources, which results in emissions of 9.0 to 12.6 kg CO2 equivalent/kg H2 ; an average of 10.6 kg CO2 /kg H2 can be taken as a basis here [21, 22]. This hydrogen is referred to as gray. Ammonia and methanol production are good examples of the processes behind basic, widely needed chemicals, and will be discussed in more detail in Sect. 5.2.3. These processes alone consume more than half of the annual hydrogen demand of the German chemical sector [17]. The commercially established manufacturing process for ammonia is the Haber-Bosch process, which uses hydrogen and nitrogen. Ammonia is an important intermediate product for the production of fertilizers and polyamides, as well as almost every other nitrogen-based compound, e.g., nitric acid, cyanide and amines. Ammonia is also considered to be a promising energy carrier for the future, as it can transport and store chemically bound hydrogen and has the potential to serve as a fuel for power plant turbines and engines. Methanol is one of the most frequently produced organic chemicals. It can be used both as an energy carrier and as a basic chemical feedstock (material) for the production of fuels and plastics. There are a number of different ways to synthesize methanol. However, in refineries, which will be examined in more detail in Sect. 5.2.2, hydrogen is used to desulfurize fuels and to refine heavy residual oils via hydrocracking. The production of synthetic fuels, also known as synfuels or eFuels, is another important area of development at present. Here, Fischer-Tropsch synthesis is used extensively to manufacture gasoline, diesel and kerosene. Among other things, H2 and CO2 serve as source materials in these processes. Experts have estimated that the transition to a climate-neutral chemical industry by 2050 will result in a seven-fold increase in hydrogen demand compared with contemporary figures [23]. A significant portion of this demand will stem from ef-

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forts that are also being made to replace petroleum as a basis for a variety of (raw materials) feedstocks, such as naphtha, which can be synthesized using hydrogen. Even if the chemical and refinery industry were to merely replace hydrogen production from natural gas and petroleum derivatives by green hydrogen this could potentially reduce emissions by 10 to 15 Mt CO2 /a in Germany [24]. Gray hydrogen cannot always be directly replaced by its green counterpart without further measures due to the organization of chemical processes in material compounds. For example, the production of urea using ammonia still needs CO2 formed during the steam reforming of CH4 . This CO2 must therefore be obtained from other, independent sources. As such, new cross-process and -sector strategies must be developed for hydrogen and carbon material flows. The goal here is to establish closed material loops that are nevertheless as flexible and modular as possible, so that they can be adapted to fluctuations in supply and demand. This helps to reduce the use of new resources and thermal waste recovery during chemical recycling [25]. As is becoming clear, eliminating the use of hydrocarbons in the industry sector as a whole will not be possible, even in the future. Instead, the focus must be on ensuring that these hydrocarbons are no longer primarily obtained from fossil sources, but rather become part of a closed-loop cycle. In other words, defossilization is the goal. In addition, the use of hydrogen from renewable sources in the chemical industry must always go hand in hand with obtaining carbon from climate-neutral sources. As it stands, CO2 is set to become the source of carbon for almost all chemical processes. This raises the question from which sources both gases will be obtained [26]. Depending on the circumstances, the use of water electrolysis makes it possible to break even in terms of finances if the effective price of electricity would be 3 to 4 ct/kWh. However, this requires restructuring the cost system [23, 26]. To achieve climate-neutral production by 2050, the chemical sector alone would require 650 TWh/a of electricity [27] at the above-mentioned price, which amounts to approximately the entire volume of electricity used by Germany as a whole at present. Consequently, it will be necessary to import hydrogen and use multiple manufacturing processes to cover the resulting demand. Although water electrolysis will be a key technology, the focus should not be a particular production method, but rather the resulting CO2 equivalent footprint. Remaining open to the possibility of using different technologies helps to avoid artificially narrowing the field of possible solutions and increases the possibility of participating in a future global hydrogen market. Other, mostly climate-neutral processes for obtaining hydrogen include splitting renewable biomethane and methane

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from catalytic cracking by means of steam reforming or pyrolysis, and gasifying biogenic, recycled carbon-based raw materials in order to produce synthesis gas. These processes emit hardly any additional (fossil) CO2 into the atmosphere [28]. However, increasing the use of chemical recycling also increases hydrogen demand, which serves as a basis for adjusting the ratio of H2 to CO in the gas produced by means of gasification so as to improve its suitability for the subsequent synthesis processes. Hydrogen is also used to improve the quality of the liquid products of plastic pyrolysis so that they are fit for use in the petrochemical industry [26]. If these processes are combined not just with hydrogen production, but also with CCU methods, i.e., capturing the CO2 in the waste gas and then using it in various chemical processes (e.g., for manufacturing synthetic fuels), materials efficiency can be increased even further and the full range of used hydrocarbons becomes accessible; see also Sects. 5.1.2 to 5.3. In addition to the costs, receptiveness to different technological options and the legislative treatment of hydrogen and processes for obtaining the gas, the chemical sector has also to meet the security of supply as regards hydrogen, taking into account the ever-increasing fluctuations in energy supply. Using hydrogen as a material (feedstock) requires a continuous supply, which in turn necessitates the development of a dynamic, flexible hydrogen infrastructure that can be controlled via a digital system. An infrastructure of this kind would improve the ramp-up process and production costs, but must be regulated in such a way that ensures non-discriminatory access. The fundamental difference between existing, private, commercial networks limited to a specific region and public networks is that the private networks are often subject to special pressure and purity requirements, as well as delivery arrangements from contractual agreements [20]. In this context, it is possible to adopt interim solutions, so that those parts of the network and users that do not have a direct physical connection to a source of climate-neutral hydrogen can still take (climate-neutral hydrogen) into account in their carbon footprint calculations based on proof of origin documentation. Processes where hydrogen is used as a material (feedstock) are very sensitive to fluctuations in the gas composition. Facilities with large-scale hydrogen demands generally do not have access to sufficient locally generated electrical current from renewable power and are dependent on long-distance connections to renewable hydrogen sources, which is why the network design is set to include a dedicated hydrogen pipeline. Methanation could possibly be used to ensure purity within the gas network structures.

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Green hydrogen in refineries

Refineries are currently the largest hydrogen consumers in both the EU and the USA, followed by ammonia synthesis plants [29, 30]. However, up to 50 percent of the hydrogen they need is produced at the refineries themselves during gasoline production, meaning that their gross consumption is far higher than their net consumption. In fact, net consumption in ammonia synthesis outstrips refineries [21, 31]. Recent calculations have shown that, on average, net consumption of externally sourced hydrogen makes up around 50 percent of the carbon footprint of German diesel-focused refineries. These refineries have a far higher net consumption of hydrogen than gasoline-focused refineries. This figure corresponds to 25 percent of the total emissions involved in fuel manufacture and use. Hence, meaning that using green hydrogen from power-to-hydrogen (PtH) plants would reduce refineries’ carbon footprints. For example, in fuel production, this could result in potential emission savings of around 104 g CO2 eq/MJ, where an average of 42 MJ/kg can be applied for both diesel and gasoline. This could enable the potential reduction in greenhouse gas to even exceed the EU average of 94.1 g CO2 eq/MJ [32], which is the maximum value that can be attributed to a fuel. Some of the most important petroleum refinery processes that consume hydrogen are the removal of sulfur, nitrogen, aromatic compounds and alkenes for quality purposes by means of hydrotreating, as well as demand-oriented use of hydrocracking for yield optimization, which increases the yield for diesel and kerosene. Currently, hydrogen from natural gas reforming and hydrogen produced during internal refinery processes are used for these purposes. The net consumption of hydrogen depends on the type of crude oil used and the complexity of the refinery. Fig. 5.9 shows the abovementioned process steps, illustrating how they are connected in a modern refinery that can process all common types of crude oil. Modern EU refineries have processes for recovering the hydrogen that is not used up during the abovementioned steps and feeding it into a closed loop so that it is fully used up. These processes play a very important role in energy and cost saving [33]. As a consequence, increased implementation of closed-loop systems offers major potential for emissions reduction in global production.

Naphtha and LPG as by-products Liquefied petroleum gas (LPG) and naphtha, also known as straight-run gasoline, are extracted from petroleum during distillation. In refineries, the refinement process also produces LPG and naphtha via fluid catalytic cracking and hydrocracking. These two by-products are the most important raw materials for manufacturing

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Fig. 5.9 Diagram of a modern refinery as described in [37]

many chemicals, solvents and plastics, including polyethylene (PE), polypropylene (PP), polystyrene (PS) and polyethylene terephthalate (PET). Naphtha and LPG are converted into intermediate products, especially valuable alkenes such as ethylene, propylene, butadiene and BTX aromatics (benzene, toluene and xylene) in a separate, large-scale steam cracking facility, independent of the refinery [34, 35]. In the future, a variety of pyrolyzed plastic waste materials could be used in steam crackers as an alternative to naphtha from refineries. Aromatic compounds, including some BTX aromatics from the reformer and the cracking processes in the refinery, are also mixed into the gasoline in order to increase its octane number. Refineries and steam cracking facilities are often located in close proximity to each other, so that the highly flammable materials do not have to be transported or stored [36].

Outlook In the medium term, hydrogen is set to play a central role in efforts to establish a secure, sustainable, economically viable energy supply based on renewable energy

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sources. Integrating PtH systems into refineries in a suitable fashion may reduce the costs of the energy transition, while simultaneously ensuring the availability of fuels and hydrogen. It is very challenging to develop a process to transition from fossil-based to low-emission supply models in a financially and technically efficient way. Refineries will play a very important role in this regard, at both a regional and national level. As such, incentives are provided for them as part of the transformation process outlined in the EU’s Renewable Energy Directive (RED-II) [38], which is in force until 2030. These incentives are aimed at helping drive the substitution of green hydrogen for the fossil equivalent, as this substitution can be counted toward Germany’s achievement of the emission reduction goals laid down in its quotas and targets for greenhouse gas reduction. With the stimulus of REDII, Germany’s refinery sector could develop an electrolysis capacity of up to 2 GW for hydrogen by 2030 [38]. This would correspond to green hydrogen production of up to 0.3 Mt per year. By comparison, the hydrogen production capacity of all the EU’s refineries amounted to 2.33 Mt in 2017 [30]. Meanwhile, consumption in 2015 reached 2.1 Mt [18]. In 2018, the EU’s refineries produced a total of 639 Mt of crude oil products [31]. The crude oil loss stemming from energy provision in refineries lies within a range of 5 to 10 percent worldwide [34]. Diesel took up the largest share among these products in the EU with 291 Mt, while gasoline and jet fuel followed behind, with 82 and 64 Mt respectively. Naphtha and LPG production amounted to 72 Mt. Germany’s 12 refineries produce fuels, naphtha, LPG, fuel oil, asphalt and carbon as usable products and process approximately 103 Mt crude oil [18]. It is expected that combustion engines will still exist after 2030 and that hydrogen will mainly replace diesel in trucks, buses, diggers and ships, as electrification would have adverse effects on those vehicles from a logistical or financial perspective, while hydrogen would offer advantages over batteries both in terms of range and costs. Furthermore, non-electrified train transportation is expected to switch from diesel to hydrogen [29, 39–41]. At present, up to a sixth of the EU’s diesel is imported, and approximately one third of the gasoline produced in the EU is exported [40]. However, hydrogen demand for fuel production at refineries could change drastically once a global hydrogen economy for fuels develops outside of refineries or the ratio of diesel to gasoline is altered. Furthermore, the development of biofuels, which are also governed by RED-II, and the fact that they generally require larger quantities of hydrogen per unit of mass are set to become important factors. However, the product volumes fall below those of fossil fuels by more than a factor of ten [42].

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5.2.3

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New methods of synthesizing basic chemicals with green hydrogen

In addition to production in refineries, the production of basic chemicals and their derivative products also requires large quantities of hydrogen and CO2 . Until now, these have primarily come from fossil sources. However, new methods of synthesizing these basic chemicals have made it possible to obtain the source materials from external, independent and sustainable sources. Some important examples are discussed below.

Methanol Currently, methanol (CH3 OH) is generally produced using a synthesis gas composed of hydrogen (H2 ), carbon monoxide (CO) and carbon dioxide (CO2 ) and obtained from raw material sources such as coal, petroleum or natural gas. There is a wide range of possible processes for manufacturing methanol, and the choice of process is heavily dependent on the raw material and operating conditions involved. If natural gas is the primary feedstock (source) of the synthesis gases, the low-pressure process is often used. The synthesis reactor used in this process is operated at a pressure of between 50 and 100 bar, with a temperature of between 200 and 300 °C [43]. One advantage of methanol synthesis is that CO2 can be used directly or in a mixture with CO. 2H2 C CO ! CH3 OH 3H2 C CO2 ! CH3 OH C H2 O This process can make decentralized, small-scale manufacturing an economically viable prospect. To produce a high methanol yield, the components H2 , CO and CO2 are fed into the reactor’s input stream in the following molar ratio: H2  CO2 D 2:05  2:1 CO C CO2 The reaction is very selective. Water is practically the only by-product, and this can be separated out by a simple rectification process at the end. In 2017, global production of methanol reached 90 Mt/a. Based on current trends, this figure is set to reach 135 Mt/a by 2027 [44]. As the availability of fossil raw materials such as coal, petroleum and natural gas will decrease in the future, and the emissions released in the production of conventional synthesis gas pose a growing economic problem, there is great interest in accessing new raw materials (feedstocks) that could serve as a source of synthesis gas.

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Thanks to the high technology readiness level of the comparatively simple methanol synthesis process, the reaction’s high degree of selectivity, the excellent scalability and the possibility of using CO2 directly, methanol is numbered among the candidate substances for CCU strategies that have the potential to be worthwhile. In addition, there is already an established market for methanol today, both in the area of fuels and, following further syntheses, chemical raw materials. Improving the sustainability of methanol production will invariably require hydrogen from renewable sources, e.g., from water electrolysis; see also Sect. 5.2.1. In addition, a carbon source will always be required. This can be obtained from smelting gases or CO2 from waste gases; see also Sect. 5.3. However, it can also be taken from the atmosphere, resulting in negative emissions. This means methanol synthesis can be used to reduce the carbon footprint of energy-intensive processes. The demand for methanol will increase further in the future, e.g., due to its potential for use as a fuel. Methanol is already used as a fuel in combustion engines, and tests are underway to explore whether it can be used in shipping. Methanol is also used to manufacture biodiesel. However, due to its high levels of toxicity and its high vapor pressure at ambient air temperatures, it also has certain properties that are less advantageous than other fuels. Despite this, the EN 228 standard permits gasoline to be mixed with methanol up to 3 percent. In addition to functioning as a fuel, methanol is an important basic chemical, meaning that it also serves as a feedstock (source material) for manufacturing other energy carriers via methanolto-hydrocarbon processes, such as methanol-to-gasoline (MtG), dimethyl carbonate + methyl formate + ethanol (DMC+), dimethyl ether (DME) and oxymethylene ether (OME) [45]. For example, in the chemical industry, in addition to ethanoic acid, it is most commonly used to produce formaldehyde. In the future, hydrogen will gain importance as a material, particularly as methanol-to-olefin processes become more common, which, together with ethylene and propylene, are used to supply what are arguably the most important basic substances for polymers (PP, PE) at present. Consequently, methanol synthesis and its derivative processes represent an economically viable means of accessing olefins and aromatic compounds without using fossil sources. This puts methanol synthesis in competition with FischerTropsch synthesis, which can also be used to manufacture these products, depending on the catalyst and the process conditions. Fischer-Tropsch synthesis, which uses synthesis gas (CO/H2 ) directly, is currently undergoing something of a renaissance itself, as new developments such as using tandem catalyst systems to manufacture PtL fuels (synfuels such as synthetic gasoline, diesel and kerosene) have made it competitive once more. Depending on the retention time and reac-

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tion conditions, the process produces hydrocarbons of varying chain lengths and degrees of branching.

Ammonia With yearly production volumes reaching around 200 Mt, ammonia is one of the most important chemicals worldwide. It is especially important for fertilizer manufacturing. Its most prominent derivative products are urea, ammonium sulfate and ammonium phosphate. Ammonia is also used as a source material in the chemical industry and as a freezing agent in various fields of application. The chemical has no global warming potential (GWP), but the products it is used in can result in the formation of fine particulates [46] and soil acidification [47]. It is produced from nitrogen and hydrogen via the Haber-Bosch process. The nitrogen is obtained via air separation, while the hydrogen is produced via methane reforming. The heterogeneous catalytic process is conducted at a temperature of 400 to 500 °C, a pressure of 300 bar and a molar H2 :N2 ratio of 3:1. Traditionally, iron was used a catalyst in the process; however, modern variants use rutheniumbased catalysts. The air separation and the conditions required for the process make ammonia synthesis highly energy-intensive [48]. In fact, ammonia synthesis is responsible for 2 percent of global primary energy consumption and, at 2 t CO2 per ton NH3 , it produces around 1.6 percent of global CO2 emissions. In an effort to reduce these figures, some initial attempts are being made to switch the process entirely to renewable energy. To do this, the air separation process must be powered by renewable energy and the hydrogen must be obtained via water electrolysis. Ammonia has the potential to become a lot more than just fertilizer—in the future, it could also serve as a direct energy carrier or as a carrier molecule for hydrogen. As ammonia molecules have around 17.8 wt% H2 , the gas can transport large quantities of hydrogen. As ammonia liquefies at a pressure of just 10 bar at ambient temperatures, and there are existing, relatively simple and cheap means of transporting, storing and manufacturing it, it is a very promising candidate for a carrier to transport hydrogen over long distances. However, more research is still required as regards the reconversion of ammonia. It could also serve as an alternative form of hydrogen storage for fuel cells. In some cases, fuel cells can be directly powered by ammonia, but otherwise, the hydrogen is extracted from the ammonia beforehand by means of catalytic decomposition before being fed into a fuel cell. Scientists are also currently exploring the possibility of directly using ammonia as fuel in engines and combustion processes, particularly in stationary engines in ships, but also in turbines and gas burners. Nitrogen-based fuels have various advantages, such as their high level of availability, well-established manufactur-

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ing process, existing production and logistics infrastructure, and their similarity to LPG. However, they do come with certain disadvantages, namely corrosiveness, toxicity and the relatively low higher heating value of ammonia [49].

Higher alcohols In addition to methanol, the simplest alcohol, synthesis gases can also be used to produce higher alcohols. The most notable products produced via hydroformylation are butanol and ethylhexanol; these can both be manufactured from butanal, which is also a product of hydroformylation itself. The oxo process is currently the most commonly used method for this synthesis: Propene C CO=H2 ! Butanal ! Ethylhexanol Other methods include hydrating alkenes and hydrogenating fatty acids to form alcohols with more than five carbon atoms. At present, researchers are primarily focusing on manufacturing alcohols from synthesis gas, which would involve direct use of CO2 , among other things. Attempts are also being made to ferment synthesis gas in order to produce higher alcohols, especially ethanol, n- and iso-propanol, and n- and iso-butanol. The manufacturing process is generally based on a synthesis gas consisting of CO and H2 in a 1:1 ratio, as well as modified Fischer-Tropsch catalysts. However, the reaction often has a low level of selectivity, meaning that not only alcohols, but also alkenes, alkanes, aldehydes and acids may be produced. The use of CO-based gases and the wide range of resulting products are two of the primary reasons that higher alcohols are not yet manufactured on a larger scale. There are many possible applications for alcohol, especially in the chemical industry, where they are used to manufacture plasticizers, detergents and cleaning agents.

5.3

Unavoidable industrial CO2 emissions: a future source of carbon

The synthesis of organic compounds using climate-neutral hydrogen requires carbon, either as a pure element or in a chemical compound preferred as carbon dioxide or carbon monoxide. If these synthesis processes are to contribute to the overall avoidance of greenhouse gas emissions, carbon dioxide from sources that will still be available in a future, largely climate-neutral world must be given priority. As described in Sect. 5.1.2, the steel industry could serve as a possible source of carbon oxides here. Others are described below.

5.3 Unavoidable industrial CO2 emissions: a future source of carbon

107

When producing burnt lime (CaO) from limestone (CaCO3 ), or when producing cement clinker (the most important component in cement) from primarily carbonate-based stone, carbon dioxide is emitted during the calcination step, whereby the solid material undergoes heating. While the energy for heating the furnaces in question could be obtained from renewable sources in the future, meaning that it could be supplied without any carbon dioxide emissions, it is not possible to prevent the emissions released from the raw materials [50]. Consequently, if their production levels remain close to constant, cement clinker and lime plants will continue to act as point sources of relatively large and concentrated carbon dioxide flows in the future. When it comes to thermal waste treatment, the primary goal is to reduce the volume of waste, while simultaneously converting the remainder into a form that can be used or disposed of safely. This process takes place in waste incineration plants, where the carbon-based waste components are converted into carbon dioxide using the energy that is released. Thanks to the increased use of chemical recycling processes, the amount of waste that cannot be reused or used as a raw material will gradually decrease, as continued advancements in scientific research are making it possible to bring ever larger shares of waste into a closed-loop carbon cycle. However, in the long term, it is also to be expected that some waste streams will continue to undergo thermal treatment. Depending on the proportion of carbon the waste contains, thermal waste treatment facilities are likely to be available as a source of carbon dioxide for many years to come. In this context, it should be noted that a large portion (approx. 50 percent) of the CO2 comes from biomass residues in the waste and that both this and the portion of the power generated from it are climate neutral. These sources share one common characteristic, namely that the carbon dioxide has so far been emitted into the atmosphere in diluted form as part of the facilities’ waste gases. In conventional processes, this dilution is primarily caused by nitrogen and residual oxygen from the combustion air. In order to use these sources to supply pure carbon dioxide as a source material (feedstock) for synthesis processes (utilization) in the future, scientists are currently exploring and developing various technological methods of carbon capture [51], including the following:  Separating the diluted carbon dioxide from the waste gas via a physicalchemical “washing” process  Chemically binding the diluted carbon dioxide from a gas flow to calcium monoxide and then extracting the pure carbon dioxide by heating the resulting calcium carbonate (calcium looping)

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 Increasing the carbon dioxide content in the waste gas stream by using a mixture of pure oxygen and recycled waste gas, instead of combustion by air containing nitrogen (oxyfuel process)  Indirectly heating the material during calcination, so that pure carbon dioxide is expelled and separated from the carbonate-based stone.

5.4

Hydrogen: an energy source for industry

At present, the primary industrial uses for hydrogen are ammonia synthesis and hydrotreating or hydrocracking (cf. Sect. 5.2.1). It is hardly used for energy generation anywhere in the sector. The challenge of making all processes more or less climate neutral by 2045 also affects industrial heat generation, which up to now relies mostly on fossil-based energy carriers. Some 30 percent of CO2 emissions in Europe result from high-temperature processes [29]. Together with renewable heat sources, such as deep geothermal systems and the use of electricity for heat generation, climate-neutral hydrogen and the energy carriers it is used to produce, such as ammonia, methane and methanol, will constitute the three core elements of industrial heat supply in the future. The supply of process heat amounted to 21.5 percent of final energy consumption in Germany in 2019 [52]. A substantial portion of the industrial heat demand stems from heat-intensive industries such as paper and cardboard manufacturing, which usually calls for temperatures of around 160 °C for drying processes. The chemical industry also requires heat for process steam. However, hydrogen is primarily relevant to high-temperature processes that can only be electrically powered to a limited extent.

5.4.1

Supplying process heat from hydrogen: the basic principles

It is technically possible to use hydrogen to supply process heat for heat-intensive industries. However, to do this, technology and combustion process control systems will have to be adjusted (modified and adapted). Ongoing developments here include the gradual replacement of natural gas with hydrogen and steam production using pure hydrogen.

5.4 Hydrogen: an energy source for industry

109

The following equation describes the reaction that takes place when hydrogen is burned: 2H2 C O2 ! 2H2 O With a lower heating value of approx. 11 MJ/Nm3 and a higher heating value of approx. 13 MJ/Nm3 , hydrogen’s energy content per unit of volume is approximately one third that of natural gas. If no other atoms are present, a hydrogen-oxygen flame will only emit light in the ultraviolet and infrared ranges of the spectrum and will produce heat energy and water. If burned in air, small quantities of nitrogen oxides (NOx ) are also formed. To burn hydrogen in air, a concentration between 4 and 75 vol% is required [53]. However, the number of high-temperature processes using hydrogen is still limited. This is due to the restricted availability of (green) hydrogen and the fact that its burning behavior strongly differ from those of natural gas. Hydrogen has a much lower density, a much higher laminar flame speed [54], reduced lower and higher heating values per unit volume and other flammability limits. This results in different flame shapes and stability during combustion, for which existing processes, equipment and burners are not designed to accommodate. As the flame has different radiation properties, adjustments would be needed in certain processes, e.g., in the glass industry, in order to achieve equivalent product quality [55].

5.4.2

Combustion of natural gas and hydrogen mixtures

With up 41 percent of final energy consumption, natural gas is the most important energy carrier for process heat generation [52]. According to the German Technical and Scientific Association for Gas and Water (DVGW), mixing a concentration of up to 10 vol% hydrogen into the German natural gas network would currently be technically feasible, and plans are in place to increase that concentration to 20 percent [56]. Other proposed approaches to constructing a hydrogen infrastructure are based on switching sections of the existing natural gas network solely to hydrogen [57]. Furthermore, this partial substitution of hydrogen for natural gas creates challenges regarding the natural gas burners, due to the differing combustion properties described above. These challenges relate primarily to efficiency, equipment safety and the emissions generated in the process. For example, as the concentration of hydrogen in the mixture is increased, the mixture’s lower heating value drops, while its adiabatic flame temperature rises. This can be problematic if the rising

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flame temperature promotes the formation of thermal NOx . As the hydrogen concentration is increased, the air-fuel ratio and the volume flow of the combustion gas must be adjusted. If this is accomplished primarily by means of appropriate H2 measurements and equipment control systems, it is possible to reduce the effects on emissions (NOx ) and efficiency that are seen in various equipment types when hydrogen is added to the mixture up to a concentration of 50 vol% [58]. Nevertheless, equipment adjustments, particularly of the burner geometry, may become necessary when the hydrogen content is high. In [59], Ferrarotti et al. demonstrated that stable operations could be achieved in a flameless burner system with hydrogen concentrations of up to 75 vol% by means of optimized injection. However, in an industrial context, even slight fluctuations in gas composition can have a negative impact on downstream processes, making it necessary to conduct studies on the possibility of refitting existing facilities (see [55] for example).

5.4.3

Direct steam generation using hydrogen

Currently, there are very few industrial applications for the direct generation of steam using pure hydrogen. In the future, however, oxyfuel processes may be a viable option for emission-free thermoprocessing plants. Oxyfuel processes use pure oxygen during combustion rather than ambient air, preventing the formation of undesirable gases such as NOx . Water is the only product that results when pure hydrogen is burned with pure oxygen, which makes producing process steam directly by means of suitable combustion management an attractive option. To do this, suitable technology and process management methods must be developed for the burner, that must be capable of dealing with hydrogen’s abovementioned flame speed, flammability and flame temperature properties. One solution for reducing the flame temperature, and thus also the thermal stress within the combustion chamber, involves diluting the flame with steam [60].

5.5

Hydrogen in the ceramic industry

In 2019, the ceramic industry achieved a turnover of around 5.4 billion euros across 200 companies. However, sintering processes make the sector extremely energy—and CO2 —intensive. The key ceramic branches in Germany are the structural clay sector, which manufactures products such as bricks and tiles, and the fine ceramic industry, which produces sanitary and household ware and technical ceramics. In energy, environmental and medical engineering, technical ceramics in

5.5 Hydrogen in the ceramic industry

111

Fig. 5.10 Electricity and gas consumption in individual ceramic sectors in Germany (2019)

particular are driving the development of innovative products in the fields of battery, fuel cell, electrolysis and membrane technology. The ceramic industry uses thermal energy for the most part (2019: 10.1 TWh), which is mainly generated from natural gas (approx. 86 percent, 8.7 TWh); the rest comes from electricity consumption (1.4 TWh) [61]. Bricks, tiles and fireproof ceramics use the lowest proportion of electricity, at 11 percent, while electricity makes up 15 percent of the energy used for household and sanitary ware. At 25 percent, technical ceramics are the leader in this field (Fig. 5.10). Sintering ceramic ware by baking it once or many times over requires temperatures ranging between 500 and 2500 °C. This constitutes the most energy-intensive step within the ceramic manufacturing process, with an 80 to 90 percent share of the overall energy consumption. Bricks, tiles and technical and fireproof ceramic ware are the most energy-intensive branches of the sector. Technical ceramics also produce by far the highest specific CO2 emissions, at 4 t CO2 -eq per ton of products. However, due to its higher production volumes, the brick manufacturing branch generates significantly more emissions overall, with 1.73 Mt CO2 eq (Fig. 5.11). Due to its high natural gas demand and the associated CO2 emissions amounting to 2.6 Mt CO2 eq per year, intensive efforts to substantially reduce emissions in the ceramic sector have long been underway, by means of technological innova-

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Fig. 5.11 CO2 emissions of the ceramic sector branches in Germany (in Mt CO2 eq, 2019) [61]

tions in the combustion process, insulation and heat recovery, as well as by using alternative energy carriers. At present, stakeholders in the ceramic industry are implementing measures aimed at increasing energy efficiency and consequently reducing the primary energy demand. For the ceramic industry to become carbon neutral, in the future, all combustion processes will have to be electrified or refitted to use hydrogen for fuel, in so far as the particular process allows. Switching to electrically powered kilns with a higher share of renewable energy is more energy efficient than using green hydrogen from electrolysis. Operating temperatures can sometimes make it very costly to use electrical energy. If this is the case, it is possible to use hydrogen, or a mixture of hydrogen and natural gas. If hydrogen were used as a fuel, it would be necessary to update the burner and the safety technology of the kiln, as well as to study the impact of the altered gas atmosphere on product quality. If we base our estimate for the maximum potential use of hydrogen in the ceramic industry on a complete replacement of the entire natural gas output of 8.9 TWh, this would result in a hydrogen demand of 2.97 billion Nm3 per year. Representatives from research and industry are collaborating in numerous projects (ENITEC, HTPgeox, EnerTherm, FF-light, AEROREF) aimed at developing ways of making combustion and drying processes more energy efficient, as well as methods for evaluating altered influencing factors relating to atmosphere composition, temperature distribution and the product quality of the material structure. To contribute to sustainable emission reduction strategies involving a gradual increase in the share of hydrogen in the fuel gas, stakeholders from the glass and ceramic industry are working in a number of joint initiatives aimed at using hy-

5.6 Outlook

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drogen burners for individual, particularly intensive process steps and at refitting their systems to run entirely on hydrogen in the future. The Deutsche Keramische Gesellschaft (German ceramic society, DKG) has commissioned Fraunhofer IKTS to produce a road map for reducing CO2 emissions in the ceramic industry.

5.6

Outlook

It is not within the scope of this book to develop a road map or possible scenarios for implementing the individual technologies of the industries described here as part of a sector coupling initiative. Nevertheless, the future intensity of certain sectors’ activities is at least qualitatively analyzed from a technical perspective and an estimate formulated. This estimate draws on the findings of the hydrogen road map for Germany, produced by Fraunhofer, where possible courses of action and obstacles to market entry were also identified [26]. Both in Germany and at an international level, these obstacles mainly relate to the lack of coordination in terms of legislation, as regulations often have different aims and are not designed to span multiple sectors. The lack of an international trade system for green hydrogen, steel, cement, carbon dioxide and fuels is another notable issue here. Furthermore, there are currently no internationally coordinated and certified standards for hydrogen-based energy carriers, chemicals and materials. To analyze the intensity of the individual industries’ future activities as regards sector coupling, the EU was taken as the scope for the carbon footprint calculations here, as per the targets outlined in the European Green Deal [62]. Based on the simplified assumption that the developments will follow an ideal course (i.e., with technical issues being the primary limiting factor) and that global framework conditions and market obstacles will have a low impact, the probable future level of sector coupling activity within each industry branch can be qualitatively evaluated from a technological perspective on a scale of 0 to 10 relative to 2020. Fig. 5.12 illustrates the results of this structured, qualitative analysis based on two scenarios, one with slower and one with faster technological implementation. By 2030, refineries—in combination with the energy and chemical sectors—could be the core element of all feasible sector coupling activities. In Germany and the EU, the (petro-)chemical, energy and refinery sectors are working to construct a shared hydrogen pipeline and are already operating large-scale electrolyzers [63]. The RED-II and the Emissions Trading System (ETS) are the driving forces behind the implementation, which appears to be financially feasible for industry and society in terms of costs. Hydrogen produced via steam cracking is only present in refinery products as a percentage by weight, which means that

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Fig. 5.12 Qualitative analysis of the intensity of individual industries’ future sector coupling activities in the EU on a scale of 0 to 10

the starting prices of 5 to 10 euro/kg of H2 will not have much impact. The share of product costs is expected to be equally low in the (petro-)chemical industry. From 2030, government subsidies and additional regulations and standards, combined with intensive efforts by researchers to reduce costs, should give more and more sectors the opportunity to join in these initiatives.

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44. Bertau M., Offermanns H., Plass L. et al. (2014): Methanol: The Basic Chemical and Energy Feedstock of the Future: Asinger’s Vision Today, 2014 edition. Springer Berlin, Heidelberg 45. Maus W., Jacob E., Härtl M. et al. (2014): Synthetic fuels—OME1: A Potentially Sustainable Diesel Fuel. 35. International Vienna Motor Symposium, Fortschritt-Berichte VDI (VDI progress reports)12 (777), vol.1, 325–347 46. Pozzer A., Tsimpidi A.P., Karydis V.A. et al. (2017): Impact of agricultural emission reductions on fine particulate matter and public health. Atmospheric Chemistry and Physics Discussions. https://doi.org/10.5194/acp-2017-390 47. Bayerisches Landesamt für Umwelt (Bavarian state office for the environment) (2018): UmweltWissen—Schadstoffe—Ammoniak und Ammonium (Environmental knowledge—pollutants—ammonia and ammonium). https://www.lfu.bayern.de/buerger/doc/ uw_6_ammoniak_ammonium.pdf, last viewed on November 21, 2021 48. Strait R. (1999): Nitrogen & Methanol 38: 37–43 49. Aziz M., Wijayanta A.T., Nandiyanto A.B.D. (2020): Ammonia as Effective Hydrogen Storage: A Review on Production, Storage and Utilization. Energies 13: 3062. https:// doi.org/10.3390/en13123062 50. Verein Deutscher Zementwerke e. V. (Association of German cement manufacturers) (2020): Decarbonising Cement and Concrete: A CO2 Roadmap for the German cement industry, Düsseldorf. https://www.vdz-online.de/fileadmin/wissensportal/publikationen/ zementindustrie/VDZ-Studie_Dekarbonisierung_Zement_Beton_2020.pdf, last viewed on November 21, 2021 51. acatech (2018): CCU and CCS—Building Blocks for Climate Protection in Industry (acatech POSITION PAPER), Munich. https://en.acatech.de/publication/ ccu-and-ccs-contributing-to-climate-protection-in-industry-analysis-options-andrecommendations/download-pdf?lang=en, last viewed on November 21, 2021 52. German Federal Ministry for Economic Affairs and Energy (2021): Energy Data: Complete Edition https://www.bmwk.de/Redaktion/EN/Artikel/Energy/energydata.html, last viewed on November 21, 2021 53. Hartmann-Schreier J. (2004): Wasserstoff (hydrogen), RD-23-00368. In: Böckler F., Dill B., Dingerdissen U. et al. RÖMPP [Online], Stuttgart. https://roempp.thieme.de/lexicon/ RD-23-00368, last viewed on February 5, 2021 54. Ilbas M. et al. (2006): International Journal of Hydrogen Energy 31: 1768–1779 (2006) 55. Ministry of Economic Affairs, Innovation, Digitalization and Energy of the State of North Rhine-Westphalia: IN4climate.NRW—Best Practice—Projects—HyGlass. https://www.in4climate.nrw/best-practice/2020/hyglass/, last viewed on February 5, 2021 56. DVGW—German Technical and Scientific Association for Gas and Water (2021): Klimaschutz und Resilienz. Der Umsetzungsplan für Wasserstoff und klimaneutrale Gase (Climate protection and resilience: the implementation plan for hydrogen and climateneutral gases). Bonn, 60 p. 57. FNB Gas (2020): Fernleitungsbetreiber veröffentlichen Karte für visionäres Wasserstoffnetz (Pipeline operators publish map for visionary hydrogen network). https:// fnb-gas.de/news/fernleitungsnetzbetreiber-veroeffentlichen-karte-fuer-visionaereswasserstoffnetz/, last viewed on January 5, 2022

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58. Leicher J., Nowakowski T., Giese A. et al. (2017): Higher concentrations of hydrogen in natural gas and their impact on industrial combustion systems. heat processing: 65–72 59. Ferrarotti M., De Paepe W., Parente A. (2021): Reactive structures and NOx emissions of methane/hydrogen mixtures in flameless combustion. International Journal of Hydrogen Energy 46 (68): 34018–34045, https://doi.org/10.1016/j.ijhydene.2021.07.161 60. Tanneberger T., Schimek S., Paschereit C.O. et al. (2019): Combustion efficiency measurements and burner characterization in a hydrogen-oxyfuel combustor. International Journal of Hydrogen Energy 44: 29752–29764. https://doi.org/10.1016/j.ijhydene.2019. 05.055 61. Own research based on data collected by Ceram-Unie 2021, destatis and the road map for climate-neutral brick industry in Germany 62. European Commission: A European Green Deal—Striving to be the first climate-neutral continent https://ec.europa.eu/info/strategy/priorities-2019-2024/european-green-deal_ en, last viewed on July 26, 2022 63. RWE partner project at the Lingen site—GET H2 Nukleus. https://www.rwe.com/en/ research-and-development/hydrogen-projects/hydrogen-project-get-h2, last viewed on July 26, 2022

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Hydrogen technologies in mobility and transportation

Ulf Groos  Malte Semmel  Achim Schaadt Fraunhofer Institute for Solar Energy Systems ISE Stefan Bürger Fraunhofer Institute for Chemical Technology ICT Felix Horch Fraunhofer Institute for Manufacturing Technology and Advanced Materials IFAM Johannes Geiling  Richard Öchsner Fraunhofer Institute for Integrated Systems and Device Technology IISB Gunther Kolb Fraunhofer Institute for Microengineering and Microsystems IMM Jonathan Köhler Fraunhofer Institute for Systems and Innovation Research ISI Abstract

With its low weight and high energy content, hydrogen is viewed as a promising option for transport in the future. This chapter outlines and discusses various options for hydrogen-powered drives such as combustion and fuel cells as well as storage options such as pressure tanks, hydrides and synthetic fuels. It also discusses the types of hydrogen-powered drives that are suitable for different kinds of transportation.

© Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_6

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Introduction

Hydrogen can in principle be used for a range of applications in the mobility sector. In the USA in particular, fuel cell drives are already regularly used in the area of in-plant material transportation, for instance in forklift trucks. Fuel cell vehicles in the passenger car market are commercially available in initial small-scale batches from Asian manufacturers. Vehicle fleets for communal bus transportation are also being established worldwide. In the truck segment, particularly in terms of medium and heavy-duty trucks, there have been significant developments in the use of hydrogen technologies (fuel cells, hydrogen internal combustion engines and internal combustion engines for synthetic fuels). In rail transportation, the first fleet trials with fuel cells for use on non-electrified line sections have started (in the Bremervörde area of Lower Saxony in Germany, for example). Niche applications also offer market potential (for road service vehicles, municipal vehicles, construction site vehicles and other similar specialist vehicles such as ground vehicles in airports or heavy-goods vehicles in ports). In addition, there are plans in the maritime sector to conduct initial fuel cell tests on ferries and cruise ships. The first prototypes for inland waterway transportation are already in place, and fuel cells have been in use by the military at sea for a number of years now, e.g., in Type 212A submarines. Methanol, which is already manufactured synthetically using hydrogen and carbon dioxide in an environmentally friendly way at pilot facilities, has been used with success in the shipping industry for several years. Scientists are also researching how hydrogen technologies can be applied to aviation. As well as battery electric mobility, green hydrogen manufactured using a renewable process via electrolysis offers emission-free, or at least low-emission, mobility using fuel cells or internal combustion engines for hydrogen or for synthetic fuels. Additionally, carbon dioxide, nitrogen or hydrogen produced from renewable sources can be used to manufacture hydrogen carriers such as methanol, ammonia and synthetic hydrocarbons, which could play an important role for heavy load and rail-borne transportation as well as shipping and air travel.

6.2 Hydrogen technologies for powertrains 6.2.1

Fuel cell drives

Fuel cells are electrochemical energy converters that use material energy carriers such as hydrogen to generate electricity and heating. In comparison to batteries, material energy carriers have high energy densities, so they enable greater ranges

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Fig. 6.1 Schematic representation of a fuel cell vehicle that generates electrochemical power in the fuel cell as well as in the electric motor (front of vehicle), hydrogen tanks and battery module (rear). (Fraunhofer ISE)

with the same weight and volume. They also allow vehicles to be refueled quicker than by battery charging. Energy conversion and energy storage in fuel cells take place in separate technological units and can thus be specifically designed for their respective application (Fig. 6.1). Fuel cell systems achieve electrical efficiencies of between 40 and 65 percent and therefore allow for high fuel utilization. They generally have higher efficiencies than internal combustion engines. Waste heat can be used in vehicles for temperature control and air conditioning. When used in winter, there is therefore typically very little loss of range compared to summertime use. Vehicles operated using hydrogen are locally emission-free and only emit moist exhaust air. Due to their low number of moving parts such as air compressors, anode recirculation pumps and valves, the systems are low-noise and low-maintenance. Compared to batteries, fuel cell systems have a complex construction. They require an air supply with a corresponding structure comprising filter, humidifier, compressor and cooler in addition to an anode supply with recirculation. Active cooling is normally achieved using liquid coolant. Since fuel cell catalysts are susceptible to contamination, high gas purity at the anode and cathode side and corrosion-resistant components are necessary. The latter is of particular importance in view of the fact that vehicle operation produces deionized water and creates a typically acid environment. Due to the temperature level of below 100 degrees Celsius for low-temperature polymer electrolyte membrane fuel cells (LT-PEMFC), a large cooling area is required. The product water generated must not have any impact on the vehicle’s ability to start under frost conditions.

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Internal combustion engine-powered drives for hydrogen

Hydrogen can be used as a fuel in internal combustion engines in addition to fuel cells. Compared to the combustion of conventional fuels, using hydrogen in internal combustion engines allows for higher efficiencies, particularly at higher loads. Modern combustion engines can be adapted for hydrogen usage. Existing production lines can be deployed to manufacture hydrogen internal combustion engines. Only low quantities of nitrogen oxide are emitted during combustion, which ensures compliance with current emission limits. In the future, it can be assumed that compliance with the new, stricter Euro 7 emission standards set to be introduced can be ensured through the use of existing selective catalytic reduction (SCR) technology, potentially in combination with innovative fuel evaporation technology. The hydrogen tank system for hydrogen-powered vehicles is higher in cost and requires more installation space. This affects vehicles with hydrogen internal combustion engines and fuel cell drive equally. However, the efficiency of fuel cell systems is significantly higher, and their consumption is therefore lower. Conversely, cars with hydrogen internal combustion engines require larger tanks to achieve the same range.

6.2.3 On-board hydrogen storage There is already a wide range of solutions available for hydrogen storage. The main difference between these solutions is that they store hydrogen in different aggregate conditions. These different conditions also result in various energy densities at which the hydrogen can be stored. A comparison is shown in Fig. 6.2. For instance, hydrogen compressed at 700 bar (compressed gaseous hydrogen, CgH2 ) has a net storage density of 1.3 kWh/l. However, system volume must also be taken into consideration, since it results in a decrease in system storage density. As can be seen in Fig. 6.2, this is true for all hydrogen storage systems. If liquid hydrogen (LH2 ) and cryo-compressed hydrogen (CcH2 ) are used, system storage density is almost doubled. However, the energy densities of previous storage systems for hydrogen are lower than those of fossil fuels [1, 2]. Research is continuing in the area of hydrogen storage and focused in particular on its use in the transportation sector [3]. For instance, in addition to storage options for transporting hydrogen in its pure form, other storage methods in which hydrogen is chemically or physically bonded are also being investigated [4]. This would simplify transportation and storage. Storing hydrogen in a solid state using

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Fig. 6.2 Energy densities of current storage systems. (Fraunhofer ICT)

Mg, Li, Be, LaNi5 and Ti-Fe [5, 6] or as a liquid is also the subject of research. There is particular interest in converting it into methanol [7] or bonding it to LOHC (liquid organic hydrogen carriers) [8]. Hydrogen rebonding to gases with an existing supply infrastructure, in particular ammonia and methane [9, 10], is also being investigated. These fuels offer an advantage in that they already have established distribution, handling and transportation networks. However, when compared to the storage of hydrogen in its pure form, these processes have a major disadvantage in terms of their efficiency in the production chain. Conversion, absorption, adsorption as well as the release of hydrogen are additional process steps and reduce the overall efficiency of fuel production and supply. In addition to hydrogen, the respective carrier must also be included, which results in the system gaining mass. Furthermore, many of these processes are still at a basic level of development or have not yet been optimized for the hydrogen economy. Where hydrogen is used in LT-PEMFCs, a complex gas purification process may be necessary to avoid contamination.

Compressed hydrogen Storing hydrogen in pressure vessels is the current industrial standard for mobile drive systems. These have already been installed in various passenger vehicles [11].

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The first commercial vehicles with pressure tanks have also been introduced and put into operation [12]. Type IV all-carbon pressure vessels are generally used here [13]. For this kind of tank system, multiple safety mechanisms are incorporated into the building design. The first safety mechanism is located directly on the tank. It consists of a valve called a thermally activated pressure relief device (TPRD). If the temperature in the tank increases beyond a predefined value, this valve will automatically open and release the remaining hydrogen in a controlled way. The purpose of this device is to prevent overheating in the tank and the resulting increase in pressure. Another important component is the infrared interface. This interface communicates with the tank system during the refueling process and transmits pressure and temperature data from the gas storage tanks. System pressure is regulated and monitored upstream of the gas outlet to the fuel cell. In case of excess pressure, a safety release valve is built in for the controlled release of the hydrogen into the environment. Space and material requirements pose a challenge for pressure tank systems. Usually, several pressure tanks must be installed in the vehicles and coupled to each other. Reducing the storage pressure to 500 bar is one potential solution to this problem. This value can be viewed as a “sweet spot” for the ratio between the weight of the volume of transported hydrogen and the weight of the tank. Due to the reduced pressure, less material is needed to achieve the required stability. This enables the same or a larger quantity of hydrogen to be transported with only a slight increase in volume but by using fewer tanks that weigh less. This allows storage system costs to be lowered. However, the global standard for compressed gas storage tanks in passenger cars is set at 700 bar and this is not expected to change.

Liquid hydrogen Due to its higher specific energy and material density, there is particular interest in using liquid hydrogen for the heavy-duty transportation sector [14, 15]. It requires gaseous hydrogen to be cooled to 253 °C (boiling point at ambient pressure). The liquid hydrogen is then stored in super-insulated tanks. For use in a commercial vehicle, for instance, the hydrogen is heated using the waste heat from the fuel cell. The liquid hydrogen can thus be converted back into a gaseous state and introduced into the drive module. One storage-related challenge is that the pressure inside the storage tank increases as soon as the boiling point for hydrogen is reached. These tanks are not typically designed to withstand high pressure (> 30 bar). As soon as the maximum pressure has been reached, the hydrogen must be released. This effect is known as boil-off and occurs almost exclusively when the vehicle

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is at a standstill. If the vaporized hydrogen is not used for energy production, it must be released into the environment to reduce pressure in the container. The vehicle therefore loses fuel when it is not in operation [16, 17]. In order to mitigate the boil-off effect, the tanks should have the smallest possible ratio of surface to volume [14]. These storage tanks are advantageous in terms of their wide availability and the low cost of the materials used for their construction. They are mainly produced using stainless steel and aluminum and thus have a cost advantage over pressure tanks, which use expensive carbon fiber. An LH2 storage container can also store more hydrogen in a smaller volume, which in turn reduces storage costs further, since fewer containers are required [15, 18].

Cryo-compressed hydrogen Another proposed storage option is cryo-compressed hydrogen. A liquid hydrogen tank that simultaneously functions as a pressure container is used here, usually at 350 bar. This allows for potential emergency refueling at 350-bar hydrogen refueling stations. As such, even in a transitional phase where an extensive network of liquid hydrogen refueling stations has yet to be established, it would still be possible for cars to run on cryo-compressed hydrogen. As depicted in Fig. 6.2, this method has the highest system storage density. This storage method has already been evaluated for use in passenger vehicles [19, 20]. However, development was put on hold in 2016 after a number of challenges arose. One challenge was isolating the tank container. Vacuum insulation, which is technically complex, was used at the time. The negative pressure between the outer and inner shell of the tank, where the vacuum is located, places the materials under very high strain. Despite the high temperature difference between the outer and inner shells, they must be able to withstand the tensile strain. Moreover, the materials used in the inner shell must be protected against low-temperature and hydrogen embrittlement. This makes selecting materials very difficult, especially when the tank design needs to incorporate lightweight components.

Reformate hydrogen Hydrogen can be produced from liquid and gaseous hydrogen carriers such as methane, methanol, hydrocarbons and ammonia. At present, these substances are generally produced or extracted using fossil fuels. However, in the future, it will be possible to produce them through renewable means that don’t pollute the atmosphere, such as by using atmospheric carbon dioxide or carbon dioxide from exhaust gas and nitrogen (ammonia).

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Due to the load dynamics generally required by mobility, so-called “reformer” systems are seldom used onboard because they require complex process engineering and are rarely capable of rapid changes in performance. However, the use of reformer systems is of interest for specific applications such as in shipping due to the high energy storage density of the liquid hydrogen that can be potentially used in this scenario and the fact that ships generally run in steady operation mode. Use of this reforming technology will be further discussed below in the context of relevant applications.

Metal hydrides and chemical hydrides One method of storing hydrogen in physical form is in metal hydrides, where the hydrogen molecules are transferred onto a metal lattice via adsorption. At low temperatures, the hydrogen can be stored in the metal hydrides safely, is very compact and can be expelled in a reversible process by adding heat. Alternatively, hydrogen can be stored in chemically bonded form in what are known as chemical hydrides. Under certain reaction conditions, salt-based hydrides such as magnesium hydride are formed. This hydride can be converted to twice the amount of hydrogen through an irreversible hydrolysis reaction with water (using the hydrogen chemically bound in the water). In both scenarios, the hydrogen can be made available for use. However, there are currently no known significant developments involving the use of hydrides in vehicles. This is because of the infrastructure required to supply hydrides at refueling stations, the cost factor and the technological complexity of providing hydrogen as well as the associated limitations with regard to dynamic load requirements in the mobility sector.

Liquid organic hydrogen carriers Liquid organic hydrogen carriers (LOHC) enable hydrogen to be stored within a carrier fluid that is used in a similar way to conventional, petroleum-based fuels. The carrier fluid dibenzyltoluene, which is the subject of extensive research, enables the achievement of storage densities of up to 1.9 MWh/m3 (related to lower heating value of hydrogen). The storage density corresponding to the substance volume thus lies between compression at 700 bar (1.3 MWh/m3 ) and the cryogenic liquefied state (2.4 MWh/m3 ) of elemental hydrogen. LOHC technology allows for large quantities of hydrogen to be stored under ambient pressure and temperature conditions. Tank size can be easily scaled. Chemically stored hydrogen is released via a “dehydrogenation reaction” under the presence of a catalyst. For the carrier substance dibenzyltoluene, which is called perhydro-dibenzyltoluene when fully loaded with hydrogen, this reaction requires temperatures of around 300 °C and

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a heat supply that corresponds to 29 percent of the lower heating value of the released hydrogen flow. The type of heat supply has a significant influence on the energy efficiency of the process. LOHC-powered drive systems have not yet been used commercially, but there is particular interest in using LOHC as carrier materials for hydrogen supply infrastructure.

6.3

Synthetic hydrogen carriers

In addition to using hydrogen directly within the mobility sector—as fuel cells, for instance—synthetic hydrogen carriers (synfuels) enable the indirect use of hydrogen (Fig. 6.3). Synfuels are synthesized from hydrogen using chemical processes and are energy carriers that are usually liquid or can be liquefied with little effort. In contrast to pure hydrogen, synfuels are easier to handle and already have a transportation and distribution structure in place. The high volumetric energy density also opens up areas of application in which the direct use of hydrogen is not possible for technical reasons or is only possible with difficulty. In addition to hydrogen, a carbon source is required to produce synthetic hydrogen carriers; in the case of ammonia, nitrogen is required. Fig. 6.3 depicts the production process based on renewable source materials. Liquid hydrogen, ammonia, methanol and LOHC are being discussed as synthetic hydrogen carriers for the global trade of renewable energy.

Sustainable Feedstock POWER

Efficient Conversion

POWER WATER

Advanced Products

HYDROGEN

HYDROGEN

HYDROGEN CO2 / CO

FUELS METHANOL AMMONIA

Water Electrolysis

Fuel and Energy Carrier Fuels

POWER

WATER POWER Co-Electrolysis etc.

CO2 / CO METHANOL POWER

Methanol, DME, OME, Gasoline, Fischer-Tropsch Products, Jet fuel

HYDROGEN

Chemicals

CHEMICALS AMMONIA

Solvents, Polymers

CO2 AIR NITROGEN

AMMONIA

AMMONIA

Fertilizer and Energy Carrier

Air Separation Unit

Fig. 6.3 Using electricity generated from renewable sources, alongside gas separation from air if necessary, enables a range of fuels to be produced for potential use in various drive types. (Fraunhofer ISE)

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6.3.1 Requirements for synfuels The question of the most suitable fuel is still being explored. Criteria for evaluating a synthetic fuel include production and logistics costs, the total amount of CO2 emissions over its life cycle, and the environmental impact of the fuel and its toxicity. A further key criterion is compatibility with existing technology and infrastructure. Technology readiness level (TRL) represents another important criterion since CO2 emissions must be reduced as quickly as possible. The production costs for synfuels have been investigated in several scientific studies. Due to the numerous influencing factors and different hypotheses, an objective comparison is difficult. Electricity production costs, which have a significant influence on production costs, exhibit particularly large fluctuations depending on the place of production. Furthermore, a distinction must be made between CO2 sources. Although separation from industrial emissions is comparatively inexpensive, direct separation from air leads to disproportionately higher CO2 production costs. Different synthesis routes also exist for the production of synfuels, which can have a noticeable impact on production costs. To assess the total greenhouse gas emission of synfuels, well-to-wheel analysis is required for estimating fuel production (well-to-tank) and fuel usage (tank-towheel). Current EU regulations primarily take into account tank-to-wheel emissions. From this perspective, preference is given to all carbon-free fuels, (e.g., hydrogen or ammonia), while the combustion of carbon-based fuels such as methanol or Fischer-Tropsch fuels is accompanied by CO2 emissions. However, it does not take into account that well-to-tank emissions from renewable, synthetic, carbonbased fuels using CO2 from air separation or from unavoidable CO2 sources could be used to at least partially compensate tank-to-wheel emissions.

6.3.2 Types of synthetic fuels The synthetic fuels with the highest potential are methanol, dimethyl ether (DME), oxymethylene ether (OME), ammonia and Fischer-Tropsch fuels as well as synthetic methane. These are presented in greater detail below.

Methanol Methanol is a liquid energy carrier with a high energy density of 5 MWh/m3 and can thus be distributed in a similar way to conventional fuels. This offers a major

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advantage over gaseous fuels. Due to its high enthalpy of evaporation and antiknock properties, methanol is viewed as a substitute fuel for gasoline engines. Only slight adjustments to internal combustion engines are necessary for its use. Using methanol in compression-ignition engines is in principle possible but requires significant modification. Methanol can be synthesized under increased pressure directly from CO2 and hydrogen and is therefore highly efficient in terms of production. The toxicity of methanol is often cited as a reason against its adoption; however, it is not harmful to the environment.

Ethanol and higher alcohols Similar to methanol, ethanol can be produced from renewable resources. Brazil has an extensive refueling station network that provides ethanol for use in passenger cars. Higher alcohols such as propylene glycol can also be produced from renewable sources. In contrast to all other energy carriers discussed here, ethanol is completely non-toxic and is not flammable when mixed with water.

Dimethyl ether There is intense discussion on the use of dimethyl ether (DME) as a diesel substitute. A considerable advantage offered by DME is the absence of bonds between carbon atoms within the molecule, which results in almost soot-free combustion. This offers the additional advantage that DME engines can be operated with a higher level of exhaust gas recirculation in order to reduce NOx emissions. DME has a higher cetane number than diesel, which enables an optimization of diesel engines. Due to the presence of oxygen in the molecule, the energy density of DME is lower than that of conventional diesel (Table 6.1). Differences in the physical properties of DME necessitate technical adjustments to the tank and injection systems of DME vehicles. Due to its low boiling temper-

Table 6.1 Comparison of the physical properties of DME and conventional diesel Molecular formula Oxygen content Density Calorific value Cetane number Kinematic viscosity (40 °C) Boiling temperature

[–] [wt-%] [kg/l] [MJ/kg] [–] [mm2 /s] [°C]

Diesel C14 H30 3 percent). This is also reflected in the slight shift toward low-temperature heating systems (with maximum flow temperatures of less than 50 °C), into which renewable energies can be integrated more easily and efficiently. High-temperature heating systems (with inlet temperatures above 50 °C) can still be found in 77 percent of all buildings. Heating systems based exclusively on hydrogen do not currently have a statistically measurable market share in Germany. Around 5000 fuel cell heating systems with integrated natural gas reformers were produced in 2020, which amounts to 0.4 percent of all heat generators installed [10]. At this point, it is worth taking a look at Japan, where around 360,000 fuel cells were installed by mid-2020 and where small fuel cell systems are an important part of the national energy strategy [11].

7.3

Heat generators—Decentralized solutions

7.3 7.3.1

157

Heat generators—Decentralized solutions Hydrogen boilers

Today, gas boilers are by far the most widespread form of heat generator in existing buildings. The production and installation costs of these are low, and their use is well established in the plumbing and heating trade. The heating industry has reacted to the emerging availability of affordable hydrogen by further developing gas boiler technology. For example, some manufacturers are already offering heating systems for standalone grids that can only be operated with hydrogen, or that can be gradually converted from natural gas to 100 percent hydrogen operation. Currently, hydrogen-compatible gas boilers are being studied in various field trials to examine their suitability for practical use. At Bosch, the first prototypes of an H2 boiler with a rated heat output of 30 kW have been running on test stands since 2017. Since September 2020, BDR Thermea Group’s first field test devices have been operated with 100 percent hydrogen in a single-family home in the United Kingdom. A field test in the Netherlands started in late November 2020 [12]. In a scenario where hydrogen is widely used in gas-fired boilers, converting the existing infrastructure would be a major challenge—unlike in the case of conversion from town gas to natural gas, far more than just the nozzle insert would have to be replaced. One approach is to use H2-ready devices—these come prepared for conversion, which can be carried out within one to two hours [13–15].

7.3.2

Fuel cells for CHP

In contrast to hydrogen boilers, the aim in using fuel cells to supply energy to buildings is to simultaneously provide electricity and heating. Together with heat Table 7.1 Gas boilers and components for operation with hydrogen (03/2021, selection) Manufacturer

Services

Nitrogen oxides Hybrid capability (NOx) BDR Thermea Group Up to 28 kW for heating < 10. . . 20 mg/kWh Pure hydrogen (Remeha, Brötje) and hot water operation Bosch ThermotechUp to 30 kW for heating Conversion to H2 nology and hot water in one hour ebm-papst Gas-air composite For use with system 100% hydrogen Viessmann 3.5 to 30 kW for heating/ < 20 mg/kWh Only burner needs 35 kW for hot water to be replaced

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A Gas condensing boiler to cover peak loads B Drinking water storage C Stainless steel Inox-Radial heat exchanger D MatriX cylinder burner with combination gas valve E Regulator to adapt to atmospheric conditions F Hydraulic unit G Hot water buffer storage H Heating coil for water heating K Cartridge for deionized water L Siphon M Reformer N Electricity meters for CHP P Fuel cell stack Q Inverter

Fig. 7.6 Cross section of a fuel cell heater (Viessmann)

and power storage systems, fuel cells can benefit the energy system by enabling sector coupling (Fig. 7.6). Systems based on polymer electrolyte membrane fuel cells (PEMFCs) and solid oxide fuel cells (SOFCs) are available on the German market as systems with an integrated unit for natural gas reforming. They usually have power ratings of up to one kilowatt and are designed to cover some of the base load. PEMFCs are low-temperature fuel cells that operate at temperatures below 100 °C. One of the challenges associated with using PEMFCs is that catalysts are required to ensure the electrochemical reaction occurs at a sufficient speed at lower temperatures. In terms of materials, the highly acidic nature of the membrane (comparable to sulfuric acid) requires the use of precious metal catalysts such as platinum or platinum alloys. One of the main objectives in developing PEMFCs is to reduce the quantity of catalyst required and the associated costs. When their power outputs range between a few watts and approx. 300 kWe , PEMFCs are economically viable. When using waste heat, it is technically possible to achieve flow temperatures of 75 °C, which are then suitable for supplying heating systems. The efficiency of the electrical cell is about 58 percent, while the efficiency of electrical systems in the kW range is between 32 and 40 percent. An alternative to PEMFCs in stationary applications is solid oxide fuel cells (SOFCs). These use a ceramic-based electrolyte and function at operating temper-

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atures up to approx. 1000 °C. Its advantages include its simple design (for example, the natural gas can be reformed directly in the cell), a long service life and a high cell efficiency of around 65 percent, as well as electrical system efficiency of up to 55 percent. For systems designed for domestic energy generation, electrical system efficiencies of 35 to 40 percent are expected; these could reach up to 50 percent during part-load operation. The disadvantage of using SOFCs is their high operating temperatures, which cause long start-up and shut-down times and thus lower modulation capacity [16].

7.4

Hydrogen in urban districts

Today, district heating is already making an important contribution to the heating supply, covering around 14 percent of all homes. Increasing the current share of renewable energies from the 18 percent seen in 2020 can be achieved primarily through switching to cogeneration based on fossil fuels. In addition to large heat pumps and biogas, the use of hydrogen can make a large contribution here. Pilot projects for using hydrogen to supply energy are currently being carried out at various locations. In these integrated systems, not only is hydrogen used to supply energy to buildings, but also to provide mobility, e.g. to power the vehicles at a waste management company. Integrating hydrogen at the district level can create benefits at a system level, as the heat generated through the electrolysis of hydrogen can be effectively used by the pipeline-based heating supply. These combined power units have higher power rating classes than individual building supply models, which results in lower costs. The suburb of Weitmar in the city of Bochum, which has 1540 apartments from the mid-20th century, is set to become an innovative example of how to supply energy in urban areas in an environmentally friendly, economical way [17]. A key component of the concept is a technical center that will supply 81 residential units using various innovative energy technologies (Fig. 7.7). These include an electrolyzer for the production of hydrogen from electricity, fuel cells and heat pumps. As a result, 60 percent of the adjacent buildings and households will be supplied with locally generated heat that does not produce harmful CO2 emissions. Some 25 percent of the electricity required will be generated locally using photovoltaic systems on the roofs of the houses. This pilot project is being carried out by Vonovia together with the Open District Hub, a research initiative led by several Fraunhofer institutes that involves 14 research institutes, technology companies and real estate companies.

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Fig. 7.7 Energy system concept for the suburb of Bochum-Weitmar. (T. Hofmann, Vonovia)

7.5

Hydrogen in gas networks—Blending and conversion

The availability of a gas network infrastructure is of central importance when it comes to using hydrogen to supply energy to buildings. The three main approaches here are mixing hydrogen into natural gas, converting existing infrastructure and constructing new gas networks for the transportation and distribution of hydrogen. Gas networks are comprised of the infrastructures for long-distance transportation of gases (the “transportation network”) and the local distribution to end customers (the “distribution network”). The long-distance pipelines are operated at up to 100 bar, while the excess pressure in the distribution network is several orders of magnitude lower, ranging from 20 to 50 mbar. Another option under discussion is the methanation of hydrogen with carbon dioxide to produce synthetic methane—this would not require any changes to the gas network. This option is not considered in detail here, since it would also require additional CO2 infrastructure, and the efficiency levels of the chain would be even lower [18].

7.5.1

Blending hydrogen depending on natural gas origin

Hydrogen can be fed into grids as an additive gas. Additive gases are gas mixtures which differ significantly from the base gas (primarily natural gas) in terms of composition and combustion properties. A limited amount can be added to the base gas. The amount to be added is determined according to what combustion behavior is required [19].

7.5 Hydrogen in gas networks—Blending and conversion

161

Fig. 7.8 Change in the gas properties (HS, WS, d) as a function of the H2 concentration for three different natural gases, taking into account the limit values according to G 260 (as at 2013). (Own graph based on [19–21])

The Wobbe index is of particular importance in the area of grid management, as it indicates the characteristic value for the interchangeability of gases (with regard to the heat load of the gas appliances). “When hydrogen is added to the publicly accessible network, it must always be taken into account that the limits for relative density, higher heating value and Wobbe index defined in G 260 must be observed” [20]. The technical rule G 260 “Gas Quality” published by the German Technical and Scientific Association for Gas and Water (DVGW) defines, among other things, the requirements for the quality of fuel gases in the public gas supply. Fig. 7.8 shows the change in the gas quality properties for three natural gases (“Holland-L,” “North Sea-H” and “Russia-H”) depending on the H2 concentration. It can be seen that at an H2 concentration of 20 percent, all three of these natural gases are below the lower limit of the relative density. If the relative density range falls below the lower limit due to the blending of greater quantities of hydrogen,

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case-by-case assessments are required in accordance with G 260. This means that even combustion gas mixtures containing H2 that fall below the lower limit of the relative density could potentially also be used. However, further restrictions prevent the blending of 20 percent H2 throughout all network sections. The H2 tolerance is being tested for 23 vol% in current gas appliances. However, this test does not allow any conclusions to be made regarding the long-term suitability of the appliances for H2 -rich gases [5]. An additional aspect to consider in relation to directly feeding in hydrogen is the use of natural gas as a fuel. It is stipulated here that as required by current standards, a maximum hydrogen concentration of 2 vol% must not be exceeded in local distribution networks in which natural gas filling stations are located [22]. Requirements for the knock resistance of the fuel gas mixture in gasoline engines, e.g., for combustion in CHPs, cause further restrictions.

7.5.2

Converting the natural gas network to 100 percent hydrogen

With a view to climate protection, a significantly more important question is whether existing natural gas networks can be converted into pure H2 networks—and how much this will cost—or whether a separate infrastructure for hydrogen can be set up. The Vereinigung der Fernleitungsnetzbetreiber Gas e. V. (Association of Transmission System Operators for Gas) has created a “Visionary H2 network” design [23]. This would involve converting 90 percent of the existing natural gas transportation lines (which often consist of several parallel lines along one route) to hydrogen lines. This could be possible if the gas demand, especially in the building sector, decreases in the medium term, freeing up capacity in the pipelines. The total pipeline length is approx. 5900 km. Only about 600 km of this would have to be built as new H2 pipelines in order to make two transportation infrastructures for natural gas (or methane-rich gases in the second family of gases) and hydrogen available in Germany in the medium term. Cavern storage facilities could be connected to support the H2 network. Converting the gas distribution networks to operate with pure hydrogen is expected to involve costs in the range of 3.1 to 6.2 billion euros up to 2050. The need to decommission networks will increase at the distribution network level, due in particular to a decline in consumption in the building sector. The costs involved with this decommissioning will range from 3.1 to 17.2 billion euros. The reduction in consumption will also lead to rising operating costs at the distribution network level (up to a factor of 2.5) [24].

7.6 Cost and efficiency of a hydrogen-based decentralized heating supply

163

The conversion of distribution networks to hydrogen can only be carried out section by section. In the long term, if resources are scarce in the HVAC sector, the existing gas boilers and heaters will have to be replaced with devices that can quickly handle this conversion process. Consistent strategies for managing the conversion are still to be developed.

7.6

Cost and efficiency of a hydrogen-based decentralized heating supply

The costs of the prospective use of hydrogen in the decentralized supply of energy to buildings are shown below. 2030 has been chosen as the reference year. Cost comparisons, in particular over a time span of 10 years for investments and of up to 30 years for operations, involve a high degree of uncertainty and are therefore only to be considered as indicative. On this basis, Meyer et al. have carried out various comparison calculations. These assumptions, as well as those concerning the effects of demand and operations on costs, also include estimates of the uncertainty involved. These are also documented in Meyer et al. [25] and shown in the results using the “whiskers” (vertical black lines) [26, 27]. The assumptions regarding the underlying investment costs in 2030 are derived from a combination of the input parameters of the energy system model REMod-D devised by Fraunhofer ISE and the current heating cost comparison by the German Association of Energy and Water Industries (BDEW) [25]. As taxes, levies and subsidies are constantly changing, these have not been included in the following comparison for the time being. Details of the selected assumptions with regard to price increases, interest rates and estimated costs for heat generators, electric vehicles, transportation, network expansion, storage and fuel costs are documented in Meyer et al. [25]. The basis for the comparison are the annual costs for providing heat in a typical single-family to two-family home with 150 m2 of living space. The comparison only considers decentralized supply options that are compatible with the goal of making the building stock climate-neutral. This means that with the appropriate conditions, such as completely carbon-free power generation, the buildings do not release greenhouse gas emissions. The compared supply variants are an electric air-to-water heat pump (included for reference purposes), a hydrogen boiler and a hydrogen fuel cell. The origin of the hydrogen (Germany or the Middle East and North Africa (MENA)) as well as the energy standard of the buildings are varied as further parameters in the study. The efficiency of electrolysis, its costs and renewable electricity production costs in North Africa are assumed by Hank et al.

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Fig. 7.9 Comparison of the energy required to provide heat using three renewable heating technologies: a heat pump, an H2 boiler and a fuel cell

[28]. Thus, it is possible to expect a potential import cost for liquid hydrogen of approx. 12.5 ct/kWhLHV in 2030. This parameter, which can sometimes be crucial for analyzing economic viability, therefore falls within the range (albeit at the upper end) that is used in other studies, such as that of Frontier Economics for FNB Gas, which predicts hydrogen import prices in 2030 of 8.6 to 12 ct/kWh [29]. If additional methanation were performed, the import costs would be approximately 2.0 ct/kWhLHV higher. This is more than the expected range of the costs for converting the gas network to a hydrogen network, which according to [18] would be between 1.0 and 1.9 ct/kWhLHV . A thermal output of 9 kW is assumed for a new building built in the present day with an annual heat requirement of 60 kWh/m2 ; for a new building with a heat requirement of 150 kWh/m2 p. a., a thermal output of 16 kW is assumed. Purely in terms of energy efficiency, the compared systems are very different. Heat pumps are more efficient than hydrogen boilers or fuel cells by a factor of 3 to 5—even when used in a non-renovated building (Fig. 7.9). While renewable energy can be used locally, when hydrogen is used, conversion losses occur during electrolysis or liquefaction for transportation. However, this does not take into account direct losses during storage and losses that may arise from additional conversion steps involved with storage. If these losses are considered when assessing the different storage capacities of electricity and hydrogen, they are comparable in terms of efficiency [29].

7.6 Cost and efficiency of a hydrogen-based decentralized heating supply

165

Fig. 7.10 Comparison of the annual costs of different heat generators in a single building (heat requirement 60 kWh/m2 p. a.), reference year 2030. Taxes, levies and subsidies are not taken into account,

The differences in the annual costs of the systems are not particularly significant. Here, too, the direct use of renewable electricity appears profitable. Due to the significantly lower investment costs for gas boilers and the lower transportation costs per kWhth in the distribution network (when compared to electricity per kWhel ), the disadvantages of the H2 heat generators in terms of efficiency can be partially offset, and are clearly within the margin of uncertainty (Fig. 7.10). The difference in costs is more pronounced when it comes to non-renovated buildings. It is true that the efficiency of heat pumps is reduced at higher flow temperatures, which are needed to heat older buildings. However, lower shares of demand for hot water and a higher relative share of consumption costs have the opposite effect for existing buildings. Due to their longer service lives and the associated higher consumption costs, fuel cell solutions are less viable in non-renovated

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Fig. 7.11 Comparison of the annual costs of different heat generators in a non-renovated building (heat requirement: 150 kWh/m2 p. a.), reference year 2030. Taxes, levies and subsidies are not taken into account

buildings than in new buildings. However, they are also subject to a particularly high degree of uncertainty, as it is to be expected that it will take some time for all parties to familiarize themselves with the new systems, and they require a large quantity of fuel. Revenue from electricity production cannot compensate for this effect, particularly if only revenues that can be achieved on the electricity market (excluding feed-in tariffs) are assumed (Fig. 7.11). Currently, the various energy sources are treated very differently in Germany when it comes to levies, taxes and revenue. If current regulations are included in the cost analysis (such as levies, energy/electricity/sales taxes and feed-in tariffs), hydrogen-based technologies will become comparatively cheaper; however, their costs will still exceed those associated with the direct use of electricity. Fuel cells in particular benefit from the current feed-in costs for combined heat and power systems.

References

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References 1. Götzberger A., Stahl W., Voss K. (1997): Das energieautarke Solarhaus (Self-sufficient solar house). Verlag C. F. Müller, Heidelberg, 146 p. 2. Stahl W., Voss K., Goetzberger A. (1993): The self-sufficient solar house in Freiburg—Results of 3 years of operation. Solar Energy 58 (1–3), 17–23 3. Ueckerdt F. et al. (2021): ARIADNE brief: Durchstarten trotz Unsicherheiten— Eckpunkte einer anpassungsfähigen Wasserstoffstrategie (Getting started despite uncertainties—Cornerstones of an adaptable hydrogen strategy). https://ariadneprojekt.de/ publikation/eckpunkte-einer-anpassungsfaehigen-wasserstoffstrategie, last viewed on December 14, 2021 4. Fraunhofer Institute for Energy Economics and Energy System Technology (2019): Entwicklung der Gebäudewärme und Rückkopplung mit dem Energiesystem in 95% THG-Klimazielszenarien: Teilbericht (Development of building heat and feedback to the energy system in 95% greenhouse gas climate target scenarios: Interim report). https://www.iee.fraunhofer.de/content/dam/iee/energiesystemtechnik/de/Dokumente/ Veroeffentlichungen/2019/2019_Feb_Bericht_Fraunhofer_IEE_-_Transformation_ Waerme_2030_2050.pdf , last viewed on November 11, 2021 5. German Technical and Scientific Association for Gas and Water (DVGW) (2019): DVGW-Regeln für klimafreundliche Energieinfrastruktur: Mehr Wasserstoff technisch sicher verankern (DVGW rules for climate-friendly energy infrastructure: establishing a secure foothold for hydrogen technology) 6. Destatis (2017): Gebäude und Wohnungen—Bestand an Wohnungen und Wohngebäuden, Bauabgang von Wohnungen und Wohngebäuden (Buildings and apartments—Existing stock of apartments and residential buildings, demolition of apartments and residential buildings). Federal Statistical Office. Wiesbaden. https://www.destatis.de/DE/Publikationen/Thematisch/Bauen/Wohnsituation/Bestand/ Wohnungen2050300167005.xlsx, last viewed on March 26, 2018 7. Cischinsky H., Diefenbach N. (2018): Datenerhebung Wohngebäudebestand 2016—Datenerhebung zu den energetischen Merkmalen und Modernisierungsraten im deutschen und hessischen Wohngebäudebestand (Data collection of residential building stock in 2016—Data collection on the energy characteristics and modernization rates in the existing residential building stock in Germany and Hesse). IWU, Darmstadt, 179 p. 8. Directive (EU) 2018/844 of the European Parliament and of the Council of May 30, 2018 amending Directive 2010/31/EU on the energy performance of buildings and Directive 2012/27/EU on energy efficiency. https://eur-lex.europa.eu/legal-content/DE/TXT/ PDF/?uri=CELEX:32018L0844, last viewed on November 11, 2021 9. Bundesverband Wärmepumpen: Positives Signal für den Klimaschutz: 40 Prozent Wachstum bei Wärmepumpen (Federal Association of Heat Pumps: Positive signs for climate protection: 40 percent growth in heat pumps). Press release, January 19, 2021. https://www.waermepumpe.de/presse/pressemitteilungen/details/positivessignal-fuer-den-klimaschutz-40-prozent-wachstum-bei-waermepumpen, last viewed on April 6, 2021 10. Deutscher Bundestag (2021): Kleine Anfrage von der Fraktion BÜNDNIS90/DIE GRÜNEN Betr.: Wirksamkeit der Fördermittel im Gebäudebereich für den Klimaschutz

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(Question from Alliance 90/The Greens re.: effectiveness of funding in the building sector for climate protection). German Bundestag printed document 19/25728 Morita S.: Panasonic Contribution to Future Hydrogen Society. Lecture on December 4, 2020. https://www.bdi.fr/wp-content/uploads/2020/12/201204_PanasonicHydrogen-Activity-FV.pdf, last viewed on November 11, 2021 BDR Thermea Group (2021): BDR Thermea joins pioneering test of hydrogen energy in Germany. Press release. https://www.bdrthermeagroup.com/en/stories/bdr-thermeajoins-pioneering-test-of-hydrogen-energy-in-germany, last viewed on April 6, 2021 Robert Bosch GmbH: Der Energiewende einen Schritt näher—Bosch präsentiert Wasserstoff-Heizkessel für Wohngebäude (One step closer to the energy transition—Bosch presents hydrogen boiler for residential buildings). Press release, November 5, 2020. https://www.bosch-presse.de/pressportal/de/de/der-energiewende-einenschritt-naeher-220800.html, last viewed on November 11, 2021 Viessmann Climate Solutions SE: Viessmann entwickelt Lösungen für das klimaneutrale Heizen mit Wasserstoff (Viessmann develops solutions for climate-friendly heating with hydrogen). https://www.viessmann.de/de/wohngebaeude/klimaneutral-heizen-mitwasserstoff.html, last viewed on April 6, 2021 Schwalme J. (2020): Wasserstoff als Brennstoff für Heizthermen (Hydrogen as fuel for heating systems). Moderne Gebäudetechnik 9/2020. https://www.tga-praxis.de/sites/ default/files/public/data-fachartikel/MGT_2020_09_Wasserstoff-als-Brennstoff-_fuerHeizthermen_23-25.pdf, last viewed on November 11, 2021 ASUE Arbeitsgemeinschaft für sparsamen und umweltfreundlichen Energieverbrauch e. V. (Association for the Efficient and Environmentally Friendly Use of Energy) (2019): Brennstoffzellen für die Hausenergieversorgung. Funktionsweise, Entwicklung und Marktübersicht (Fuel cells for domestic energy supply. Operation, development and market overview). https://asue.de/sites/default/files/asue/themen/brennstoffzellen/2016/ broschueren/05_03_16_asue_brennstoffzellen_hausenergieversorgung.pdf, last viewed on November 11, 2021 Vonovia: Vonovia entwickelt Bochum-Weitmar zum Innovationsquartier für Klimaschutz (Vonovia turns suburb of Weitmar in Bochum into a center of innovation for climate protection). Press release, January 20, 2020. https://presse.vonovia.de/de-de/ aktuelles/200123-innovationsquartier-bochum-weitmar, last viewed on April 25, 2021 Fraunhofer Institute for Energy Economics and Energy System Technology (2020): Wasserstoff im zukünftigen Energiesystem: Fokus Gebäudewärme (Hydrogen in the energy system of the future: Focus on heating in buildings), 46 p. German Technical and Scientific Association for Gas and Water (DVGW) (2013): Technical Rule—Code of Practice: DVGW G 260 (A) Gas- und Wärme-Institut Essen e. V. (Gas and Heating Institute Essen) (2017): Untersuchung der Auswirkung von Wasserstoff-Zumischung ins Erdgasnetz auf industrielle Feuerungsprozesse in thermoprozesstechnischen Anlagen (Study of the impact of blending hydrogen into the natural gas network on industrial combustion processes in thermal processing plants). Final report, 121 p. Müller-Syring G. et al. (2011): Power-to-Gas: Entwicklung von Anlagenkonzepten im Rahmen der DVGW-Innovationsoffensive (Power-to-gas: Development of plant concepts as part of the DVGW innovation program). GWF—Gas—Erdgas 11/2011

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22. German Technical and Scientific Association for Gas and Water (DVGW) (2014): Wasserstofftoleranz der Erdgasinfrastruktur inklusive aller assoziierten Anlagen (Tolerance of hydrogen in the natural gas infrastructure including all associated systems): Final report 23. Vereinigung der Fernleitungsnetzbetreiber Gas e. V. (Association of German Gas Transmission System Operators): Fernleitungsnetzbetreiber veröffentlichen Karte für visionäres Wasserstoffnetz (H2-Netz) (Transmission system operators publish map for visionary hydrogen network (H2 network)). https://fnb-gas.de/news/ fernleitungsnetzbetreiber-veroeffentlichen-karte-fuer-visionaeres-wasserstoffnetz/, last viewed on April 20, 2020 24. Federal Environment Agency (2019): Roadmap Gas für die Energiewende: Nachhaltiger Klimabeitrag des Gassektors (Gas roadmap for the energy transition: Sustainable contribution to climate protection by the gas sector) 25. Meyer R., Herkel, S., Kost C. (2021): Ariadne analysis: Die Rolle von Wasserstoff im Gebäudesektor: Vergleich technischer Möglichkeiten und Kosten defossilisierter Optionen der Wärmeerzeugung (The role of hydrogen in the building sector: comparison of technical possibilities and the costs of options for defossilized heat generation). 49 p. 26. Fraunhofer Institute for Solar Energy Systems ISE (2020): Wege zu einem klimaneutralen Energiesystem—Die deutsche Energiewende im Kontext gesellschaftlicher Verhaltensweisen (Paths to a climate-neutral energy system—The German energy transition in the context of social behavior). 66 p. 27. BDEW Bundesverband der Energie- und Wasserwirtschaft e. V. (German Association of Energy and Water Industries) (2021): BDEW-Heizkostenvergleich Altbau 2021 (BDEW heating cost comparison of old buildings, 2021) 28. Hank C. et al. (2021): Energy efficiency and economic assessment of imported energy carriers based on renewable electricity. Sustainable Energy Fuels 2021 (4), 2256–2273 29. Frontier Economics Ltd. (ed.) (2021): Der Wert von Wasserstoff im Wärmemarkt— Analyse unter Betrachtung verschiedener Heiztechnologien mit Fokus auf Wasserstoffbrennwertkessel und elektrische Wärmepumpe. Studie für FNB Gas 08/21 (The value of hydrogen in the heat market—Analysis considering different heating technologies with a focus on hydrogen condensing boilers and electric heat pump. Study for FNB Gas, 08/2021)

8

Hydrogen infrastructures — Networks and storage

Ulrike Herrmann  Natalia Pieton  Benjamin Pfluger  Katharina Alms Fraunhofer Research Institution for Energy Infrastructures and Geothermal Systems IEG Tanja Manuela Kneiske Fraunhofer Institute for Energy Economics and Energy System Technology IEE Christopher Voglstätter Fraunhofer Institute for Solar Energy Systems ISE Bernhard Klaassen Fraunhofer Institute for Algorithms and Scientific Computing SCAI Robert Burlacu  Alexander Martin Fraunhofer Institute for Integrated Circuits IIS Björn Ole Gerloff Fraunhofer Institute for Microstructure of Materials and Systems IMWS Abstract

Hydrogen is considered to be an important option for effective sector coupling. It could create a supply of (potentially) greenhouse-gas-neutral energy for applications for which renewable energy and other options are not suitable for a variety of reasons. However, hydrogen can only be substantially used if the appropriate infrastructure is in place. © Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_8

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This chapter will outline the options and challenges that come with establishing this infrastructure. It will examine the ways that it will be necessary to change and expand the transportation and distribution elements of the network, and discuss different storage options.

8.1

Introduction

8.1.1 Hydrogen infrastructures as the foundation for sector coupling Hydrogen is considered to present an important opportunity for sector coupling. It could create a supply of (potentially) greenhouse-gas-neutral energy for applications where renewable energy and other options are not suitable for a variety of reasons. However, significant use of hydrogen can only be achieved if the appropriate infrastructure is in place. Each sector faces its own challenges here. For example, filling station infrastructure needs to be expanded if hydrogen is to enter the transportation sector. Alongside Japan and the USA, Germany is numbered among the countries with the most hydrogen refueling stations worldwide [1]. As of spring 2021, the total number of hydrogen refueling stations in operation stands at 91 [2]. The state of the art of hydrogen refueling stations will be described in Chap. 6. In heating for buildings, hydrogen is currently only used when green electrolytic hydrogen is blended in the natural gas network (see Sect. 8.2). This is an option for transporting hydrogen that could act as an initial and transitional solution for reducing emissions in the heating supply sector, without requiring any major investments; however, the positive effects on the climate and the potential for expansion are extremely limited. In order to completely defossilize heating in buildings, in addition to options such as district heating or heat pumps, the possibility of switching the gas distribution networks to hydrogen in the future is under consideration. In Germany, this switch is still in the very early testing phase; this will be briefly explained in Sect. 8.2. As it stands, hydrogen is a very important raw material in the industrial sector, and there are already some privately operated hydrogen transportation networks. However, fossil hydrogen produced from natural gas and hydrogen that occurs as a by-product in other processes are most often used in this sector. Nevertheless, these networks in industrial clusters are relevant as a starting point for establishing a general public hydrogen backbone network, as the defossilization of the industrial sector will create substantial demand for green hydrogen [3].

8.1

Introduction

8.1.2

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Pure hydrogen networks

In Germany, three main industrial clusters have been formed that privately operate hydrogen pipelines. The majority of the transported hydrogen comes from the sector coupling processes in refineries and industries, or it is produced as a natural gas through steam reforming. To date, there are no pure hydrogen networks that are publicly accessible. Fig. 8.1 shows the industrial cluster in the Ruhr region. At a length of 240 km, it is the largest connected hydrogen network in Germany, and is operated by the company Air Liquide. The Ruhr region has a high density of industrial facilities for producing gray hydrogen, with overall annual production of approx. 20 TWh [4]. Air Liquide also operates Europe’s largest hydrogen distribution center for filling containers for transportation, which is also located in the Ruhr region. The main hydrogen consumers here are refineries and chemical parks. In the project tkH2Steel, which is funded under the BMBF living laboratory scheme, the company thyssenkrupp is also using hydrogen to work toward gradually defossilizing steel production and is planning to connect to Air Liquide’s hydrogen network [5].

Fig. 8.1 Industrial cluster in the Ruhr region with Air Liquide’s pipeline. (FfE Forschungsgesellschaft für Energiewirtschaft mbH)

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Fig. 8.2 Industrial cluster in central Germany with Linde AG’s pipeline. (FfE Forschungsgesellschaft für Energiewirtschaft mbH)

Another large hydrogen cluster, shown in Fig. 8.2, is located in the Central German Chemical Triangle. Linde AG operates a hydrogen pipeline in this area that is 150 km in length. The pipeline connects chemical sites such as Bitterfeld and Leuna [4]. The gray hydrogen produced by Linde AG is used by the chemical industry, in refineries and for ammonia production. The Energy Park Bad Lauchstädt living laboratory, funded by the German Federal Ministry for Economic Affairs and Climate Action (BMWK), will test the production of green hydrogen in the double-digit gigawatt range using an electrolyzer. As part of this project, a natural gas pipeline will be converted to extend the hydrogen network by 20 km [3, 6]. In the Lower Elbe region, there is a hydrogen pipeline stretching 30 km between Brunsbüttel and Heide. It is operated by the Heide GmbH refinery; as a stakeholder in the cluster, Heide GmbH is also involved in the Westküste100 living laboratory funded by the BMWK. As part of this initiative, green hydrogen will be produced using offshore wind power and used for purposes such as producing synthetic kerosene. The existing hydrogen network will also be expanded [7]. The Emsland region is also a focal point for testing large-scale electrolyzers, and for developing a hydrogen network by building new pipelines and converting existing ones. Among other projects, the GET H2 Nukleus project is particu-

8.2

Construction of hydrogen network infrastructure

175

Fig. 8.3 Industrial cluster in Lower Elbe/Weser/Ems with the Heide refinery’s pipeline. (FfE Forschungsgesellschaft für Energiewirtschaft mbH)

larly noteworthy here. This project aims to create Germany’s first pure hydrogen network with non-discriminatory access. The plan is to create a 130 km hydrogen pipeline that will connect the chemical sites and refineries in Lingen and Gelsenkirchen [8]. To achieve this, as well as building new sections of pipeline, existing natural gas pipelines will be converted. The Lower Elbe and Emsland regions can be joined to form the Lower Elbe/Weser/Ems hydrogen cluster shown in Fig. 8.3, which has a high generation capacity for renewable energies, particularly offshore wind farms, as well as a good gas network infrastructure and the possibility of storing gas underground (see Sect. 8.6); this means this region unites two advantageous features for the construction of a hydrogen infrastructure [4].

8.2 Construction of hydrogen network infrastructure This chapter will discuss different options for constructing hydrogen networks. These options are not mutually exclusive; instead, they could be used simultaneously in some instances, or used in different ways for various regions. Sect. 8.3

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will describe how individual hydrogen islands that are currently disconnected can be integrated into existing trans-regional hydrogen networks.

8.2.1

Blending hydrogen into natural gas networks

Before pure hydrogen networks become available locally, there are multiple possible alternatives for transporting hydrogen. One of these is transportation via the natural gas network, which involves blending a certain proportion of hydrogen into the natural gas flow. This option is used in many existing power-to-gas pilot plants (creating more than the plants need for their own use) [9]. It is technically possible for hydrogen consumers to separate hydrogen from the natural gas flow with the aim of obtaining pure hydrogen from the mixture; however, this has rarely been carried out to date because of the high amount of effort involved and the associated costs. The blended hydrogen is therefore mainly used as a fuel and contributes to reducing CO2 in combustion processes. Consumers of pure hydrogen that do not produce hydrogen themselves are generally supplied via containers, if they do not have access to a hydrogen network. The German transmission system operators believe that adding up to 2 vol% for facilities with highly specific requirements in industry and households will be straightforward and will not require major investment or adaptation costs [3]. In its directives, the German Technical and Scientific Association for Gas and Water e. V. sets out a maximum blending percentage of 10 vol% for suitable pipeline sections and aims to increase this to 20 vol% [10]. For chemical plants that use natural gas (e.g., reformers), changing the gas composition means that the burners must be modified, as blending in hydrogen alters combustion properties. Significant hydrogen blending is not carried out in network sections where CNG (compressed natural gas) filling stations are located. In these sections, the maximum amount of hydrogen that can be blended in is limited to 2 vol%, as higher proportions of hydrogen could damage the steel storage tanks in CNG vehicles [11]. Whether hydrogen can be blended into natural gas depends not only on its intended use, but also on the flow conditions in the relevant pipeline sections. For example, in pipes with bidirectional flow or a significantly reduced gas flow rate (mainly during the summer months), it is not possible to rule out hydrogen bubble formation, which leads to substantially increased concentration levels [3, 12]. If injecting pure hydrogen into a pipeline is not possible for these reasons, or if the amount of hydrogen blended in exceeds the permitted percentage, there is also the option of conducting hydrogen methanation in an additional process step. However, a suitable CO2 source is required for this purpose.

8.2

Construction of hydrogen network infrastructure

8.2.2

177

Transforming gas transmission networks

Although converting pipelines creates challenges in terms of pipeline materials, compressor stations and measurement technologies (see Sect. 8.3), it is estimated that the cost of converting a natural gas pipeline is 10 to 25 percent of the cost of building new hydrogen pipelines [13]. This means Europe’s well-developed natural gas network can be used as the foundation for a European hydrogen backbone network, which will make it possible to transport hydrogen from regions with high potential for renewable energy generation in the south or on the North Sea to centralized areas of consumption. An important factor influencing the conversion of pipelines is the growth of demand for natural gas—pipeline capacities are only freed up for conversion if demand is falling. In Germany, the Grid Development Plan Gas contains specific plans for constructing a hydrogen transportation network by converting natural gas pipelines in the period between 2020 and 2030. This plan focuses on the Lower Elbe/Weser/Ems cluster and on connecting it to the cluster in the Ruhr region—firstly because there is a high demand for hydrogen in this area, and secondly because pipeline capacities are being freed up for conversion from L-gas to H-gas and the Netherlands is withdrawing from natural gas production. FNB Gas e. V. aims to establish a hydrogen network by 2030 that is 1236 km in length; it intends to develop 92 percent of this network by converting existing natural gas pipelines [3].

8.2.3 Transforming gas distribution networks The future of hydrogen networks in the transportation sector depends on converting the existing natural gas network infrastructure. The question of where the specific hydrogen routes will be built will primarily be influenced by which locations have highest demand in the future. These locations will determine the necessary generation and network structures. However, it is less clear how things will develop in the future at the distribution network level. There are numerous existing natural gas networks, and they currently supply 31.55 million people in Germany. Slightly more than one third of natural gas consumers are industrial, one third are private households and one third includes the commercial and service trade sectors [14]. Completely converting the natural gas infrastructure does not appear to be a suitable approach. Instead, it is more important to identify the processes that currently use natural gas and for which hydrogen is to be used in the future, and to determine whether there are

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more efficient and economical options here. It is therefore only possible to discuss the role of hydrogen networks in the distribution network sector in the context of alternative solutions. Generally speaking, there are three different possible approaches to defossilizing gas distribution networks:

I. Decommissioning the natural gas infrastructure in the distribution network—ruling out a future hydrogen distribution network In this scenario, for industries and modes of transportation that are not directly connected to the transmission grid, hydrogen is either produced directly on site or transported via tankers. In this context, it is assumed that the natural gas distribution networks will be decommissioned due to the decline in gas demand. This decline in demand will be caused by the heating system being switched to electric heat pumps and heating networks of Generation 4.0 and higher. However, the heating requirements of individual residential units must be significantly reduced for this conversion to be achieved. Older buildings and uninsulated buildings pose the biggest challenge here—to date, for many buildings, only gas-fired heating systems have been able to achieve the flow temperatures necessary to use the buildings’ existing heat pipes and heating appliances without making further investments and conversions. Completely removing the natural gas infrastructure, and thus completely avoiding hydrogen networks at the distribution network level, also means that gas distribution network operators will need to adopt new strategies. In the past, the regulated market meant that investing in gas infrastructure came with very little risk. The demand for gas connections has also grown in recent years, since it became apparent there will be a ban on oil heating in the near future. Decommissioning the gas networks would inevitably have dramatic economic consequences for the network operators; however, at least temporarily, there could also be a rise in costs for the remaining customers, who will then have to pay increasing network charges. The decision to decommission the gas networks must therefore be well thought-out [15]. Involving energy customers in the process of deciding for or against a certain type of heating supply also plays a significant role here and creates an uncertainty that is very difficult to predict [16]. According to a Fraunhofer IEE study, the costs of decommissioning the natural gas infrastructure are similar to the costs of converting; however, these decommissioning costs could increase by a factor of 2.5 if consumption declines [17].

8.2

Construction of hydrogen network infrastructure

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II. Switching the natural gas infrastructure to climate-neutral gases, including hydrogen If climate protection targets are to be achieved, the only way to secure the current gas network infrastructure is to switch to climate-neutral gases. In 2020, the DVGW study “H2vorOrt” described a possible way of making this switch [18]. The study laid out an eight-point agenda for creating the desired structure in 2050. First, the technical and regulatory requirements must be created. This will include integrating H2-ready components into the natural gas infrastructure and formulating standards and technical regulations. In 2030, the first regional pilot applications for hydrogen distribution networks will be put into operation, so that in 2040, entire network sections can be operating on 100 percent hydrogen. The aim is to ensure a wide-scale supply for the hydrogen distribution networks via three expansion stages, while also expanding the H2 backbone at the same time. According to a Fraunhofer IEE study, the costs of conversion will be in the range of 3.1 to 6.2 billion euros by 2050 [17]. It must be emphasized here that converting natural gas networks poses a huge logistical challenge. It is not possible to gradually increase the amount of blended hydrogen until it reaches 100 percent. There is no equipment that can run on both natural gas and hydrogen, as the combustion properties are different for each. Instead, clusters must be formed that will convert to hydrogen en masse at a specific point in time. This would need to be planned in advance, which would involve inspecting all buildings and testing all connected devices to determine the most suitable equipment to replace them. The preliminary work could necessitate upgrading network sections that are not suitable for hydrogen. A typical cluster could consist of 5000 connection points, for example. When it came time for the conversion, the cluster would have to be disconnected from the gas network. This would create a supply interruption; this should not exceed two weeks as otherwise it will not be accepted by customers, and must take place during summer so that only the hot water supply is affect by the outage. The residual gas must be completely removed (e.g., through flaring). All equipment must then be replaced. As this must be done within a limited time frame, it will require a lot of manpower. Once the new equipment is installed, the new network can be put into operation. At this time, the cluster can and must be supplied with hydrogen, while clusters that have not yet gone through the conversion continue to be supplied with natural gas. At present, there are no specific plans for how the costs of the conversion and the new equipment will be covered. As far as is currently known, converting many distribution grids to hydrogen is technically possible; however, there will be a great deal of effort associated with this, and alternatives must be compared.

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III. Tailored, regional solution that could include a limited H2 network structure A compromise can be reached based on the first two extreme scenarios, wherein the hydrogen infrastructure is specifically planned out for certain regions. This will ensure the necessary amount of green hydrogen is supplied for industrial purposes and mobility applications, and is combined with efficient integrated heating supply methods, which are mainly covered by electricity and heating networks. Finding optimum regional solutions such as this is a complex task. Methods and support tools will need to be developed to enable joint strategic planning with all stakeholders involved in a region. At present, institutes across the Fraunhofer Cluster of Excellence Integrated Energy Systems (CINES), among others, are cooperating on this. To this end, software tools to optimize individual districts (DISTRICT, [19]) are being used in combination with the technical and economic network calculation software pandapower [20] and pandapipes [21] and the gas network simulation tool MYNTS [22]. In a project together with the Stadtwerke Bamberg public utility company, it was shown in the context of the LaGarde district that overarching optimization of electricity, heating, gas and hydrogen infrastructures is a workable solution, particularly if all the energy networks are already present in an urban district [23]. An initial investigation into the joint optimization of electricity and gas network expansion has focused on the idea that in areas with older houses, the use of gasfired heat pumps can be combined with the necessary increase in electrical heat pumps in new builds. This could ease the load on the power grid and make more efficient use of the gas network infrastructure. Calculations based on publicly available data regarding buildings and the electricity and gas networks in a small town have shown that building owners and network operators in all sectors need to collaborate to evaluate costs so that an optimum economic solution can be determined [24]. However, the costs of converting to hydrogen have not yet been taken into account here. In the next three years, as part of the AnaplanPlus project, methods and software tools for automating electricity, natural gas and hydrogen network plans will be developed that will help network operators and public utility companies to make the best decisions in terms of strategically developing their integrated network infrastructures.

8.3

8.3

Transforming hydrogen islands and hydrogen valleys into connected networks 181

Transforming hydrogen islands and hydrogen valleys into connected networks

Hydrogen networks will become available in Germany from 2030 at the earliest—with some areas not getting access until 2040 [18]. Nevertheless, due to factors such as the Clean Vehicles Directive for public transportation and municipal vehicles [25] and European regulations for the industry, consumers will continue to be put under pressure to reduce emissions until then. This means the demand for low-CO2 hydrogen will continuously increase. Various marketing activation programs at the federal level (e.g., the “HyLand” project by the German Federal Ministry of Transport and Digital Infrastructure (BMVI)) and the state level (e.g., the Ministry of the Environment, Climate Protection and the Energy Sector BadenWürttemberg’s “Model region green hydrogen” project, see Fig. 8.4) are promoting the development and establishment of local or decentralized solutions for a sustainable hydrogen supply. As shown by the high number of applications for a variety of grant initiatives, these programs have been met with significant interest from regional stakeholders [26]. This means a large number of hydrogen islands will emerge in the coming years, i.e., regions that are separate and self-sufficient in terms of their hydrogen supply, and that will produce hydrogen from renewable energies, have their own regional logistics networks and have multiple regional consumers for the hydrogen produced. In this context, large international hydrogen islands and research platforms must be mentioned, such as the EU-funded Hydrogen Valley in the Groningen province in the Netherlands [27]. Due to their sizes and the very diverse external conditions affecting them, these do not need to be discussed in greater detail at this point. Other noteworthy initiatives include the Living Labs for the Energy Transition, which are aimed at hydrogen and sector coupling; these kinds of initiatives generally tend to represent important components for the model regions, particularly in terms of H2 production, and thus contribute to the proportional funding of hydrogen islands on a large scale. However, the focus hereafter will be on smaller hydrogen regions, of which there are many. In most cases, these hydrogen islands have a combination of the following elements, which are generally distributed across a city and its neighboring municipalities: 1. A conventional (i.e., natural gas-based) partially adjustable hydrogen source for a chemical company to create its own supply (e.g., the southern Upper Rhine model region) or a refinery (e.g., Ingolstadt) that serves as an option for flexibility or temporary conventional supply to the model region before the expansion of the hydrogen production capacity powered by renewable energy

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Fig. 8.4 Diagram of a model region and its components, using the example of the southern Upper Rhine region with potential consumers (blue) and existing power generation facilities (orange)

2. A dedicated electrolysis system powered by renewable energy and/or grid power 3. A source for hydrogen as a by-product, such as a chlor-alkali electrolysis process—e.g., the Rhein-Neckar hydrogen region (H2 Rivers/H2 Rhein-Neckar) 4. Transportation of gaseous hydrogen by truck (CGH2 trailers) 5. Industrial gas pipelines for hydrogen, which tend to be rather short 6. Companies that directly or indirectly use hydrogen as a raw material (e.g., Industriepark Höchst, ChemCoast, etc.)

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7. Hydrogen consumers such as trains or buses in public transportation, or municipal vehicles 8. In exceptional cases: An underground gas storage facility such as the research cavern at Bad Lauchstädt (see Sect. 8.6 for more information) Currently, these kinds of hydrogen islands are still in their setup phase. This means the expected life cycle and the path to integrating the islands into a wider network can only be approximately estimated according to what is currently known and the results of initial analyses. The following is a rough outline of a hydrogen island’s expected life cycle: 1. Initialization phase (until approx. the mid 2020s) In the early phase, a group of regional stakeholders creates a custom design for a hydrogen island. The first step is to build a decentralized hydrogen production facility (an electrolysis system with low MW power output), which supplies local consumers with sustainable hydrogen. Generally, the designs require public funding in order to reach the launch phase, although the stakeholders’ belief in their vision plays an important role. 2. Gradual expansion and development (multi-step process, end of the 2020s) The hydrogen island is extended further and the infrastructure is gradually expanded. The original field of application is expanded to include additional elements. The driving forces behind this phase are changes to regulations/laws that have already occurred or are projected, and positive experiences during the first phase. As a rule, promising indicators that value creation can be achieved at an early stage include mobility or industry applications such as acquiring additional vehicles or increasing the proportion of green hydrogen used in the industry. The typical amount of hydrogen production is increased into the doubledigit MW range. 3. Connecting individual hydrogen islands (concurrent with phase two): The next phase involves consolidating individual hydrogen islands. This is carried out either via road transportation (trailers) or via individual pipelines. Connecting regions can enable the development of various applications that will allow for the better utilization of resources. 4. Connecting to a hydrogen transportation network (from the 2030s onwards) Depending on the situation, it may be possible to connect a region to a wider hydrogen transportation network, which allows the hydrogen island to feed hydrogen in and out. This development is likely to begin in northern Germany, as this region’s wind energy offers the potential to produce large quantities of H2 energy from renewable sources. In this region, it is also possible to connect

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to the hydrogen infrastructure currently being constructed in Belgium and the Netherlands and to use geological storage facilities in the north. This includes the large ports such as Rotterdam and Hamburg. This qualitative outline emphasizes the importance of creating power lines connections from the hydrogen island to a connected infrastructure in the later stages, not least to ensure strong economic viability. By connecting to a wider pipeline network, it becomes possible to carry out open and trans-regional hydrogen trading that uses inexpensive hydrogen and involves potential geological storage options. As a result, the use of conventional hydrogen generators is being reduced or discontinued, use of green hydrogen as a raw material is increasing, and hydrogen produced as a by-product is reaching a broader customer base. However, expanding the hydrogen transportation network also means facing more intense competition; as a result, regional electrolysis systems will either have to expand (as it will then be possible to cheaply transport inexpensive hydrogen produced in the north to the south, for example) or will have to cease operations due to the increased competition in terms of price. The issues outlined in this section (e.g., the transition from the first phase to connecting to a wider network, the optimal connections within the model region, setting up a transportation system between islands at an early stage) and many issues relating to the finer details are currently the subjects of various research projects. These will significantly strengthen and influence the plan for this transformation in the coming years.

8.4 Requirements for transforming infrastructure components The natural gas network in Germany currently consists of approx. 40,000 km of pipelines and around 470,000 km of distribution networks, most of which are underground. They are made from steel or plastic (e.g., polyethylene or PVC). At present, plastic pipelines are usually limited to an operating pressure of up to 10 bar [28]; this also creates a limit at the distribution network level. When it comes to using steel to construct pipelines, it is necessary to follow the recommendations in DIN EN ISO 313837, as they apply to pipeline transportation systems in the oil and gas industry. However, older line sections in particular use steel that does not comply with this standard. Neither the materials that the standard recommends using for natural gas, nor the materials used in older line sections, have been fully tested for their suitability for transporting hydrogen. It will therefore be necessary

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Requirements for transforming infrastructure components

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to clearly classify as many materials as possible in terms of their attributes and properties, and to analyze their interactions with hydrogen. The H2-PIMS project is investigating this matter among other things and will also provide recommendations for a monitoring system [29].

8.4.1 Effects of hydrogen on materials in the pipe system It is well known that hydrogen is able to penetrate metallic lattice structures or diffuse through them, due to its extremely small particle size in the atomic state. This means hydrogen accumulates in the material, which can lead to what is known as hydrogen embrittlement. This often results in the material’s fracture toughness being reduced, and can lead to sudden material failure during use, and ultimately to leakage. Material damage often cannot be detected in advance, so the failure occurs without warning. At the same time, it is well known that the degree of embrittlement depends greatly on the hydrogen concentration and on the operating parameters of pressure and temperature in each respective case. For the materials analyzed so far, these effects have primarily been investigated using a 100% hydrogen atmosphere. To date, only a few research projects (e.g., NATURALHY [30, 31]) have studied low hydrogen concentrations or specific mixtures of natural gas and hydrogen. Moreover, the tests have mainly been carried out on new materials. Many studies within the field of materials research have examined the durability of steel when it is exposed to corrosion caused by H2 . It has been found that static stress from compressed gaseous hydrogen has no significant effect on the steel’s strength (in tensile tests) [32–38]. However, there are significant measurable effects on fracture toughness and necking; this also applies to higher quality steels [39]. In addition to the direct effects of hydrogen on the material, existing cracks in materials (e.g., due to prior damage or impurities in the welded joints) are considered to be critical, as they can lead to increased level of hydrogen diffusion into the material, and thus higher concentrations of hydrogen in certain areas within the fabric. In many materials, this leads to the cracks developing at a faster rate, and as a result, a need for appropriate monitoring tools. These, however, are not currently available. The NATURALHY project’s investigations found that axial cracks and prior plastic deformations are particularly critical issues for steel pipelines. An important influencing factor here is the stress frequency, which is determined using pressure cycles. In particular, low load frequencies that cause slow deformation processes

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have an adverse effect, increasing the likelihood of material failure occurring due to embrittlement. However, these tests have only been carried out on a few materials. The results cannot automatically be transferred to other materials and can only be applied to other operating conditions a limited extent. Aside from these challenges, some studies have also discovered positive effects. It has been shown that the presence of oxygen and carbon monoxide reduces the harmful effects of hydrogen, for example. Where necessary, this effect could be harnessed deliberately to influence the damage described above. The effects of hydrogen discussed above have mainly been identified through tests on new materials that are currently being used. However, when it comes to older materials in particular, the problem arises of hydrogen causing the material properties to deteriorate, as these older materials generally have low levels of toughness in comparison to the steels used today. This was shown in the NATURALHY project with two different types of steel of differing ages (produced before and after 1975). These factors have a long-lasting effect on the durability of materials, particularly under dynamic and cyclic loading conditions. Various studies have found that the service life of materials is reduced by between 10 percent (for 50 vol% hydrogen) and 25 percent (for 100% hydrogen). It is therefore particularly important to test older sections of pipeline for hydrogen compatibility. Several studies have tested different types of steel for their suitability and developed recommendations for ideal material property values that should be followed when transporting hydrogen. This allowed the identification of material properties that suggest a material should theoretically be suitable for transporting pure hydrogen. The materials recommended for transporting pure hydrogen based on the results partially align with the materials mentioned in DIN EN ISO 3183 [40]. These specifications could provide guidance for existing materials. However, it has been shown—through methods such as random sampling—that the older building materials often fall short of the required values. Further investigation is required to evaluate all materials used to date for their suitability for use with natural gashydrogen mixtures or pure hydrogen.

8.4.2

Consequences for the monitoring of pipe systems

As a consequence of this inconsistency in the suitability of materials, studies have concluded that a pipeline integrity management system (PIMS) would be a suitable method of monitoring pipelines for expected damage.

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The aim of a PIMS is to provide the operator of an existing natural gas transportation network with a visualization of the pipeline’s technical integrity and security. The resulting evaluations therefore form the basis for the technical and economic operation of the pipe network, and for planning renovation work and the construction of new sections of pipeline. In addition to the material studies on hydrogen, the integrity evaluation also includes information on corrosion and the resulting material erosion, or weld defects that are detected over time.

8.4.3 Effects of hydrogen on compressor systems Once the natural gas transportation infrastructure has been converted to a hydrogen infrastructure, it will be necessary to take into account the fact that the energy density of hydrogen is significantly lower (approx. 1/3 in comparison to natural gas with a high methane content) in order to transport quantities comparable to today’s volumes. The diagram in Fig. 8.5 shows the expected compression ratio when a mixture of natural gas and hydrogen is compressed. The different colored lines represent

Fig. 8.5 Compression ratio when compressing gas mixtures [41]. (Fraunhofer SCAI)

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the constant compressor capacity in each case, which is given in kJ/kg (known as the enthalpy difference). The compression ratio on the y axis shows the factor by which the outlet pressure increases in comparison to the inlet pressure. The diagram shows that the factor falls to below 1.1 when the methane content is zero percent. To achieve the standard compression ratio of a factor of 1.3, for example, three to four compressors must be connected in series for hydrogen, while the same quantity of energy from natural gas could be compressed by a factor of 1.3 using one compressor. Simply increasing the volume flow is not a suitable option, as this could destroy the compressor’s fins—at least in the case of the turbo compressors that are most commonly used. An alternative here is to use piston compressors, which are significantly more robust; however, these are less efficient when compared to turbo compressors. The first manufacturer to respond to this problem was the American firm Baker Hughes, which offers a hydrogen-ready turbo compressor that can operate with up to 100 percent H2 . Gas transportation companies will therefore need to make larger investments in compressor machinery in the future. However, it is necessary to take into consideration the fact that, when these machines are operated using natural gas, they need to be rebuilt at certain intervals.

8.5

What are the challenges and solutions involved in operating the infrastructure?

Natural gas networks have been used in Germany for over 100 years. The main challenge in using these networks lies in the interaction between the physics of the gases and the individual control decisions. It is very difficult to find a specific arrangement of components (such as compressors or slides) that is guaranteed to physically transport the gases through the pipeline. The stability of natural gas often means the network can be controlled manually. This is done on the basis of expert knowledge and using recommendations for operation produced by specific mathematical simulation and optimization models. Hydrogen pipelines only have about a quarter of the linepack (i.e., the volume of gas stored in the pipeline) of natural gas pipelines. This means hydrogen networks must be controlled in a much more dynamic way (see [42], for example). The control of the gas network will thus need to be switched from manual processes to automated, smart control. It is very likely that the new control systems will be developed based largely on algorithmic intelligence.

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What are the challenges and solutions involved in operating the infrastructure? 189

8.5.1

Data and digital twins

Controlling gas networks using smart systems requires very detailed knowledge of the network, including all its components (pipes, compressors, storage facilities, etc.). It is likely that large sections of the existing natural gas network can be repurposed or converted to transport hydrogen. As operational control needs to be taken into account when planning the construction of a hydrogen economy in Germany, having detailed information on Germany’s natural gas network will be crucial in the near future. Previous projects such as GasLib [43] and SciGRID_gas [44] have collated and published the first freely accessible collection of information on the German natural gas network. The information is very detailed in some cases, but was published with some partial modifications. This information included graphs with nodes and edges that visualize the current network (Fig. 8.6). An important task in the coming years will be to create a detailed and comprehensive digital copy of the actual components that make up the natural gas network. It has been shown that digitalizing the network is already very relevant for natural gas networks. For hydrogen networks, this is even more important, as hydrogen is significantly less stable than natural gas. A digital twin therefore needs to be developed based on actual network data that can realistically depict the technical and physical characteristics of a gas network. This can not only be used for smart control systems for the network, but also to plan the construction of a hydrogen economy in Germany.

Fig. 8.6 Digital model of the German natural gas network (center) with detailed information about a subnetwork in the Rhine-Main-Ruhr region (left) and more general information about the overall German network (right). (GasLib-40 and SciGRID_gas)

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Mathematical models

The mathematical models for gas networks are usually characterized as a mixture of non-linear and discrete integer problems. The non-linearities show the physics of the gas and are either given in algebraic form or as a system of partial or ordinary differential equations. The integers, which are mainly binary variables, model controls and decisions that do not allow continuous transition, such as switching a compressor on or off or building a pipeline, for example. It is very difficult to solve each of these problems (non-linear and integers) on their own, but when they are combined, the difficulty increases exponentially. A possible model distribution can be created using steady-state and transient gas flows. Transient models are generally more precise; however, the disadvantage of these is that they are more complex and can therefore only be used for smaller problems. At this point, it is necessary to mention the Transregio CRC 154 Mathematical Modelling, Simulation and Optimisation Using the Example of Gas Networks (spokesperson: Prof. Alexander Martin, IIS institute director), which has been running since 2014. This center aims to develop a new mathematical quality standard that incorporates different sub-topics within the field of mathematics. The advantage of steady-state models is that they are easier to work with than transient models in terms of their technical complexity. With stationary models, it is possible to address problems that are formulated across longer periods of time, where physical dynamics are of lesser importance. An example here is the problem of planning the transition phase; during this period, some sections of the existing natural gas pipelines must be used at the same time as the sections that have been newly added for hydrogen. Investments into new hydrogen pipelines and compressors are being planned for the next few decades. It is therefore sufficient to focus on a steady-state gas flow to solve the problem. A good overview of the current methodology used here can be found in [45]. However, certain problems require the gas flow to be modeled in a dynamic, transient way, meaning that they cannot be adequately solved using steady-state models. An example of this is when it comes to power-to-gas and the direct storage of gas in the network; see [46]. In this case, additional gas produced through electrolysis is fed into the grid at specific intervals and released again at a later point time. A transient model is vital to adequately depict the dynamics of the gas, and thus to determine how much the network can realistically store. Aside from a variety of transient optimization methods to control the network, e.g. [47], there are a number of different software solutions that can simulate gas flow through a pipeline or, on a larger scale, through an entire network using a transient (and thus also steady-state) simulation. The MYNTS-Gas simulator by Fraunhofer

8.6

Geological storage options

191

Fig. 8.7 Schematic aggregation of the German gas network with combined centralized optimization (center) and decentralized optimization (right) [49]

SCAI [22] and the SIMONE simulator [48] are of note here, as they are often used by network operators.

8.5.3 Decision support tools/Smart gas networks The larger a gas network is, the more difficult it is to control the entire network through one central control system. Due to the increased dynamics of hydrogen, decentralized solutions are therefore a good way of managing the rising level of complexity in the future gas network. The diagram in Fig. 8.7 shows a means of using decentralized simulation and optimization methods in the overall control of a network. Another suitable approach is to combine subnetworks to create a node in a combined overall network. A model of a central, simplified control system is then created for the combined network, which is transformed as input for the respective subnetworks. Digital twins can enable smart control of the subnetworks themselves. They can also send bidirectional information to the central control system, so that it can be adjusted if necessary.

8.6 Geological storage options The storage of hydrogen will be a key factor in carrying out the energy transition. This is because hydrogen can only provide a flexible option if it is possible to balance out the difference that arises between hydrogen demand and produc-

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tion at certain times. Although there are other options (see Sect. 8.7), geological underground storage is particularly suited to storing hydrogen in the long term. Underground storage has been used for decades in the hydrocarbon industry in Germany and worldwide to store large quantities of natural gas in the pore spaces of rocks (“pore storage”) or in salt caverns. Overall, around 24 billion cubic meters of natural gas is stored in underground storage facilities in Germany [50]. This means Germany has the fourth-largest storage capacity in the world, after the United States, Russia and Ukraine. Even before natural gas was introduced, in Germany and Europe, town gas was produced that sometimes consisted of more than 50 percent hydrogen; following production, this town gas was transported and stored underground in areas such as Beynes (France), Lobodice (Czech Republic) and Engelbostel, Hähnlein, Kirchhellen, Bad Lauchstädt, Eschenfelden, Ketzin and Kiel (Germany) [51–54]. The underground town gas storage facilities were built in the 1950s and used porous underground rock before the first salt caverns were brought into operation. Today, these facilities have been converted for use with hydrogen or decommissioned. Pure hydrogen (with a H2 content of over 95 percent) is currently only stored underground in salt caverns, and only at a few locations: Teesside in the United Kingdom and Clemens Dome, Spindletop and Moss Bluss in United States [51, 52, 55]. Salt caverns are cavities in underground salt domes with an average volume of 500 to 800 thousand cubic meters, which are leached via boreholes up to a depth of 2000 meters (Fig. 8.8). Salt is particularly suitable for storing gas because it is naturally impermeable to gas and the investment costs are low. In the United Kingdom and the United States, pure hydrogen has been stored for decades in underground salt caverns and used in the local chemical industries [52, 55]. This project demonstrates the suitability of rock salt for storing hydrogen, as well as the technical feasibility and economic viability of using these systems on a large scale. There are also thick salt deposits on land and at sea in Germany and Europe, which can be used on a seasonal basis to store hydrogen [56, 57]. Overall, Europe is estimated to have a potential storage capacity of 84.8 petawatt-hours; of this, 35.7 petawatt-hours stems from Germany alone [56]. However, the extent to which these reserves can actually be used depends on economic, environmental and social factors, and will require further analyses. At the Bad Lauchstädt Energy Park (HYPOS: H2-Forschungskaverne [58], see infobox) and in Rüdersdorf (HyCAVmobil [59]), some initial living laboratory projects have begun investigating the long-term storage and use of hydrogen in salt caverns. Porous rock reservoir refers to natural storage spaces with specific storage properties: First of all, the reservoir rocks must have a sufficient number of pores and cracks—examples include sandstone and limestone. They must also be overlaid with an impermeable, dome-shaped barrier rock, such as clay or salt. Only this

8.6

a

Geological storage options

193

b

Fig. 8.8 Underground storage facilities. (A) Salt caverns in artificially created cavities within a salt dome. (B) Porous rock reservoirs are a natural storage facility. Gaseous energy carriers can be stored in the pores and cracks in sandstone and limestone. The impermeable seal rocks made from clay or salt prevent the gas escaping vertically or laterally

barrier rock prevents the gas escaping laterally and vertically (Fig. 8.8). Abandoned hydrocarbon storage facilities or deep saline aquifers (i.e., layers of rock saturated with groundwater) must be considered here, as they have huge storage potential due to their size. Practical experience with hydrogen storage in porous rock storage facilities has mainly been limited to storing town gas in deep saline aquifers. Abandoned natural gas storage facilities could also be brought back into use as inexpensive storage options, as their barrier rocks of clay or rock salt have been proven to retain gases for millions of years. Other advantages include the fact that information is available about the underground area and the existing infrastructure can be used [51–53, 55]. The key factor here is whether the hydrogen stored underground can still meet high quality requirements after it is brought out of storage, or whether it has been contaminated with residual gases from the abandoned hydrocarbon storage facilities and thus needs to be treated. Microbial reactions that consume hydrogen also create an element of uncertainty here. Notable reactions include methanogenesis, acetogenesis, sulfate reduction and iron(III) oxide reduction, among others. A well-known example of converting hydrogen into methane using methanogenic bacteria is the aquifer town gas storage project in Lobodice (Czech Republic) [52, 53, 60]. In theory, geochemical reactions such as the reduction of sulfates, nitrates or iron ions are also possible. In the Beynes town gas storage facility (France), for example, the formation of hydrogen sulfide was traced back to the reduction of pyrite to pyrrhotite [61]. It has not yet been conclusively established whether pore storage fulfills the high-quality requirements for hydrogen and to what extent it can be used within the infrastructure chain.

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H2-Forschungskaverne project

Phase I: Development of a H2 storage research platform for storing green hydrogen at Bad Lauchstädt High-volume, safe and efficient storage of green hydrogen in underground gas storage facilities forms the groundwork for a secure energy system and material infrastructure that primarily comes from renewable sources. Salt caverns currently provide the best conditions for storing large volumes of hydrogen from renewable energy sources that go through large fluctuations. The goal of the joint project is to develop and set up a storage research platform for large-scale industrial underground storage of hydrogen produced through electrolysis in salt caverns, including a functional business model, and a connection to an existing hydrogen supply network. The project is part of the HYPOS—Hydrogen Power Storage & Solutions East Germany research initiative. The most important objectives for Fraunhofer:  Comparing the electrolysis technologies available on the market in terms of their suitability for use in combination with the planned cavern storage facilities at different locations and under varying supply conditions  Identifying the preferred multi-megawatt electrolyzers variants in terms of their placement and connection options  Developing an algorithm that can design the annual operating plan for the electrolyzers based on any current profiles that are fed into it, including deriving the economic parameters from hydrogen production costs  Creating an operating plan based on this algorithm for various system configurations and regulatory options that are in progress Partners:

DBI—Gastechnologisches Institut gGmbH Freiberg, VNG Gasspeicher GmbH, Fraunhofer IMWS, IfG—Institut für Gebirgsmechanik GmbH, ONTRAS Gastransport GmbH Research budget: Project budget: 1.3 million euros; Funding from Fraunhofer: 220,000 euros Timeline: May 2019 through July 2022 Contact: Marcus Tümmler (Fraunhofer IWES)

8.7

Other storage options

8.7

195

Other storage options

In addition to geological storage, there are other technologies available to store hydrogen. This chapter will discuss the most common of these. The low volume-rated energy content of hydrogen presents a technical issue when it comes to its storage [62]. Kurzweil et al. [63] classify the storage technologies into six main categories (Fig. 8.9). Classification into physical and chemical storage technologies can also be found in the relevant literature [62, 64].

8.7.1

Compressed gas storage

Pressurized vessels are already often being used to transport hydrogen in sectors such as transportation. Fig. 8.10 presents some storage technologies in a diagram. It shows that gaseous hydrogen has a low energy content and gravimetric energy density. In the past, there was also discussion around using technologies such as organometallic scaffold structures, metal hydrides, chemical hydrides and liquid

Fig. 8.9 Overview of technologies for storing hydrogen [64]

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8 Hydrogen infrastructures — Networks and storage

Fig. 8.10 Comparison of selected hydrogen storage technologies. Horizontal axis: Gravimetric energy density (ratio of weight of stored hydrogen and volume stored); vertical axis: Energy density per unit of volume [67]

organic hydrogen carriers (LOHC) in the mobility sector; however, these have not yet become established [65]. To withstand the high-pressure levels of up to 700 bar, cylindrical tanks wrapped in carbon fibers are usually used. When designing compressed gas storage tanks, it must be considered that, although the amount of stored gas increases as the pressure rises, this means the energy needed for compression and the required thickness of the tank wall, and thus the weight of the tank, increase at the same time. The optimal value to strike a balance between these parameters in transportation applications is 700 bar [66].

8.7.2

Liquid hydrogen

The volumetric energy density of hydrogen can be increased by cooling it to a critical temperature of 252.8 °C, which causes it to become liquefied [63]. This process significantly reduces the storage space. However, Töpler et al. report two main challenges that arise when storing liquid hydrogen: First, around 30 percent of the energy stored in the hydrogen is used just to carry out the liquefaction process [68]; second, even with good insulation, it is not possible to avoid converting the hydrogen to gas, which increases the pressure. For this reason, hydrogen must be purged from the storage container when the permissible pressure threshold is exceeded [66].

8.7

Other storage options

8.7.3

197

Binary metal hydrides

Storing hydrogen in the form of binary compounds with a metal hydride is considered to hold great potential for small- to medium-sized applications (0.01 to 30 Nm3 H2 ) [69]. However, the technology is still in its infancy. The main advantage of this storage method is its compact design; however, this comes with a high weight. In contrast to physical adsorption, where hydrogen molecules bond without changing structurally, in metal hydrides, the hydrogen is first chemically adsorbed through dissociation, before diffusing into the metal when a certain level of pressure is exceeded. At higher temperatures, the required pressure increases. If the temperature exceeds a critical level, storage becomes impossible. If hydrides are used at temperatures between 20 and 90 °C, they are referred to as low-temperature hydrides; while in this temperature range, they have a gravimetric energy density of 0.5 to 3 percent [69, 70]. To discharge the storage vessel, the temperature is raised, and the pressure is reduced. Transportation applications therefore have an advantage here—if the tank is damaged, the hydrogen remains bound in the metal. The waste heat from upstream or downstream processes can be used to release the hydrogen, as part of an efficient energy management system. Currently, the high costs and the weight of the storage containers pose challenges. In addition, there is a limit to the number of possible charging cycles, due to the formation of oxide layers and cracks from stresses in the material that result from the storage process [71].

8.7.4

Liquid organic hydrogen carriers (LOHC)

Liquid organic hydrogen carriers are probably the most promising alternative to compressed gas storage tanks. In these carriers, the hydrogen is not in its elemental form, but rather is bound to a liquid carrier substance through a chemical reaction (hydrogenation). This reaction requires a catalyst and happens exothermically, i.e., heat is released. To recover the hydrogen (dehydrogenation), heat must be constantly added [72]. The advantages to this method are the high energy density and that it has a simple refueling process, which is comparable to that of petrol or diesel; these could allow the existing fuel infrastructure to be used to the greatest extent possible [73].

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References 1. IEA (2019): The Future of Hydrogen, Seizing today’s opportunities 2. H2 MOBILITY Deutschland GmbH & Co. KG: H2Live. https://h2.live/en/, last viewed on March 21, 2021 3. FNB Gas (2020): Network Development Plan Gas 2020–2030, draft 4. FfE Forschungsgesellschaft für Energiewirtschaft mbH (2019): Studie zur Regionalisierung von PtG-Leistungen für den Szenariorahmen NEP Gas 2020–2030 (Study on the regionalization of power-to-gas services for the scenario framework for the Gas NDP 2020–2030) 5. BMWK (2019): Reallabore der Energiewende, H2Stahl. https://www.energieforschung. De/spotlights/reallabore, last viewed on October 2, 2021 6. VNG Gasspeicher GmbH: Bad Lauchstädt Energy Park. https://energiepark-badlauchstaedt.de/, last viewed on October 2, 2021 7. Raffinerie Heide GmbH: Westküste100. https://www.westkueste100.de/en/, last viewed on October 2, 2021 8. Nowega GmbH: GET H2 Nukleus. https://www.get-h2.de/projekt-nukleus/, last viewed on October 2, 2021 9. Deutsche Energie-Agentur GmbH (dena): Power to Gas Strategy Platform, project map. https://www.powertogas.info/projektkarte/, last viewed on October 2, 2021 10. Deutscher Verein des Gas- und Wassersfaches e. V. (DVGW) (2019): Mehr Wasserstoff technisch sicher verankern (Integrating more hydrogen in a technically secure way). Press release, https://www.dvgw.de/medien/dvgw/verein/aktuelles/presse/201904-09_-_Wasserstoff_technisch_verankern.pdf, last viewed on March 21, 2021 11. German Federal Parliament (2019): Sachstand, Grenzwerte für Wassersstoff (H2) in der Erdgasinfrastruktur (Critical values for hydrogen (H2) in the natural gas infrastructure). https://www.bundestag.de/resource/blob/646488/a89bbd41acf3b90f8a5fbfbcb8616df4/ WD-8-066-19-pdf-data.pdf, last viewed on February 10, 2021 12. German Federal Parliament (2019): Sachstand, Grenzwerte für Wassersstoff (H2) in der Erdgasinfrastruktur (Critical values for hydrogen (H2) in the natural gas infrastructure). https://www.bundestag.de/resource/blob/646488/a89bbd41acf3b90f8a5fbfbcb8616df4/ WD-8-066-19-pdf-data.pdf, last viewed on February 10, 2021 13. Gas for Climate (2020): European Hydrogen Backbone. How a dedicated hydrogen infrastructure can be created. https://gasforclimate2050.eu/?smd_process_download= 1&download_id=471, last viewed on January 25, 2021 14. Statista 2020: Anteil der Verbrauchergruppen am Erdgasabsatz in Deutschland in den Jahren 2010 und 2020 (Proportion of consumer groups in natural gas sales in Germany in 2010 and 2020) 15. Then D., Spalthoff C., Bauer J., Kneiske T.M., Braun M. (2020): Impact of Natural Gas Distribution Network Structure and Operator Strategies on Grid Economy in Face of Decreasing Demand. Energies 13: 664 16. Then D., Bauer J., Kneiske T.M., Braun M. (2021): Interdependencies of Infrastructure Investment Decisions in Multi-Energy Systems—A Sensitivity Analysis for Urban Residential Areas. Smart Cities 4 (1), 112–145. https://doi.org/10.3390/smartcities4010007

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66. Töpler J., Lehmann J. (2017): Wasserstoff und Brennstoffzellen (Hydrogen and fuel cells). Springer, Berlin, Heidelberg 67. Reuß M., Grube T., Robinius M. et al. (2017): Seasonal storage and alternative carriers: A flexible hydrogen supply chain model. Applied Energy 200: p. 290–302. https://doi. org/10.1016/j.apenergy.2017.05.050 68. Schüth F. (2009): Challenges in hydrogen storage. The European Physical Journal Special Topics 176: 155–166. https://doi.org/10.1140/epjst/e2009-01155-x 69. Tarasov B.P., Fursikov P.V., Volodin A.A. et al. (2020): Metal hydride hydrogen storage and compression systems for energy storage technologies. International Journal of Hydrogen Energy 100: 2. https://doi.org/10.1016/j.ijhydene.2020.07.085 70. Schlapbach L., Züttel A. (2001): Hydrogen-storage materials for mobile applications. Nature 414: 353–358. https://doi.org/10.1038/35104634 71. Klell M., Eichlseder H., Trattner A. (2018): Wasserstoff in der Fahrzeugtechnik (Hydrogen in autumotive engineering). Springer Fachmedien, Wiesbaden 72. Stolten D., Emonts B. (ed.) (2016): Hydrogen Science and Engineering: Materials, Processes, Systems and Technology. Wiley-VCH, Weinheim 73. Arlt W. (2017): Machbarkeitsstudie: Wasserstoff und Speicherung im Schwerlastverkehr (Feasibility study: hydrogen and storage in heavy goods transportation). https://www. encn.de/fileadmin/user_upload/Machbarkeitsstudie_LOHC-LKW_Teil_2.pdf, last viewed on November 2

9

Producing hydrogen through electrolysis and other processes

Sebastian Metz  Tom Smolinka Fraunhofer Institute for Solar Energy Systems ISE Christian I. Bernäcker  Stefan Loos  Thomas Rauscher  Lars Röntzsch Fraunhofer Institute for Manufacturing Technology and Advanced Materials IFAM, Dresden institute branch Michael Arnold  Arno L. Görne  Matthias Jahn  Mihails Kusnezoff Fraunhofer Institute for Ceramic Technologies and Systems IKTS Gunther Kolb Fraunhofer Institute for Microengineering and Microsystems IMM Ulf-Peter Apfel  Christian Doetsch Fraunhofer Institute for Environmental, Safety, and Energy Technology UMSICHT Abstract

In addition to expanding renewable energy sources and implementing electrical energy storage systems, hydrogen will form the third building block of the energy transition. Hydrogen and hydrogen-based synthetic fuels are particularly suitable for use in industrial processes, such as in the steel industry and the chemical industry, as well as in long-distance mobility, heavy goods transport and aviation, where battery storage meets its technological limits. Hydrogen applications will also become increasingly significant in reconversion processes, © Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_9

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as well as in the heating sector to a certain degree. It will only be possible to couple hydrogen with regenerative energy sources (wind power, photovoltaics) and integrate the energy system across sectors if hydrogen is produced by electrolysis. Below, the various technologies for hydrogen production that are either already available on the market or currently being launched on the market are presented and described in terms of their advantages and disadvantages. Whereas alkaline electrolysis has been an established practice on the market for decades, PEM electrolysis is still in the phase of being scaled-up in order to reduce costs. Other promising technologies that are still under development or in the demonstration phase include high-temperature electrolysis and alkaline membrane electrolysis. These “green” processes for hydrogen production will be compared to both existing processes (gray hydrogen: steam methane reforming) and new processes based on fossil fuels (blue/turquoise hydrogen). In the outlook, photo catalytic and biological processes are presented.

9.1

Hydrogen production processes

Today, the majority of hydrogen is produced by the steam reforming of natural gas, a process that releases large amounts of carbon dioxide (CO2 ). The production of one ton of hydrogen produces around ten tons of CO2 . Endothermic reforming also requires energy, so additional natural gas has to be combusted to keep the reaction going. A large proportion of “gray hydrogen” is required for processing crude oil in refineries, and consequently, for mass producing fuels and lubricants. It is also required for synthesizing ammonia (which is ultimately used to produce fertilizers) and producing chemical raw materials such as methanol, higher alcohols and amines (Fig. 9.1). In addition, it is used as part of the Fischer-Tropsch synthesis to produce synthetic fuels. Aside from natural gas, coal is also used as a fossil fuel. Hydrogen, also known as black hydrogen, is produced in a hydrothermal gasification process using steam. The term blue hydrogen is used when the CO2 released during steam reforming processes is separated and stored in subsoil. This is known as carbon capture and storage (CCS). This way, the CO2 is not released into the atmosphere. However, the challenge is to store it safely in the long term. Turquoise hydrogen is also produced from natural gas, with methane being broken down into its components by the supply of thermal or electrical energy to produce solid carbon and gaseous hydrogen. Therefore, the process itself does not result in the release of CO2 , provided the endothermic process is operated with

9.1 Hydrogen production processes

205

Fig. 9.1 Hydrogen production and applications worldwide. (own diagram based on IEA)

CO2 -free energy. However, as with all production processes based on natural gas, it is necessary to take into account the long-term sequestration of the carbon, as well as emissions that emerge upstream in the supply chain and cannot be avoided completely. In both steam reforming processes and methane pyrolysis, it is also possible to use biogas instead of natural gas. In terms of sustainability, there are particular benefits to using biogenic residues. However, the entire process chain and the associated emissions must be considered in light of the materials used, for example refuse materials or residue materials. One already-established method of producing hydrogen using electrical energy is chloralkali electrolysis, whereby hydrogen is produced as a by-product. However, the share of total hydrogen production is small. In the long term, green hydrogen and its synthesis products will have to play the most important role in building a sustainable hydrogen economy. The majority of green hydrogen is produced via water electrolysis, a process that only uses electricity from renewable energies and purified water (Fig. 9.2). This makes producing hydrogen a largely emission-free process. However, there are currently a variety of definitions for green hydrogen. For the German Federal Ministry for Economic Affairs and Climate Action (BMWK) and the Federal Ministry of Education and Research (BMBF), hydrogen is considered “green” if it is produced via electrolysis using renewable energies. On the other hand, testing organizations such as

9

Producing hydrogen through electrolysis and other processes

Gray

Reforming natural gas with steam - Associated with high CO2 emissions - Production costs: approx. €1.6/kg,

Blue

Reforming natural gas with steam, coupled with CCS - Requires permanent storage of CO2

Turquoi

Thermal breakdown ofmethane (pyrolysis) with renewable energies - Requires only the storage of solid carbon

Green

Reducing greenhouse gas

206

Water electrolysis with electricity from renewable energies - Electricity prices heavily influence

Fig. 9.2 Comparison of different methods of producing hydrogen in terms of current deficits and production costs. (own diagram)

the TÜV or the CertifHy European Guarantee of Origin have broader definitions when it comes to possible production processes and what renewable energies can be used. It is expected that these varying definitions will be coordinated in the near future, at least at a European level. As it stands, green hydrogen is on average twice as expensive as blue hydrogen, and about three times more expensive than gray hydrogen. Due to the increase in CO2 charges and the potential limits of low-cost CO2 storage facilities, it will be difficult to further reduce the cost of gray and blue hydrogen in the future. However, the cost of providing green hydrogen may nevertheless decrease the future if, first, there is an improvement in the efficiency and long-term stability of the electrolysis processes used, second, suitable regulatory framework conditions are established and, third, a hydrogen infrastructure is constructed in line with requirements. Various electrolysis processes can be used to produce green hydrogen. These differ mainly in terms of operating temperature and their particular stage of development. In order to select the appropriate technology, both environmental conditions and operating conditions must be taken into account. This will be further explained in Sect. 9.2. Further possibilities for producing green hydrogen can be

9.2 Hydrogen production by electrolysis

207

found in biotechnological processes and strategies for obtaining solar hydrogen through photocatalysis. Currently, the process of splitting water via photocatalysis is being tested on a laboratory scale. It promises future advantages in terms of cost thanks to its low system complexity and the tried-and-tested use of large-scale technologies from the photovoltaic industry. These electrolysis procedures, as well as other innovative procedures, will be discussed in more detail in the following sections.

9.2 Hydrogen production by electrolysis 9.2.1

Fundamentals of water electrolysis

Introduction In general, electrochemically splitting water into its components, hydrogen and oxygen, by means of electrical energy is referred to as water electrolysis. The process of splitting water is endothermic. The following equation describes the basic reaction: 1 H2 O  H2 C O2 2

HR D 286 kJ=mol

(9.1)

This is the opposite direction to a reaction in a fuel cell, whereby hydrogen and oxygen react to form water while producing electrical energy. The water can be supplied to the process either in liquid form or as steam; oxygen and hydrogen are produced as gases. At present, the technically relevant processes are alkaline electrolysis with a liquid basic electrolyte (AEL), acidic electrolysis with a solid polymer electrolyte (PEMEL) and high-temperature electrolysis with a solid oxide electrolyzer cell (SOEL). However, there are other electrochemical processes that can be used for water splitting which are currently under development (Fig. 9.3). These include alkaline membrane electrolysis, which uses an alkaline electrolyte membrane that is conductive to OH ions (AEMEL); proton conducting ceramic electrolysis (PCCEL); and co-electrolysis, which is also based on solid oxide cells (CoSOEL) and produces synthesis gas (CO C H2 ) by directly reducing CO2 and splitting water in a cell. The reverse water gas shift reaction (rWGS), which produces CO, runs in parallel. The Hydrogen Evolution Reaction (HER) at the cathode and Oxygen Evolution Reaction (OER) at the anode vary according to the electrolyte used and are summarized in Table 9.1.

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Fig. 9.3 Schematic representation of various water electrolysis procedures. Links: Lowtemperature electrolysis. Right: High-temperature electrolysis. (Fraunhofer ISE) Table 9.1 Half-cell reactions, typical temperature ranges and charge carriers of the three main types of water electrolysis Procedure

Temperature

Cathode reaction

Charge carrier

Anode reaction

AEL

70–90 °C

2H2 O C 2e ! H2 C 2OH OH

2OH ! 12 O2 C H2 O C 2e

AEMEL

50–70 °C

2H2 O C 2e ! H2 C 2OH OH

2OH ! 12 O2 C H2 O C 2e

PEMEL

50–80 °C

2H+ C 2e ! H2

H+

H2 O ! 12 O2 C 2H+ C 2e

PCCEL

450–600 °C

2H+ C 2e ! H2

H+

H2 O ! 12 O2 C 2H+ C 2e

SOEL

650–850 °C

H2 O C 2e ! H2 C O2

O2

O2 ! 12 O2 C 2e

CoSOEL

700–900 °C

H2 O C 2e ! H2 C O2

O2

O2 ! 12 O2 C 2e

CO2 C 2e ! CO C O2 CO2 C H2  CO C H2 O

One important factor that distinguishes the various methods is the choice of electrolyte. This determines the type of charge carrier (H+ , OH or O2 ), thus indirectly influencing the operating temperature of the cell. This is because ensuring that the ionic conductivity of the electrolytes is high enough requires establishing a minimum temperature. Determining temperature and pH value also determines what catalyst material should be used, since electrodes must have a sufficiently high level of electrochemical activity in this operating window to develop hydrogen and oxygen and must also remain stable for a long time. The types of materials and cell constructions, as well as other aspects of the system used for the individual technologies, will be discussed in the following sections. Under standard conditions (298.15 K and 101.325 kPa), the energy required to split the water according to Eq. 9.1 is HR0 = 285.8 kJ/mol, thus corresponding to

9.2 Hydrogen production by electrolysis

209

the heating value of hydrogen. According to the Gibbs-Helmholtz equation, the reaction enthalpy consists of two components: HR D GR C TSR

(9.2)

Free enthalpy of reaction (Gibbs free energy) GR describes the minimum required amount of energy that must be supplied in the reaction in the form of electrical energy. It corresponds to the heating value of hydrogen under standard conditions and has a value of GR0 = 237.2 kJ/mol. The product of the temperature T and enthalpy of the reaction SR from Eq. 9.2 is the portion of enthalpy of the reaction that can also be supplied to the reaction as thermal energy. However, unlike high-temperature methods (Fig. 9.3), low-temperature electrolysis (alkaline electrolysis and PEM electrolysis) cannot absorb (or can barely absorb) heat from the environment. Instead, the missing heat energy must similarly be introduced to the process in the form of electrical energy. The above values apply to standard conditions at 298.15 K but vary according to the process temperature. Fig. 9.4 is a diagram showing the temperature dependence of the thermodynamic variables. The discontinuity at 100 °C (373.15 K) is due to the phase transition of the water from liquid to steam. While the enthalpy reaction HR at T > 373.15 K (100 °C) is largely temperature-independent, the Gibbs free energy GR and the portion of entropy TSR show considerable variation according to temperature, resulting from the temperature dependence of the heat capacities of the substances involved. As the temperature increases, the Gibbs free energy GR decreases; at the same time, the product of temperature and entropy TSR increases. As the operating temperature increases, the minimum proportion of the enthalpy of reaction that has to be supplied in the form of electrical energy for the decomposition reaction decreases. This is the main advantage of high-temperature electrolysis, provided that intense heat can be used in the process. Given that electrolysis is an electrochemical process, the Gibbs free energy can be used to calculate the necessary voltages required for operating the electrolysis cells. The reversible cell voltage is calculated from the free reaction enthalpy GR0 0 to Vrev = 1.23 V and is equal to the cell voltage of a fuel cell operated under ideal conditions. However, when it comes to low-temperature electrolysis, no heat can be fed in, meaning that the minimum energy required for splitting water under standard conditions is equal to the reaction enthalpy HR0 , which can be used to calculate the minimum (thermoneutral) decomposition voltage Vth0 = 1.48 V. At temperatures of approx. 800 °C, the electricity required GR is reduced by approx.

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Fig. 9.4 Correlation between the thermodynamic condition variables HR and GR and the temperature for the decomposition of liquid and gaseous water at 101.325 kPa. (Fraunhofer ISE)

25 percent, with the theoretical decomposition voltage V rev dropping to values of around 1.0 V. However, during the actual operation of an electrolysis cell, these ideal cell voltages cannot be achieved—here, it must be taken into account that the voltage is dependent on the concentration, as described by the Nernst equation: VNernst;H2 D 

GR .p; T; H2  Ox/ RT xH2 O  ln 1=2 2F 2F xH2 xO2

(9.3)

In addition, additional loss mechanisms occur when a current flow is applied, which in actual operation leads to an increase in the operating voltage, and thus to a reduction in efficiency:  Ohmic losses: The electron flow and the ion flow run in opposite directions in an electrolysis cell. They are mainly caused by the ionic resistance of the electrolyte, the internal electrical resistance of the electrodes and by contact resistance.

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 Kinetic losses: These occur at the anode and cathode respectively, due to the speed-limited transition of the electrons to the boundary surface between the electrode and the electrolyte. These losses create overvoltages at the electrode, which work in the opposite direction of the reaction. The overvoltages on the hydrogen side (cathode) are significantly lower than the overvoltages on the oxygen side (anode).  Losses due to mass transport limitations: These losses are caused by obstacles to transporting gases and liquids to and from the electrode. Less conversion takes place at the electrode given the insufficient supply of the electrochemical reaction to the reactants. In order to uphold the conversion process, it is necessary to increase the overvoltage as a driving force at the electrode. A wellknown example of this mechanism can be found in the overvoltage caused by gas bubbles in gas-producing electrodes in liquid electrolytes, which are also exploited in alkaline water electrolysis. Although the effects of the unavoidable losses that occur when a current flow is applied to the cell can vary wildly, they nevertheless lead to an increase in the actual cell voltage compared to the ideal cell voltage in all electrolysis technologies. As a result, more energy has to be supplied as current density increases and the efficiency of the electrolysis cell is reduced. Since the rate of hydrogen production is proportional to the current supplied (Faraday’s law), developments the area of new materials and components aim to achieve the highest possible current densities, while keeping cell voltages low. In other words, it is necessary to find a compromise between high efficiency (low operating costs) and high current density (low acquisition costs). The losses outlined above appear to different degrees in the various electrolysis technologies. Fig. 9.5 shows typical voltage-current density characteristics for the three most important technologies: AEL, PEMEL and SOEL. The figure also estimates future development up to around 2030. Alkaline electrolysis uses nickel-based electrodes. It is carried out at temperatures of around 80 °C and current densities between 0.2 and 0.6 A/cm2 , while cell voltages are below 1.9 V. Recent developments with more complex electrodes are also suitable for current densities up to 1.0 A/cm2 at the same cell voltages. In the future, current levels of more than 1.0 A/cm2 should also be possible at cell voltages of around 1.8 V. PEM electrolysis can achieve high current densities of approx. 2.0 A/cm2 at approx. 60 °C thanks to its electrodes, which contain precious metal, and its very compact design. The cell voltages are between 1.8 and 1.9 V, making them comparable to those found in alkaline electrolysis. The current density will be increased to

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Fig. 9.5 Comparison of the different voltage-current characteristics for the three essential procedures, AEL, PEMEL and SOEL, and an estimation of typical operating points for the present day and 2030. (Fraunhofer ISE)

well over 3.0 A/cm2 by 2030, and the cell voltage will be reduced to approx. 1.7 V. High-temperature electrolysis, a comparatively new technology, also offers great potential in terms of development. Due to its high operating temperatures, the cell voltage is typically only 1.3 V. This will not change significantly in the next few years, but the current density will be increased considerably. A significant improvement in the life span of the cell stack is also expected as the technological maturity of the cells increases. Based on a literature study on the service life forecasts in Herz et al. [1], Fig. 9.6 shows an adapted representation for the three technologies AEL, PEMEL and SOEL. Although there are still significant differences in service life, over the coming decades, it is expected that individual cells or complete stacks will not have to be replaced in any of the three processes until over 80,000 hours of operation have passed. However, when coming up with a strategy for use, it should be considered that the mode of operation of the electrolysis system can have a considerable influence on the service life of the cells.

A brief history The principle of electrochemically decomposing water in an electrolysis cell has been known for more than 230 years. The first electrochemical production of hydrogen by means of electricity was carried out as early as in 1789 by van Troostwijk and Deiman, using an electrostatic generator as a DC power source [2].

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Fig. 9.6 Service life forecasts for the various electrolysis technologies, adapted according to Herz et al. (Fraunhofer IKTS according to [1])

Shortly after Volta had developed the voltaic pile in 1800, Carlisle and Nicholson used such a device to break water down into hydrogen and oxygen [3]. In the same year, Ritter carried out similar experiments in Jena. In addition, at the beginning of the 19th century, Cruickshank used a photovoltaic battery for the electrochemical decomposition of NaCl solutions into hydrogen and chlorine. Nevertheless, it took decades for these procedures to be used in technical applications. Around 1890, Charles Renard constructed a water electrolysis system for the production of hydrogen for French military airships. The world’s first electrolyzer to be built with cell stack (filter press) architecture was patented in 1899 by Oscar Schmidt from the company Oerlikon (R.P. 111131) and presented to the general assembly of the German Society of Electrochemistry in Zurich in August 1900 [4]. It is estimated that around the year 1900, more than 400 industrial alkaline water electrolyzers were in operation worldwide [5]. In addition, the large-scale technical application of the chloralkali process began, pioneered by the Griesheim-Elektron company in Bitterfeld, at the largest site of its kind at the time. Later, in the first half of the 20th century, various types of commercial alkaline water electrolyzers were developed in order to produce the hydrogen needed for producing ammonia fertilizer by making use of low-cost hydroelectric power. In Trail in Canada, Rjukan and Glomfjord in Norway, at the Aswan Dam in Egypt and elsewhere, large-scale plants with atmospheric electrolyzers and connection capacities of

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over 100 MW were built [6]. The production of heavy water also contributed to the commercialization of water electrolysis during this period. In the second half of the 20th century, the more cost-effective method of producing hydrogen through steam methane reforming increasingly replaced water electrolysis, and toward the end of the 20th century, the process was only used in niche applications. Work on PEM electrolysis began in the 1960s with NASA’s Project Gemini. General Electric then made the decisive breakthrough in the early 1970s [7] by using DuPont’s Nafion® membrane, which Walter G. Groth had developed some years before [8]. In the first twenty years, due to the high material costs, development work was almost exclusively focused on laboratory, military and space applications, although General Electric also developed concepts for large-scale use [9]. BBC then took its first steps to open up new markets with the 100 kW MEMBREL PEM system in the 1980s [10]. Also in the late 1960s, General Electric and the Brookhaven National Laboratory began developing a high-temperature electrolysis system with solid oxide cells [11]. In Germany, Dornier pursued the development of tubular HTEL cells between 1975 and 1987 as part of the Federal Ministry of Education and Research (BMBF) project HOT ELLY (High Operating Temperature ELectroLYsis) [12]. However, despite all these technical advances, these processes did not become widely commercially established, as they were not able to compete with the advantages offered by steam reforming. Water electrolysis has been attracting attention again since the mid-1980s, when hydrogen was used as a green energy carrier in conjunction with renewable energy sources such as wind and solar energy. The coupling of water electrolysis with renewable energies was successfully demonstrated in projects such as the DLR’s HySolar or Solar Wasserstoff Bayern (Solar Hydrogen Bavaria) in Neunburg vorm Wald [13]. However, it is only in the last ten years that the worldwide interest in water electrolysis has increased significantly with the adoption of ambitious national climate protection programs. It is now regarded as a key technology for sector coupling.

9.2.2

Alkaline water electrolysis

In addition to the peripheral systems (gas drying, compressors, pumps, rectifiers, etc.), an alkaline electrolyzer consists mainly of a stack of several electrolysis cells, in which water is separated into H2 (cathode) and O2 (anode) at the two electrodes. The structure of a single alkaline electrolysis cell in principle is shown in Fig. 9.7. The cathode and anode chambers (known as half-cells) are separated by a gasimpermeable membrane or a diaphragm. According to the general state of the art,

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Fig. 9.7 Basic structure of an alkaline electrolysis cell. (Fraunhofer ISE)

an aqueous solution, usually of 30% KOH, is used as the electrolyte at typical process temperatures between 70 and 90 °C. The nature of the electrodes depends on two main factors: first, low overvoltage and second, a lengthy service life of the electrocatalyst material and the electrode structure. The overvoltage ˜ on an electrode is defined as the difference between the reversible potential (thermodynamic ideal) for the corresponding half-cell reaction (Table 9.1) and the potential that actually has to be applied for the production of H2 or O2 . The industry-standard cell voltage values in alkaline electrolyzers range from 1.65 to 2.0 V, which corresponds to a specific energy consumption of 4.0 to 4.8 kWh per standard cubic meter of H2 produced (electrolysis efficiency of 73 to 88 percent relative to the heating value (HHV) of H2 ). In general, the electrode overvoltage rises as current density increases, meaning that current densities of 0.2 to 0.6 A/cm2 are typically used on a commercial scale. Platinum results in a very low overvoltage, making it the most suitable catalyst material for the cathode, which is where H2 is produced (hydrogen evolution reaction, HER). However, like other precious metals, it is not economically viable due to the high material prices. Therefore, several cheaper materials, which also have high HER activity (low overvoltage), were developed. Raney Ni and Ni-Mo compounds have shown the best properties in this regard [14–23]. The electrode

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catalyst materials most widely used today are layers of Raney Ni, which are applied to metallic carrier plates. Compared with smooth surfaces, Raney layers have a significantly higher effective surface area for the reaction and an increased structural defect density, making it possible to achieve a low HER overvoltage with the same effective current density. On the anode side, where the O2 formation reaction (OER) occurs, developments have mainly focused on nickel compounds [24, 25]. Raney Ni and Ni-X compounds (X = Co, Fe) play a leading role in this process and their activity can be further increased through the targeted addition of other transition metals [18, 26–28]. In addition to the electrochemical and mechanical properties of the electrode material, the way that the electrode is integrated into the individual cell is also crucial. The reaction chambers for HER and OER are separated by a gas-tight diaphragm (or membrane) to avoid cross-contamination of the gases. There are numerous common cell architectures which have different arrangements and distances between the individual components. For example, zero gap arrangements [24] are used, whereby the electrodes are directly pressed onto the diaphragm to reduce the voltage drops within the electrolysis cell by lowering the ohmic resistance of the electrolyte solution. In the classic design, however, a distance of a few millimeters is left between the electrodes and the diaphragm (or membrane) [25]. The advantages of this architecture lie in the simple and robust construction. The removal of the gas bubbles has always been problematic in all previous designs, however, because the resulting bubbles significantly increase the cell voltage. This is because they both temporarily block the active electrode surface and increase the ohmic resistance of the electrolyte solution. This is why the electrodes in conventional AEL cells usually consist of perforated sheets with as rough a surface as possible, which are positioned as “pre-electrodes” close to the diaphragm. By perforating the pre-electrodes, the gas bubbles, which are formed on the side facing the diaphragm, can be discharged into the space between the pre-electrode and the end plate. However, the fact that a significant part of the surface area cannot be used due to the perforation (up to 30 percent of the pre-electrode area) is a considerable disadvantage. This in turn limits the space-time yield of the entire electrolysis cell. Recent electrode developments are based on porous metallic carrier structures (porosity of 60 to 90 percent) with electrocatalytically active layers deposited on the surface. The production of such porous, current-carrying 3D substrate materials with an electrocatalytically active alloying system and the associated investigation of the structure-property relationship has been a core competence of Fraunhofer IFAM for several years and goes hand in hand with the development of technologies for production on an industrial scale [29, 30]. Metallic foams, fiber structures, webbing and mesh are used as substrate materials. These are generally made

9.2 Hydrogen production by electrolysis

a

c

217

b

d

e

Fig. 9.8 Examples of macroporous metallic substrate materials for live pre-electrodes: (a) metallic foams, (b) metallic fiber structures, (c) porous metal films, (d) additively manufactured metal structures, and (e) metallic nets and mesh which can also be used threedimensionally as a layered stack (optionally even with a porosity gradient). (Fraunhofer IFAM)

of nickel and are also widely available in sizes of one or more m2 . Moreover, they have a good corrosion resistance in the KOH solution at higher temperatures (Fig. 9.8). In general, the efficiency of the electrolysis process decreases as current density increases. Alongside the reaction kinetics (Butler-Volmer behavior), the increasing ohmic resistance of the cells should be considered the main factor for the increase in the cell voltage. The resistance is caused by gas bubbles in the electrolyte between the electrode and the separator. Since the gases produced lead to a significant increase in electrolyte resistance, it is possible to noticeably improve how effectively these gas bubbles are handled by employing three-dimensional cellular metallic structures. Due to the porous three-dimensional structure of the electrode, gas bubbles flow from the entire surface, i.e., along the electrolyte space between the electrodes and the separator (Fig. 9.9). As a result, the overall cell resistance falls and the efficiency of the process increases. These porous electrodes are particularly suitable for the zero-gap arrangement, which can therefore work at lower cell voltages or can work at higher current densities, for example.

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Fig. 9.9 Comparison of classical and zero gap cell architecture in alkaline electrolysis. (Fraunhofer IFAM)

The coating of 3D substrate structures with electrocatalytically active layers can be carried out via electroplating, sintering or plasma processes. The powder metallurgical method has been shown to be particularly favorable as a continuous production process. Fig. 9.10 shows an example of a Raney Ni coating applied to a nickel substrate via a powder metallurgical process. The following process steps are required for production: First, the Ni foams are coated with aluminum in a powder metallurgy process route. Subsequently, a heat treatment is carried out to produce Ni-Al phases close to the surface, from which aluminum is then selectively extracted, resulting in skeletal nickel, known as Raney nickel.

Fig. 9.10 Schematic representation of the manufacturing steps of the Raney Ni coating of electrode substrate materials. (Fraunhofer IFAM)

9.2 Hydrogen production by electrolysis

a

After heat treatment

219

b

After leaching

Fig. 9.11 Cross-sections of the Ni foam (450 µm) (a) following heat treatment and (b) following leaching (I: leached Ni2 Al3 phase, II: leached NiAl3 phase). Inserted images: view from above. (Fraunhofer IFAM)

Fig. 9.11 shows cross-sectional views of the Ni foams following heat treatment and leaching. After the heat treatment, a homogeneous layer can be seen on the Ni foam joints. After the leaching of the Al-rich phases, a porous layer (Ni skeleton) with channels arranged perpendicular to the foam joints, resulting in a significant increase in surface area compared with uncoated foam (increased by a factor of 1000 to 10,000). It is also evident that the channel-like layers consist of several Ni-Al phases. As shown in the Ni-Al phase diagram, these are Ni2 Al3 or NiAl3 . The effect of the resulting Raney Ni layer on the activity of the hydrogen evolution reaction (HER) can be explicitly demonstrated by means of electrostatic measurements and steady-state current density potential curves (Fig. 9.12). Regardless of pore size, uncoated Ni foams exhibit an overvoltage of approximately 390 mV at a current density of 0.3 A/cm2 . As a result of the Raney Ni coating, the overvoltage is reduced to approx. 70 mV. This corresponds to an improvement of approx. 320 mV (approx. 85 percent). The Ni foam structures coated with Raney Ni therefore represent highly active electrodes for the development of hydrogen in highly concentrated alkaline solutions. The development of the overvoltage over time is close to constant. The steady-state current density potential curves confirm the high activity of the Raney Ni-coated Ni foams. At the same time, no transport limit is evident, even with high currents, meaning that an unhindered gas transport through the porous 3D Raney Ni foam structure can be assumed. Of all the electrolysis technologies, alkaline electrolysis (AEL) has so far proven the longest service life of 90,000 h, which is due, among other things, to

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Fig. 9.12 Electrochemical evaluation of Ni foams coated with Raney Ni with different pore sizes (450 µm, 580 µm) compared with uncoated foams. Links: Galvanostatic measurements at a geometric current density of 0.3 A/cm2 for 5 h; right: Steady-state current density potential curves (Tafel plots) after 5 h at 0.3 A/cm2 for different electrode materials at 29.9% KOH by mass at 60 °C. (Fraunhofer IFAM)

the robustness of the materials and components used. With regard to current density, however, alkaline electrolysis is lagging behind the other methods. Currently, studies are being conducted regarding the operation of AEL cells up to 1 A/cm2 , and in some cases beyond that, which would significantly increase the space-time yield of alkaline electrolyzers in the foreseeable future. At the same time, component and plant manufacturers are currently making extensive efforts to automate production in order to achieve annual production capacities in the gigawatt range by the late 2020s.

9.2.3 PEM electrolysis The general structure of a PEM electrolysis cell is shown in Fig. 9.13. Both halfcells are separated by a proton conducting membrane that serves as a solid electrolyte in the cell. A thin catalyst layer (CL) is applied as an electrode on both sides of the membrane. Oxygen is produced at the anode and hydrogen is produced at the cathode; see the reaction equations in Table 9.1. This structure is known as membrane electrode assembly (MEA). Porous transport layers (PTLs) are pressed against the electrodes, which draw the electrical current to or from the electrodes.

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Fig. 9.13 Schematic diagram of a PEM electrolysis cell; PTL: porous transport layer. (Fraunhofer ISE)

The porous structure also means that the anode can be supplied with educt water and the gases produced can be dissipated at both electrodes. The PTL is connected to a flow field plate, which ensures that the educt water is distributed over the entire surface area of the cell and the gases produced are discharged from the back side of the PTL. In a cell stack, the flow field is often part of the bipolar plate. Alternatively, multi-layered expanded metals can be used as flow fields, as they work as electrically conducting spacers. The proton conducting membrane is usually a perfluorinated sulfonic acid membrane (PFSA) such as Chermour’s Nafion® or FuMA-Tech’s fumapem® with a thickness of 50 to 180 µm. This membrane is characterized by its very high proton conductivity, low gas permeability and excellent mechanical and chemical stability. During operation, however, it is not possible to completely suppress the permeation of oxygen and hydrogen through the membrane. Typical H2 purity levels at cell output range from 2.8 to 4.0 (based on dry hydrogen). The degree of purity can be significantly increased by using an internal, catalytically active recombination layer. As it absorbs water, the PFSA membrane swells. Undesirable wrinkles can occur, especially at large surface dimensions, and the membrane in the pressed cell can be mechanically damaged as a result. In order to prevent this, mesh structures inside the membrane provide reinforcement. These counteract the swelling, but also reduce conductivity. For these reasons, alternative

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ionomers are also being developed for PEM electrolysis, for example hydrocarbon membranes. However, for technical reasons, these materials have not yet become widely established in practice. Proton-conducting membranes have highly acidic properties. Combined with the high potential in an electrolysis cell, it is necessary to use precious metals as electrode materials. The catalyst layers are only a few micrometers thick on the anode and cathode alike. Efficient hydrogen production requires platinum as a HER catalyst. In most cases, platinum is placed on a carbon support for more efficient material use. The precious metals iridium (the preferred option), ruthenium and their oxides are used for the oxygen production. Modern MEAs have a catalyst load of approx. 1.5 to 2.5 mg/cm2 on the anode side and approx. 0.8 to 1 mg/cm2 on the cathode side [50, 51]. Typical power characteristics are shown as voltagecurrent density characteristics in Fig. 9.5. There are significant efforts underway to reduce these loads by approx. 40 to 60 percent in newer MEA generations. Titanium or titanium dioxide-based carrier materials are also being developed to this end for the anode side. The primary reason for reducing precious metal loads is not because it is necessary to reduce material costs, but rather because iridium is a critical material [31]. The annual production volume of iridium is only about 6 to 8 tons worldwide. At current power densities and loads, however, the production of PEM electrolyzers requires approx. 650 to 700 kg of iridium per 1 GW output. In order to produce PEM electrolyzers capable of producing gigawatts of energy on a large scale in the future, the specific iridium consumption should therefore be reduced to approx. 50 kg/GWel . Alternatively, there are ongoing efforts to replace precious metals in PEM electrolysis. Transition metal oxides and sulfides, in particular, are, alongside alloys, subjects of extensive discussions in scientific literature as possible materials for anodes and cathodes. Significant progress has been seen in recent years in terms of stability and performance characteristics. However, most of these materials are still a long way from an industrial application due to the lack of studies conducted on upscaling these materials and the fact that they are not sufficiently incorporated into the necessary membrane electrode assemblies [52]. The porous transport layers (PTL) in PEM electrolysis are only a few hundred micrometers thick. They ensure an even distribution of the electrical current between the bipolar plate and the electrodes, and allow high gas and water permeability. On the hydrogen side, the electrode potential is close to 0.0 VRHE , making the use of carbon paper or carbon-based non-woven material possible, just as with PEM fuel cells. On the oxygen side, titanium is almost exclusively used as a material for its high corrosion resistance, on account of the high potential. However, when titanium comes into contact with oxygen, it forms a passivating and electrically insulating layer of titanium oxide on the surface. For this reason, protective

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Fig. 9.14 Typical PTL and spacer materials for PEM electrolysis cells: (a) sintered Ti powder, (b) sintered Ti-based non-woven fabric, (c) Ti expanded metal, and (d) carbon paper. (Fraunhofer ISE)

layers are sometimes also applied to ensure better electrical contact. Fig. 9.14 shows porous transport layers of titanium and carbon for PEM electrolysis. Sintered Ti-based non-woven fabrics have become established as the best material for a PTL, but this also greatly depends on the particular cell design and level of porosity [53]. Sintered Ti particles have also produced good results but are significantly more expensive than expanded metals and non-woven materials. The flow field or bipolar plates in a stack must also be made of corrosionresistant materials such as titanium or coated steel. However, the latter approach is not used in commercial products today. On the hydrogen side, cheaper carbon composite materials could also be used, but the use of a single-layer titanium bipolar plate is more cost-effective. The plate is made from thin sheets (of a few hun-

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dred micrometers to approx. 1 mm) through milling, punching, deep drawing or hydroforming processes and can also be coated to minimize contact resistance by passivation. The most common design for PEM electrolysis is the filter press design with approx. 50 to the current maximum of 220 cells per stack, which are electrically connected in series, with the fluids flowing through them in parallel. This means that two adjacent cells are separated by a bipolar plate (BPP), which simultaneously acts as the anode of one cell and the cathode of the other. These days, typical cell sizes have geometric dimensions of 300 to 1500 cm2 (active surface area). Tests are also underway using the first prototypes with a cell area of up to 5000 cm2 . The cell thickness ranges from 2 to 5 mm. This makes PEM electrolysis stacks significantly more compact than alkaline electrolysis stacks in terms of the number of cells, but above all also the cell area and volume. In addition, they have a higher power density. The electrical connection power of a single stack ranges from several hundred kilowatts to the current upper limit of approx. 1.5 MW [54]. In the meantime, the rectangular design has become the norm for PEM electrolysis, despite having to withstand pressures of up to almost 50 bar. Due to the cell design, a PEMEL stack can also be operated at differential pressure with several MPa of differential pressure between the anode and cathode. While the cathode produces hydrogen under pressure, the oxygen side works at close to atmospheric conditions. The advantage of this is that the hydrogen is already electrochemically compressed, meaning that the significantly less efficient process of mechanical compression at a later stage is no longer necessary. In addition, low-cost components can be used for the peripherals on the oxygen side, as these do not have to be pressure-resistant, and ultimately, the uncompressed oxygen represents a significantly lower safety risk. A stack of this kind, operated at differential pressure, can be seen in Fig. 9.15. To examine the long-term behavior, all cell voltages in this stack are tapped individually. The single voltage tap can be seen on the right side of the image. The electrolysis stack is the key component of any electrolysis system. In order to achieve higher production capacities, several stacks are usually interconnected in a single system. A number of additional components are required for water splitting in order to be able to operate the stacks as desired and in a stable condition. The basic structure of a PEMEL system is comparable to that of an alkaline system. The DC current required for water splitting is specified via a rectifier. After the water is treated to achieve DI water quality, the water is circulated on the anode side in order to continuously feed educt water to the PEMEL cell and to cool the cell via a heat exchanger. No such circulation is required on the cathode side. On both sides, gas-water separators and demisters are placed behind the stack exits in

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Fig. 9.15 Measurement of a NEL Hydrogen 250 kW PEMEL stack with single cell voltage tap for monitoring the cells in continuous operation. (Fraunhofer ISE)

order to retain the liquid water. This also accumulates on the cathode side through the electro-osmotic water transport via the membrane and has to be returned to the cell. The hydrogen, which is still wet, is then dried; residual oxygen is catalytically removed in a deoxo stage. Pressure-retaining valves regulate the pressure on the anode and the cathode.

9.2.4

AEM electrolysis

Two technologies are currently used in the classical production of hydrogen through electrolysis of liquid water: Alkaline electrolysis (AEL), in which base metals such as nickel alloys and non-ferrous compounds are used as electric catalysts, bipolar plates (BPP) are made of cost-effective nickel-plated steel and the alkaline liquid electrolyte used is KOH. The disadvantages of the method are the use of potassium hydroxide as a circulating electrolyte and the (still) low current densities. The more recent PEMEL technology uses an acidic membrane elec-

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trolyte, DI water, precious metals (iridium, platinum) as catalysts and titanium (Ti) as the material for bi-polar plates and the porous transport layers (PTL). Due to the compact design of the membrane electrode assembly (MEA) and the use of precious metal catalysts, PEMEL cells are characterized by cell voltages below 2.0 V and current densities greater than 2 A/cm2 . There are also disadvantages with this method, in particular the high material costs for the catalyst-coated membrane (CCM) and the titanium-based bipolar plates and the porous transport layer (PTL). In particular, the availability of iridium as an anode electrocatalyst is critical [31]. In order to minimize the disadvantages of the two abovementioned methods, while nevertheless exploiting their respective advantages, widespread efforts are underway to combine both technologies in AEM electrolysis by using an alkaline anion exchange membrane (AEM) as a solid electrolyte (Fig. 9.2). The system design of an AEM electrolyzer is similar to that of a PEM electrolyzer but uses cost-effective materials that have been proven to be effective in AEL. For the construction of an efficient AEMEL system, stable, conductive and, above all, cost-effective anion exchange membranes must be developed, while stable, electrochemically active catalysts need to be found. An anion exchange membrane installed in an electrolyzer must have a level of conductivity above 0.1 S cm1 and a thickness of between 50 and 80 µm. In addition, the membrane should be stable in the long term. The basic approach for constructing an anion conductive membrane is to produce a self-conducting homogeneous membrane. In this case, cations are bound to a stable non-conductive polymer framework, for example to polyarylethers or fluorinated polymers. Quaternary ammonium salts or analog phosphonium and sulphonium salts are used as cations [32–34]. Since the ion mobility of the hydroxide ion is significantly lower than that of the protons, the anion exchange membrane usually has a lower level of conductivity than the proton exchange membrane (PEM), e.g., Nafion. Various strategies are being pursued to improve the conductivity of the alkaline membrane. On the one hand, researchers are attempting to increase the ion exchange capacity (IEC) within the membrane. However, this leads to a strong swelling of the membrane due to water absorption, which in turn has negative consequences for the stability of the membrane and the integrity of the membrane electrode assembly. On the other hand, the development of “phase-segregated” AEMs is favored. By using hydrophobic and hydrophilic phases, the aim is to create specific “ionic highways” where fast ion transport is possible. Pan et al. were able to produce an anion exchange membrane with the conductivity of Nafion using a functionalized polysulfone [35]. The main disadvantage of homogeneous membranes is reduced stability. This is due to the fact that the quaternary salts, a good leaving group for the purposes of Hofmann elimination or a nucleophilic substitution reaction, can be

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quickly separated in the alkaline medium [36]. Various concepts for avoiding this degradation pathway have been discussed, including the use of sterically demanding quaternary amines, bypassing hydrogen atoms in “ position to the quaternary amine and using electrolytes containing carbonate [32, 37–39]. In addition to the homogeneous membranes, heterogeneous membranes are also a subject of discussion. These are characterized by the fact that a mostly inorganic ion exchanger material is embedded in an inert polymer matrix. For example, polyethylene oxides (PEO or PEG) or polyvinyl alcohols (PVA) are used, in which an inorganic salt, such as KOH, can be dissolved. The conductivity of the membrane is only made possible by the salt. These are known as ion solvent membranes. Conductivity of up to 103 S cm1 can be achieved here. One particularly noteworthy variant is the use of polybenzimidazole (PBI), which is characterized by good chemical stability and has conductivity of up to 101 S cm1 [40–42]. Another current task in the area of AEMEL R&D is the development of suitable electric catalysts. Stable, PGM-free and electrochemically active catalysts are required for this [43]. When it comes to the OER reaction, not only precious metals, but also non-stoichiometric transition metal oxides appear to be the primary potential candidates [44]. Perovskites (ABO3-• ) and layered double hydroxides (LDH) have been shown to be particularly catalytically active here. Most studies, however, do not carry over well to a real-world application environment. From a technical point of view, mainly Ni-Fe and Ni-Co compounds have become established for the OER side. For example, at 80 °C and 1 M, NaOH overvoltages of 265 mV with a current density of 0.5 A/cm2 have been achieved [45]. A study from 2015 presents a series of transition metal (oxy)hydroxides as trifunctional catalysts (OER, HER, ORR). Although the study only looked at low current densities, these are highly interesting for reversible AEMEL cells [46]. With regard to HER, several studies have been carried out to attempt to improve the catalytic properties of cathode materials [47, 48]. In addition to the catalysts containing precious metals (Pt, Pd), it is Ni-based compounds, especially Ni-Mo, that have become established. In principle, the preferred solution would be to use DI water, as in PEM electrolysis. Under these conditions, however, most AEM electrolyzers show high cell voltages. The use of an alkaline electrolyte, on the other hand, seems to be more feasible on a technical basis, as the HER/OER catalysts are more stable and active here due to the alkaline environment, which poses less of a risk of corrosion. Cell voltages of less than 1.9 V could be achieved with current densities up to 1 A/cm2 . For example, Liu et al. showed that an AEM electrolyzer with an optimized AEM and NiFeCo catalyst (HER) and NiFe2 O4 delivers a stable (2000 h) current density of 1 A/cm2 at approx. 1.9 V on the anode side in 1 M KOH [49].

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Despite the material and technical challenges, AEM electrolysis has the potential to become an important technology in the field of water electrolysis. Assuming a technological revolution similar to that of membrane-based PEM electrolysis, it can be expected that AEMEL systems will be established on a megawatt scale by the late 2020s.

9.2.5 High-temperature steam electrolysis High-temperature electrolysis (HTEL) is generally understood to mean electrolysis based on solid oxide electrolytes, known as solid oxide electrolysis (SOEL). High-temperature electrolysis converts steam into hydrogen and oxygen, which significantly reduces the need for electrical energy in the conversion process compared with water electrolysis. The reason for this is the lower free enthalpy (Gibbs free energy) of the steam compared with the liquid water, which is reduced by the heat of evaporation. This relationship is illustrated in Fig. 9.4. In addition, a declining trend in Gibbs free energy is also evident as the temperature rises. This results in a lower decomposition voltage and means that less electrical power is required for electrolysis. Thermodynamically speaking, electrolysis is an endothermic process that can only be carried out given a continuous supply of heat. The internal resistance of the cell serves as a source of heat. In the case of high-temperature electrolysis (HTEL), the Joule heat generation from the internal resistance of the cell compensates for the other losses of the steam splitting once a certain operating voltage is reached. If the amounts of thermal energy required for electrolysis and heat provided by voltage losses are the same, the operating voltage is referred to as the thermoneutral voltage. Due to the self-sustaining nature of the reaction, hightemperature electrolysis is only viable when operated close to the thermoneutral voltage. The absolute value of the thermoneutral voltage depends on the operating temperature of the cell and the gas composition. At temperatures between 700 and 850 °C, it is in the range of 1.28 to 1.30 V. Since a higher local current density generates a greater local steam conversion, and thus a higher local cooling capacity, the current density and temperature distribution over the cell surface in SOEL is much more uniform than in fuel cell operations. There, a higher local current density leads to hotspots due to the exothermic reaction. Despite the thermodynamic advantages, the high operating temperature poses major challenges to the materials and seals of an HTEL stack. The first hightemperature electrolyzers were constructed with tubular cells and had relatively high internal resistances. The progress in the development of the planar solid oxide

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Fig. 9.16 Schematic representation of a solid oxide cell according to [56]. (Fraunhofer IKTS)

cell for fuel cell applications, as well as the considerable increase in power density while simultaneously reducing manufacturing costs, enabled the development of a new generation of high-performance, planar HTEL cells. Current cell structures of high-temperature electrolyzers (Fig. 9.16) are based on Y2 O3 (YSZ) or Sc2 O3 (ScSZ) stabilized ZrO2 as an electrolyte, a cermet cathode (Ni/G8VDC or Ni/8YSZ) and a perovskite (La0,6 Sr0,4 Co0,8 Fe0,2 O3 ) or composite anode (perovskite/electrolyte). The steam is fed to the cathode side of the cell. As nickel is a component of the steam electrode and oxidizes into NiO in pure steam, a small amount of hydrogen is added to the steam. In electrolysis, the oxygen is removed from the steam electrochemically and then is directed to the anode side via an oxygen-conducting electrolyte. The hydrogen concentration on the cathode side increases continuously from the gas inlet to the gas outlet. Especially in concentration ranges of more than 90 percent hydrogen in the steam, the Nernst voltage rises considerably [55], meaning that there is a considerable increase in the operating voltage and the electrical energy supplied during electrolysis. This does not make sense for an economical operation. In a concentration range of 20 to 85 percent hydrogen, the Nernst voltage only slowly changes as hydrogen content increases, meaning that at a hydrogen concentration of 10 to 20 percent in the steam, steam utilization rates of 80 percent are not only reasonable to expect, but entirely possible.

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Fig. 9.17 Components and structure of an SOC stack. (Fraunhofer IKTS)

In the last decade, planar stack construction has become established, with two different cell concepts widely used by various companies around the world for stack building:  Electrolyte supported cells (ESCs) based on a thin electrolyte substrate (60 to 150 m) as the supporting element  Cathode supported cells (CSCs) consisting of a Ni-YSZ cermet substrate with a sintered electrolyte layer (5 to 10 m) Although the SOEL cell itself is the heart of an HTEL electrolyzer, it is only one part of the stack, which also contains gas manifolds, seals and current collectors. The structure and essential components of a planar SOC stack are shown in Fig. 9.17. The stack consists of the coated metallic interconnector (bipolar plate), the ceramic cell itself, glass seals and contact elements on the steam (Ni mesh) and air side (oxide contact layers). The SOEL cells are manufactured by means of tape castings and screen-printing technology. The basic sequence of cell production is shown in Fig. 9.18. It is a “sheet-to-sheet” production process that can be implemented with high cycle times. A tunnel furnace can be used in mass production for electrode baking.

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Fig. 9.18 Production steps for an electrolyte-supported cell. (Fraunhofer IKTS)

Fig. 9.19 Production steps for an SOEL stack. (Fraunhofer IKTS)

The production of an HTEL stack is shown schematically in Fig. 9.19. The process is similar to the manufacturing process of NT electrolysis stacks, with the exception of the joining process. The joining process includes not only the serial contacting of the cells, but also a check of the functionality and tightness of the stack. The forecasts of the cost of production of SOC stacks are thus very close to the targets for PEMEL and AEL stack production. Due to the high operating temperature and the thermo-mechanical stresses in ceramic components that develop when the stack cools down, the lateral dimensions of the SOC cells that can currently be implemented are limited to approx. 25  25 cm2 [57]. For high plant performance, smaller stacks (with cell sizes 10  10 cm2 to 15  15 cm2 ) are therefore integrated into larger modules [58–60]. The individual stack modules are then installed in larger plants. Since the solid oxide cell works in electrolysis, fuel cell and bidirectional operation (known as a reversible solid oxide cell, rSOC), it seems appropriate to use the same modules for different applications. There are also considerable differences in the electrode structure as well as in the thermal management in the stack for stable SOFC and SOEL operations in the long term, resulting in applicationspecific cells and stack designs [61]. While the stable electrolysis operation of ESC at 800 °C has already been demonstrated by the development of robust electrodes at Fraunhofer IKTS, long-term operation of CSC at lower operating temperatures (650 to 750 °C) remains a challenge. Although the data of CSC stacks show a low rate of degradation after an initialization phase, this is often not taken into account when calculating the overall degradation [62].

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The plants for high-temperature electrolysis have not yet reached the level of technological maturity required for series production as seen in alkaline and PEM electrolysis. Nevertheless, there are still some impressive demonstrations for rSOC and SOEL pilot plants, as exemplified by a company from Dresden, SunFire GmbH (formerly Staxera GmbH), which was established on the basis of stack technology development and technology transfers from Fraunhofer IKTS. Since 2014, the focus of the company has been on the development of synfuels via high-temperature electrolysis. SunFire has demonstrated the first industrial plants for SOEL operation (GreenHy, Salzgitter, 750 kW) [63] and for reversible electrolysis/fuel cell operation (rSOC) (with Boeing, 150 kW/30 kW) [64]. Although the PEM stack, for example, is very well suited for pure hydrogen production and use, rSOC technology has advantages in efficiency for stationary applications, in particular thanks to its compact integration and efficient use of heat. A 62.7 percent round-trip efficiency was recently demonstrated in this area by the Forschungszentrum Jülich research center for an rSOC plant with an electrical output of 5 kW [65].

9.2.6

Co-electrolysis of water and carbon dioxide

Due to the high temperatures, CO2 electrolysis may take place in an SOC hightemperature cell similar to steam electrolysis. However, the free enthalpy of carbon dioxide reduction is greater than that of splitting water (Fig. 9.20). For this reason, higher electrical voltages are required for direct electrolysis of CO2 . The production of carbon monoxide (CO) from CO2 in HTEL cells has already been commercially implemented by the company Haldor Topsoe [66]. A CSC stack with a modified cermet electrode is used for this purpose. The special feature of pure CO2 decomposition is the avoidance of carbon formation from the Boudouard reaction. Thermodynamic calculations show that the carbon-forming threshold in the CO2 /CO gas mixture shifts towards higher CO concentrations as operating temperature increases. Above 750 °C, carbon monoxide is thermodynamically stable. Carbon formation is possible below this temperature. In this case, the nickel in the cermet electrode acts as a catalyst for carbon formation. Due to the temperature gradients in the stack, there are always certain temperature ranges that are prone to involve carbon formation. The electrochemical processes in the cell are similar to those of steam electrolysis, with the overvoltage for CO2 reduction on the cathode being significantly higher than the overvoltage of steam decomposition (Fig. 9.20). The addition of steam to CO2 fundamentally changes the reaction

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Fig. 9.20 Thermodynamic comparison of steam electrolysis and CO2 electrolysis. (Fraunhofer IKTS)

mechanism. Under the operating conditions of the SOEC, the rWGS reaction establishes a thermodynamic equilibrium state on the side of the products. Thus, by using the smaller overvoltages for steam decomposition, carbon monoxide can be produced in addition to steam. Since the overvoltage of hydrogen reduction is significantly lower than that of CO2 reduction, the electrochemical steam reduction (with hydrogen production at the three-phase boundary) and the reverse water gas shift reaction (rWGS) with CO production on the surface of the catalyst (Ni) take place simultaneously in the high-temperature cell (see the reaction equations in Table 9.1). Nevertheless, the production of H2 and CO from the H2 O/CO2 mixture is generally referred to as co-electrolysis. This fact is also reflected in small differences in electrical energy consumption for H2 O and H2 O/CO2 electrolysis. These have been detected for the first time by Fraunhofer IKTS in measurements on cells and stacks at 800 °C. The higher electrical energy consumption during co-electrolysis can be explained thermodynamically by the slightly higher open circuit voltage when CO2 is added to steam. The no-load voltage results from the higher free enthalpy (GR ) of CO2 at temperatures below 823 °C (Fig. 9.20). This also changes the thermoneutral voltage, which influences thermal management and the energy balance. Even if a gas mixture of steam and carbon dioxide is used, H2 must be introduced at the gas inlet in order to avoid Ni oxidation at the cathode. In addition, the utilization of steam and

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CO2 is limited not only by the concentration-related increase in the Nernst voltage, but also by the limit of carbon formation. Co-electrolysis offers new possibilities for the single-stage production of synthesis gas and its coupling with chemical synthesis processes. In particular, the use of heat from exothermic reactions, as is the case in Fischer-Tropsch synthesis (ekerosene production), the Haber-Bosch process (e-ammonia production) and the Sabatier reaction (e-methane production). The use of the heat of reaction to generate steam as an educt for electrolysis reduces the electrical energy required and thus increases the overall electrical efficiency of the synthesis process. Initial feasibility and demonstration projects at Fraunhofer IKTS show that, by combining co-electrolysis with Fischer-Tropsch synthesis, highly efficient processes for the production of wax and diesel are possible [67].

9.2.7 High-temperature ceramic-based proton-conducting electrolysis A promising option for hydrogen production is steam electrolysis with proton conducting ceramic electrolytes (PCCEL). The motivation for the development of a proton-conducting ceramic cell for higher operating temperatures comes from fuel cell development and is based on the fundamental advantages of proton conduction over oxide ion conduction at lower operating temperatures (500 to 600 °C). This results in a longer service life and lower costs for passive stack and BoP components, as well as simpler system integration. At the same time, other advantages of the SOEL, such as fast electrochemical kinetics and electrodes free from precious metals, come into play. Compared with SOEL technology, the lower steam content on the cathode side constitutes an additional advantage, as the steam has a far lesser influence on the Nernst voltage. However, the proportion of steam in the gas also has a decisive influence on the proton conduction in the electrolyte, meaning that sufficient steam still has to be fed into the cell on both sides. Similar to PEM electrolysis, the steam is fed to the oxygen side in the proton conducting cell through humidification. In the anodic reaction step on the air side, the protons are separated from the steam molecule and transported via proton conductors to the cathode side, where they are reduced to molecular hydrogen (Table 9.1). Thermodynamically speaking, this process has the same energetic advantages over liquid water electrolysis as the SOEL process. Due to the enthalpy of evaporation through the addition of heat, the Nernst voltage at which steam electrolysis starts is considerably lower than in the case of electrolysis of liquid water.

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There are a few different options for electrolyte composition from the last ten years, with most cells having a proton conductor based on BZY (Ba(Zr,Y,Yb)O(Zr,Y,Yb)O3 ). It is assumed that the proton conduction in this material, due to the incorporation of proton defects as hydroxide ions (OH ), runs according to the following mechanism in the presence of steam [68]:   C OO;.BZY/ ! 2OHO;.BZY/ H2 O.g/ C VO;.BZY/

(9.4)

A major disadvantage of the PCCEL process is the fact that the BZY electrolyte is permeable to oxygen ions as well as protons [69], meaning that the Faraday efficiency of the proton conducting cell is greatly reduced. In the case of BZY-based proton conductors, the proton conduction and the oxide ion conduction improve as the temperature increases. At temperatures well above 600 °C, oxide ion conduction is comparable to proton conduction and makes a decisive contribution to ion transport and electrochemical processes. For this reason, the operating temperature of these cells is limited to approx. 500 to 600 °C. A cermet of Ni and BZY is used as the cathode material for cell production and a perovskite of La0.6 Sr0.4 Co0.8 Fe0.2 O3 or Ba0.5 Sr0.5 Co0.8 Fe0.2 O3 is used for the anode [70]. As nickel is used as the catalyst on the cathode side, small quantities of hydrogen must be continuously fed into the catalytic converter during operation, similar to the SOEL process. Due to the low proton conductivity and the high grain limit resistance in the BZY electrolytes, the cells are designed with the Ni/BZY substrate as a support mechanism and a thin BZY layer as an electrolyte, which corresponds to the cathode-supported cell concept (CSC) of a SOEL cell. The level of technological maturity in PCCEL is less advanced than solid oxide electrolysis. In Europe, the materials for proton conductors and tubular proton conducting cells have been developed by SINTEF for decades [71]. However, as in the case of SOEL, planar cell technology also offers a higher power density. Developments in this area are currently being driven by players from outside Europe. In the meantime, good power densities in industrial CSC prototype cells based on BZY electrolytes are being demonstrated in Japan (Panasonic, Nippon Shokubai [72, 73]) and the USA (Fuel Cell Energy [74]). A planar PCCEL stack is structured in the same way as an SOEL stack. Activities for stack development based on PCC cells can be found, for example, in [74]. Nevertheless, due to its short service life and poor Faraday efficiency, this technology is still a few development steps away from the demonstration phase.

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Other innovative processes for hydrogen production

9.3.1 Steam reforming with carbon capture and utilization Hydrogen can be obtained from a wide range of hydrogen-containing energy carriers by means of steam reforming. The general formula for hydrogen production from alcohols and hydrocarbons through steam reforming is:  y H2 Cx Hy Oz C .x  z/H2 O ! xCO C x  z C (9.5) 2 The reaction is usually carried out at temperatures above 700 °C using a heterogeneous catalyst and on an industrial scale in tubular bundle reactors filled with the catalyst. By the homogeneous combustion of a part of the hydrogen carrier or fuel, the endothermic steam reforming process is supplied with energy from an external source. In this way, on a large scale, the majority of the world’s hydrogen production can be carried out at low production costs of approx. C 2/kg using natural gas (48 percent) without competition, while a further approx. 30 percent of the hydrogen is produced from crude oil, whereas only approx. 4 percent is produced by electrolysis processes and the remaining portion is produced by carbon gasification (Fig. 9.1). Alongside hydrogen, the primary product of steam reforming is carbon monoxide. The mixture of hydrogen and carbon monoxide is called synthesis gas and can be used for many chemical syntheses. If the hydrogen is to be obtained in pure form, the carbon monoxide, which is already partially converted to carbon dioxide in the above-mentioned water-gas-shift reaction during the reforming process, is converted in a water gas-shift reaction in a separate reactor, which is operated at lower temperatures. In addition to the gas washing, pressure swing adsorption systems are mainly used for hydrogen purification. These systems enable the separation of all other gases by adsorption at high operating pressure. The separated gases are released again at a lower operating pressure (desorption). These separated gases contain proportional amounts of carbon monoxide and some hydrogen and can be used to supply energy for steam reforming. The chemical equilibrium of the steam methane reforming (Eq. 9.5 where x D 1, y D 4 and z D 0) is shifted toward the side of the natural gas by the increased operating pressure of the pressure-swing adsorption systems (see Table 9.2). This means that unconverted methane is always present in the separated gas mixture. In fact, the increased operating pressure is a disadvantage, but it is accepted if the hydrogen is to be purified. An alternative to pressure swing adsorption is the separation of the hydrogen by membranes. The most widespread membranes are made of palladium, in which

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Table 9.2 Equilibrium conversion of methane reforming at a steam-to-carbon (S/C) ratio (i.e. the molecular ratio of steam to methane in the feed) of 2.5 at various pressures and temperatures T [°C] 600 700 800

p [bar] 1 71.5 95.4 99.6

5 41.9 70.1 92.6

10 32.3 55.9 82.1

the hydrogen dissolves atomically and moves to the other side of the membrane as a result of the increased pressure, where it recombines to form molecules. However, these membranes are very expensive and have not become widely established on an industrial scale. After combustion, the separated gas mixture contains only carbon dioxide and water. The latter can be easily separated, and the carbon dioxide is reused as process gas or for chemical synthesis. Furthermore, grouting in caverns has been discussed and tested, but possible long-term negative effects are not yet sufficiently understood. If the carbon dioxide is separated and permanently stored by CCS processes, the hydrogen produced is called blue hydrogen. Fig. 9.21 shows a block diagram of a corresponding system that additionally generates an excess of electrical energy. If carbon dioxide is obtained from the air or from industrial processes such as cement production, it can be converted to methane by means of electrolytically produced

Fig. 9.21 Block diagram of a system for methane steam reforming with integrated CO2 separation. (Fraunhofer IMM according to [75])

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hydrogen by the reverse reaction of steam reforming (methanation) and used as a hydrogen carrier in the same way as fossil natural gas. This is possible without conversion of the natural gas network and in a concept that is fully compatible with fossil natural gas and allows a gradual conversion to renewable synthetic methane.

9.3.2 Methane pyrolysis In contrast to the steam reforming described above, methane pyrolysis involves the conversion of methane (from natural gas or biogas) without adding water. The endothermic reaction produces so-called turquoise hydrogen (Fig. 9.2). The methane is decomposed into solid carbon and hydrogen, and no carbon dioxide is produced. At atmospheric pressure, methane is no longer thermodynamically stable above 1000 °C. At increased pressure, this temperature limit increases considerably (to approx. 2000 °C at 10 bar). The thermal decomposition can be achieved well above this temperature without a catalyst, for example at temperatures of approx. 2000 °C in plasma. The production of carbon black by thermal decomposition for the tire industry, for example, is a process that has been established on an industrial scale for about 100 years, albeit with a low efficiency. It has already been used for hydrogen production using natural gas from oil production. As described, the decomposition reaction only takes place at high to very high temperatures. This creates a technical problem, namely that the solid carbon has to be transported out of a very hot reactor in a moving bed, which nevertheless must be gas tight. If the methane pyrolysis is carried out using a catalyst, it is called thermocatalytic decomposition. This reaction already takes place below 1000 °C. The lowest reaction temperatures can be achieved with nickel-containing catalysts. However, the catalyst is usually rapidly deactivated by the carbon produced. One solution to this problem is the use of fluidized bed reactors, in which the catalyst can be moved relatively easily between different reactors. If the intention is to regenerate the catalyst, the carbon has to be oxidized, thereby creating undesired carbon oxides (Fig. 9.22). With regard to the technical maturity of the systems, plasma processes are currently the most advanced. However, they are mainly aimed at the production of carbon. Hydrogen production is currently not economically viable, mainly due to the high market price of gray hydrogen. It is only used as an energy source for the process. If regenerative electricity is used to generate the plasma, the plasma processes have a high potential to enable the production of turquoise hydrogen in large quantities in the future. The resulting carbon can then be used in a variety of technological processes, which could compensate for the higher manufacturing

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Fig. 9.22 Block diagram of a system for the thermocatalytic decomposition of natural gas with integrated catalyst regeneration. (Fraunhofer IMM according to [76])

costs of the hydrogen. If the energy supply of the decomposition process originates from renewable sources, the ecological footprint is reduced considerably (Fig. 9.2). The projected production costs of hydrogen through the thermal or thermocatalytic conversion of natural gas are currently only slightly higher than the costs of approx. C 2/kg resulting from steam reforming at approx. C 3/kg. In summary, the handling of the solid product in the thermal decomposition of methane and the large amount of carbon formed on the catalyst during thermocatalytic decomposition remain the main technical challenges to be tackled.

9.3.3 Photocatalytic systems In another process, sunlight is used to directly produce green hydrogen by allowing semiconductors to absorb the light and then catalytically split water on their surface. This is referred to as a photoelectrochemical (PEC) or photocatalytic process, because the charge carriers are generated directly in the semiconductor, which then provide for the reduction to hydrogen or oxidation to oxygen [77]. There are only a few materials that are suitable for both coupled processes, which is why two dif-

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ferent semiconductors are usually combined for oxygen and hydrogen production. This means that each can be better adapted to the different requirements and, in addition, improved with specific co-catalysts for a greater level of activity. For the future, the direct PEC splitting of water using light promises simple structures with low system complexity. However, in practice, the technology is at an early stage: In addition to the search for new materials for the individual reactions, there are only isolated studies looking at upscaling the cells, and actual setups to determine the overall efficiency of the process chain from solar radiation energy to hydrogen often suffer from low levels of energy efficiency [78, 79]. The Fraunhofer-Gesellschaft is involved as part of its internal anticipatory research, aiming to build bridges between scientific theory and application for a possible technology of the future. Several concepts are being pursued: With the active cooperation of Fraunhofer ISE, a multi-layered cell structure with highly active III–V semiconductor materials based on gallium, indium and rhodium, among others, has been developed. This cell has been able to demonstrate solar-to-hydrogen efficiencies of 19 percent—the highest value achieved to date [80]. A current project aims to scale these cells to surface areas of up to 36  36 cm2 . In a second approach taken by the Fraunhofer Institutes IKTS, IST and CSP, on the other hand, robust and low-cost materials with an average efficiency of 10 percent are used. They are constructed economically in integrated tandem systems by means of coating processes established in the field of photovoltaics. Moreover, they are built to be inherently scalable. Cells with an active surface area of as big as one square meter will be created here. In general, in a tandem cell, the sunlight passes through a semi-transparent anode that absorbs the short-wave light and hits a cathode that absorbs the long-wave light. If both layers are applied to the opposite sides of a glass substrate and are electrically connected (Fig. 9.23), hydrogen is released on the cathode side and oxygen is released on the anode side when the cell is exposed to sunlight. A thin film of water covers the surfaces [81], which may be circulated if necessary. This structure allows higher efficiencies than separated half-cells, and automatically results in important physical separation in order to avoid the formation of explosive oxyhydrogen gas and expensive separation steps. For such a tandem cell with a high degree of efficiency in the overall system, the semiconductors used must be precisely matched to each other: The power per unit of surface area is limited by the less active single electrode, and it is more favorable if the same electrolytes and a similar pH value are used in the water for both half-cells. Such adaptations of semiconductor properties are often achieved by chemical composition, doping, or by using a specific structure and morphology. The process conditions during sputtering and possible post-treatment steps can be used to influence specific features of the microstructure of the separated layers.

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Fig. 9.23 Structure of a tandem cell, the central element of a PEC unit. (Fraunhofer IKTS)

Fig. 9.24 (a) Targets for the sputtering process of different PEC semiconductors and (b) a layer deposited with them; (c, d) layers with different structures in the scanning electron microscope. (Fraunhofer IKTS)

In order to use carefully coordinated materials, semiconductor materials are being developed and manufactured at Fraunhofer IKTS as targets for the generation of these layers (Fig. 9.24). The investigation of large PEC cells poses a problem: How can we get the sunlight into the laboratory? For a reproducible measurement, it is very important to accurately replicate natural light conditions. Fraunhofer CSP therefore operates

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Fig. 9.25 Test bench for PEC cells. (Fraunhofer CSP)

a test stand for large PEC cells with LED solar simulators, which produces a homogeneous light field of 20 cm  20 cm with high spectral quality and is used for the examination of the electrode materials and cells. A 2 m2 solar simulator is to be used in a future expansion stage. The PEC technology for the production of green hydrogen is at a very early stage of its development. Key questions about efficiency, scalability and longevity still need to be addressed. The Fraunhofer-Gesellschaft is conducting research on this in various projects and also contributes its expertise in the development of modular systems in order to help a promising technology go from laboratory scale to a possible application.

9.3.4 Biological procedures In addition to the above-mentioned processes for hydrogen production, hydrogen can be produced from biologically available materials or directly through biological processes. Biomass gasification is already a very advanced process used on an industrial scale. In such a thermochemical conversion (partial combustion) of biological material at temperatures of up to 900 °C, an oxidizer—such as steam, air and/or oxygen—produces hydrogen, carbon monoxide, but also CO2 , methane and steam. However, with prices of approx. C 7/kg of hydrogen, the costs of the process are significantly higher than the costs of producing gray hydrogen [82]. In contrast to biomass gasification, the use of photosynthetic or (photo)fermentative microorganisms offers a purely biological method for hydrogen production. Some prokaryotic agents of these microorganisms (e.g., bacteria) and also a few eukaryotic single cells (e.g. green algae) form hydrogen as a metabolic product.

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Table 9.3 Hydrogen production pathways by microorganism [84] Dark fermentation Anoxygenic photosynthesis Oxygenic photosynthesis

Energy source Electron source Organic molecules (e.g. acids and sugars) Light Acids, H2 S

Known organisms Clostridia, enterobacteriaceae Purple bacteria

Light

Cyanobacteria, single-cell green algae

Water

By analogy with electrolysis and fuel cells, hydrogen serves as a natural storage mechanism and source of electrons in the organism [83]. Basic metabolic pathways for biological hydrogen production are summarized in Table 9.3. The enzyme hydrogenase plays a key role in the biological production of hydrogen. Depending on the metal content, a distinction is made between [Fe], [FeNi] and [FeFe] hydrogenases (Fig. 9.26; [85]). However, [FeFe] hydrogenases are by far the most efficient systems for hydrogen production [86]. There are numerous metabolic processes in which hydrogen is formed under anoxic conditions, e.g., by the intestinal bacterium Escherichia Coli [87] or clostridia [88]. Hydrogenases in prokaryotic microorganisms in particular may become more important for the biological production of hydrogen in the future. These are able to use wastewater and nutrients as an energy source for hydrogen formation. In the future, purple bacteria may also be used for photofermentative hydrogen formation [89] and cyanobacteria may be used for photobiological hydrogen formation [90]. In this context, it is remarkable that the hydrogenases of algae, such as the green algae Chlamydomonas reinhardtii, enable photosynthetic hydrogen formation.

Fig. 9.26 Active centers of [FeFe] hydrogenases (left) and [FeNi] hydrogenases (right). (Color code: gray: carbon, yellow: sulfur, red: oxygen, blue: nitrogen, brown: iron, turquoise: nickel) [91]

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Although theoretically, the energy conversion efficiency of these hydrogen production systems is around 10 percent, the biological hydrogen production is usually linked with other metabolic pathways [92]. This reduces the conversion efficiency, meaning that hydrogen is usually not freely accessible in large quantities. The biological systems are also often sensitive to oxygen, which usually leads to the inhibition of the enzymatic system, and thus to the cessation of hydrogen formation. However, the yield of free hydrogen can be increased and the direct biological utilization inhibited through targeted genetic manipulation of the organisms [93]. There are also approaches to reduce the oxygen sensitivity of these systems [94]. In addition to hydrogen formation through hydrogenases, hydrogen is primarily produced as a by-product during the natural nitrogen fixation (conversion of atmospheric nitrogen to ammonia) by the enzyme nitrogenase [95]. These biological processes are still at a relatively low technology readiness level (TRL), making them the subject of research in more theory-based projects. It will take a great deal of time before they are ready for use on an industrial level.

9.4

Summary and outlook

CO2 -free water electrolysis, based primarily on renewable energies, will become the key technology for sector coupling and the third phase of the energy transition in Germany. From a cost perspective, green hydrogen cannot yet compete with conventional gray hydrogen. However, the reasons for this are not so much related to the technology involved, but are mainly due to the unsuitable way that the energy market is designed. With rising CO2 prices, cost reductions in electrolysis production and a growing supply of cost-effective electricity from wind and solar energy worldwide, green hydrogen is becoming more and more competitive. Blue or turquoise hydrogen, i.e. non-renewable, but CO2 -free or low-CO2 hydrogen, is currently being discussed as an interim option. This is because the necessary electrolysis capacities can neither be built up at the appropriate speed, nor will the expansion of renewable energies be sufficient in the next few years. How long that interim period will last remains the subject of debate. It must also be stressed that the process routes of blue and turquoise hydrogen production have also not yet been widely tested and are not yet available, and that the long-term consequences of CCS technology and the associated CO2 storage remain difficult to estimate. It is not yet clear to what extent the low-temperature technologies (alkaline electrolysis or PEM electrolysis) will establish themselves on a large scale. Whereas

9.4 Summary and outlook

245

alkaline electrolysis, the longest-used and most advanced technology, is the established standard today, advances are being made in the (even more expensive) field of PEM electrolysis, which promises improved flexibility, more compactness and greater efficiency at the same power density, with the goal of reducing costs through mass production. In the short term, alkaline electrolysis will continue to account for the largest share of electrolysis capacities, but PEM electrolysis is expected to become increasingly significant, especially in the case of small and medium power outputs. In the medium to long term, high-temperature electrolysis will also become established on the market, provided that production costs can be drastically reduced, and the service life continues to increase. The pure material costs are significantly lower than PEM electrolysis. Especially in applications where existing waste heat can be used, the advantages of this technology in terms of efficiency will come to the fore. Alkaline membrane electrolysis remains another pertinent option. This combines the advantages of classical alkaline electrolysis with the compactness and improved efficiency of PEM electrolysis. However, some developments and cost reductions are still needed in this regard to make the technology competitive. Blue and turquoise hydrogen act as bridging technologies and are expected to play a greater role abroad (at coal and natural gas sites as well as CO2 or carbon sinks). They will fulfill their role as hydrogen imports in Germany on a temporary basis, but the operation of such plants in Germany seems unlikely. Photocatalytic and biological processes are still at an early stage of development and cannot yet be fully evaluated in terms of their potential marketability. In the near future, hydrogen will play an increasing role in the energy system in Germany, especially in sector coupling. On the consumer side, mobility (air, ship, heavy goods traffic) and sustainable process routes will be the biggest drivers in industry. In industry, a reduction in CO2 emissions can be achieved in the short term by replacing gray hydrogen with green hydrogen in refineries and ammonia production. The challenges and opportunities of the industrial use of hydrogen are described in more detail in Chap. 5. However, the increasing demand for hydrogen will still largely have to be met through gray hydrogen, at least in the early stages. In the medium term, it will be covered by domestic green hydrogen and hydrogen imports (blue, green and possibly turquoise). In the long term, the goal will remain to use only CO2 -free, primarily green hydrogen.

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Fuel cell technologies

10

Ulf Groos Fraunhofer Institute for Solar Energy Systems ISE Carsten Cremers Fraunhofer Institute for Chemical Technology ICT Laura Nousch  Christoph Baumgärtner Fraunhofer Institute for Ceramic Technologies and Systems IKTS Abstract

Fuel cells are energy converters that transform the chemical energy of a fuel into electrical and thermal energy. They enable cogeneration of heat and power and thus have the potential to become a vital component of hydrogen-based energy supply. This chapter analyzes the functionality and properties of various types of fuel cell.

10.1 Introduction Fuel cells are energy converters that transform the chemical energy of a fuel into electrical and thermal energy. As such, they enable cogeneration of heat and power. Power generation via fuel cells creates opportunities in many areas. The cells’ potential efficiency is high when compared to the combustion engine and the energy density values of their fuels are higher than those of batteries. In addition, fuel cells help to avoid local pollutant emissions and a wide range of fuels are available. As a result, fuel cell systems have many possible areas of application. Whether in stationary energy production, or as a mobile energy supply for an electrical drive unit, fuel cells have the potential to play a significant role in global power supply solutions. © Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_10

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Fuel cell systems can achieve high efficiency rates of over 50 percent, and if they are powered by renewable hydrogen, they are emission-free. If the hydrogen used is non-renewable but produced at one central location, they are emission-free at least at the local level. In the case of fuels like methane and methanol, the cells offer a sharp reduction in emissions compared to combustion engines. The systems are quiet and low maintenance. Fuel cells can be used in a wide range of applications, ranging from output capacities of 1 watt to multiple megawatts:  1 W to 1 kW: camping, construction sites, portable generators, drones, toys  1 to 10 kW: heat and power cogeneration for household energy, forklifts, emergency generators, telecommunications, auxiliary power units (APU) for land vehicles  10 to 100 kW: vehicle range extenders, airport ground handling, stationary power generation and heat and power cogeneration, auxiliary power units (APUs) for aircraft  50 kW to multiple MW: fuel cell power trains for cars, trucks, buses, trains, boats, ships, aircraft; stationary heat and power cogeneration As in a combustion engine, the power converter in a fuel cell system can be dimensioned separately from the energy storage device. This allows power output and operation time to be developed to fit the application in question. Each individual fuel cell consists of a bipolar plate (BPP) with an anode and a cathode side, along with a membrane electrode assembly (MEA). Individual fuel cell technologies differ depending on the particular electrolytes used, as these determine the operating temperature level. The operating temperature, in turn, determines the types of fuel that can be used. If multiple individual cells are electronically connected in series, stacked on top of each other and supplemented with balance-of-stack (BOS) components such as end plates, current collectors, distributor plates and monitoring units, they form a fuel cell stack. As a rule, the individual cells of a stack are supplied with fluid in parallel. The number of individual cells defines the total voltage level, and their active surface area determines current. Together, the number of cells and their surface area allow variation in power output. Fuel cell systems are based on fuel cell stacks, together with the support of balanceof-plant (BOP) elements like air compressors, humidifiers, hydrogen supply, purge valves, thermal management modules and power electronics. Membrane fuel cells use a solid-state, ion-conducting membrane as an electrolyte. In a polymer electrolyte membrane fuel cell (PEMFC), the membrane electrode assembly is made up of a very thin catalyst-coated membrane (CCM)

10.1

Introduction

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Table 10.1 Overview of various fuel cell technologies Technology Advantages LT-PEMFC High power density Long service life Good start-stop and cycle stability DMFC Good start-stop and cycle stability High energy density (methanol) SOFC High efficiency High tolerance of contaminants Long service life HT-PEMFC High tolerance of contaminants Moderate startup time MCFC

AEMFC

Wide range of capacity CO2 management High efficiency when used with CO2 -based fuels H2 as a by-product Precious-metal-free catalysts

Disadvantages Low tolerance of contaminants Complex water management system Low efficiency Low power density Medium power density Low start-stop and cycle stability Long startup time Medium start-stop and cycle stability Medium power density Low power density Low start-stop and cycle stability Long startup time

TRL 9

Low power density Short service life to date

3

9 8

8

8

made of polymers with a gas diffusion layer (GDL) on each side. Bipolar plates (BPP) are the most common means of supplying reaction gases and cooling the stacks. Other types of membrane fuel cells include anion exchange membrane fuel cells (AEMFC) and ceramic solid oxide fuel cells (SOFC). Alkaline (AFC), phosphoric acid (PAFC) and molten carbonate fuel cells (MCFC) come under a different category. These types of fuel cell use a liquid electrolyte that is adsorbed to a ceramic matrix and the electrode structures. Current high-temperature polymer electrolyte membrane fuel cell (HT-PEMFC) models fall under this cell type. The chemical interaction between phosphoric acid and polybenzimidazole within the electrolyte membrane is so strong that these can be treated as one homogeneous membrane. In the electrodes, however, phosphoric acid is adsorbed only as a liquid. HT fuel cells use solid and liquid electrolytes that need to reach 600 °C to achieve sufficient ionic conductivity. Oxygen ions (O2 ) or carbonate ions (CO2 3 ) are conducted through the electrolytes. This has the added advantage that carbon monoxide can be converted within the cell itself. This allows a wide choice of fuels. Various hydrocarbon-based fuels (liquid and gas) from conventional mining and renewable sources (e.g., biogas) can be used, up to and including ammonia (NH3 ). High-temperature fuel cells can reduce system costs and increase system efficiency (Fig. 10.1).

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Fig. 10.1 Fuel conversion stages in various fuel cell types and their influence on fuelprocessing complexity. (see [6])

High operating temperatures allow extraction of useful heat from the exhaust systems, meaning high-temperature fuel cell systems are perfectly positioned to play a major role in stationary generation of electricity and heat (cogeneration or CHP). The high part-load efficiency of SOFC systems distinguishes them from other converters such as gas-powered engines. However, there are drawbacks for sectors such as mobility, as SOFCs’ energy- and time-intensive warm-up phase, along with their limited number of thermal cycles, make them less suited to applications involving high load flexibility.

10.2 Low-temperature polymer electrolyte membrane fuel cells 10.2.1 Overview In PEMFCs, the hydrogen molecule is split into two protons and two electrons on the anode side. The electrons follow an external circuit to the cathode and can perform electrical work in the process. The protons are conducted through the membrane electrolyte to the cathode, closing the electric circuit. At the cath-

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Low-temperature polymer electrolyte membrane fuel cells

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ode, they combine with (atmospheric) oxygen and electrons to form water, which is discharged from the fuel cell as increased humidity. Anode: 2H2 ! 4HC C 4e Cathode: O2 C 4HC C 4e ! 2H2 O Total: 2H2 C O2 ! 2H2 O

10.2.2

Stack components

With the system architecture currently available, membrane electrode assemblies operating in an automotive fuel cell achieve power densities of approximately 1.5 W/cm2 and current densities of 2 A/cm2 at 675 mV. Platinum loading typically reaches 0.25 to 0.4 mg/cm2 for the cathode and anode combined. The reactions that take place in fuel cells are enabled by electrochemical catalysts. Catalyst nanoparticles are deposited onto carbon particles (catalyst supports) with varying levels of porosity by means of wet chemistry techniques. Platinum (Pt) or Pt alloys are used as catalysts. Researchers are currently investigating coreshell architectures and complex alloys, as well as catalysts that are not based on precious metals. To adapt catalysts’ long-term stability to particular applications, various carbon particle shapes are being used for catalyst support, as well as different degrees of graphitization. The catalyst powder is mixed with the ionomer (for proton transport) and a solvent to form a paste or ink. A coating process is then used to turn this mixture into a catalyst layer (Fig. 10.3). The composition of the catalyst layer affects operating behavior. When a low current is applied, high ionomer content leads to improved

„ Dimensions from nanoscale to macro-scale „ Nano-scale: proton transport, catalyst particle, catalyst support pores „ Micro-scale: ionomer distribution, agglomerate, catalyst layer morphology

„ Time scale from ns to hours „ Proton & electron transport „ Fluidics & diffusion „ Degradation

Catalyst Particle 2 – 8 nm Catalyst Support 30 – 60 nm

Catalyst Layer 5 – 15 μm

„ Macro-scale: Flow field

Catalyst Loading 0.02 – 0.4 mgPt /cm² Carbon Fiber Ø 10 μm Gas Diffusion Layer (GDL) 100 – 200 μm O2 Polymer Electrolyte Membrane (PEM) 8 – 50 μm 30 cm

H2

Fig. 10.2 Membrane electrode assemblies (MEA) in fuel cells present a multiscale problem. (Fraunhofer ISE)

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Fig. 10.3 Manufacturing a membrane electrode assembly (MEA). (Fraunhofer ISE)

Fig. 10.4 Current density at two operating points with different Pt loading levels (on the cathode) and different ionomer content levels. The MEA was produced by a screen-printing process, as part of the DEKADE project, which was funded by the German Federal Ministry of Education and Research (BMBF). (Fraunhofer ISE)

performance due to low proton contact resistance at the boundary between the electrode and the membrane (Fig. 10.4). Conversely, low ionomer content allows improved oxygen diffusion, increasing power output when high currents are applied.

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Low-temperature polymer electrolyte membrane fuel cells

259

Slot-die coating is the primary method used on an industrial scale today, as this makes it possible to achieve even, high-throughput roll-to-roll coating (R2R). However, research laboratories often use sprays coatings, as this coating method is simple and cost effective. One currently well-established method involves coating a decal foil and then transferring the dried catalyst layer onto the polymer electrolyte membrane (PEM) via hot pressing or calendering. Direct coating of the PEM is already being carried out in some industrial plants. The combination of the PEM and the catalyst layer on the anode and cathode side is known as a catalystcoated membrane (CCM).

DEKADE project: German-Canadian fuel cell cooperation: diagnosis and development of components for automotive fuel cells

Fig. 10.5 Manufacturing a CCM via screen printing. (Fraunhofer ISE)

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Scientific objectives  Development of new, sustainable catalyst systems for LT-PEMFCs, based on stable carrier structures with optimized platinum-carrier interaction  Development of new composite membranes with nanofiber reinforcement, based on the direct membrane printing process developed by the participants, with the aim of producing an optimal membrane electrode unit with reduced membrane thickness and improved operating stability (Fig. 10.5)  Modeling of the membrane electrode units to optimize their structure and component composition  Innovative electrode structuring with through-plane gradients to achieve optimal ionomer and Pt distribution Project partners: Fraunhofer ISE, University of Freiburg, Greenerity GmbH Funded by the German Federal Ministry of Education and Research (BMBF) Implementation: January 1, 2017 to December 31, 2019 Contact: Ulf Groos, head of the Fuel Cell Systems department, Fraunhofer ISE Information: https://www.ise.fraunhofer.de/en/research-projects/ dekade.html

The structures of the flow field facing to the microporous catalyst layer are too coarse for gas molecules, so in order to enable a good gas supply, gas diffusion layers are applied to the CCM. The gas diffusion layers are composed of nonwoven carbon-fiber materials or meshes with a thickness of 100 to 300 m, which are equipped with a fluorinated polymer layer to make them hydrophobic. Typically, a microporous layer (MPL) 20 to 50 m thick and consisting of hydrophobic carbon particles is then applied to the side facing the electrode. These microporous layers assist with water management within the PEMFC. The active area of the catalyst-coated membrane (CCM) is cut out via punching. To make it possible for machines to handle the CCM and to enable the creation of seals between the CCM and the gas ports and bipolar plates, polymer reinforcement frames are laminated onto the membrane. These frames can be made of materials such as polyethylene naphthalate (PEN). Finally, the gas diffusion layer is fixed to each side of the membrane.

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Low-temperature polymer electrolyte membrane fuel cells

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Flow fields incorporated into bipolar plates distribute the reaction gases over the active surface of the membrane electrode assembly. The bipolar plates distribute gases, conduct electrical currents between cells, provide a gas-tight seal separating the anode and cathode spaces and act as a seal to shield against cooling. Bipolar plates can be made from graphite-based or metallic materials. Compound bipolar plates result in greater stack heights when compared to metallic plates. As such, they must contain conductive, graphite-based filler materials to ensure the bipolar plates can conduct electricity. The main advantage is their high corrosion resistance. Metallic plates have good mechanical strength and are easy to machine. However, they do present some disadvantages, for example, metal surfaces tend to form oxides and their corrosion resistance is not as good. Consequently, an additional surface coating must be applied to ensure a low level of electrical contact resistance between the plate and its neighboring GDL in the long term, and to prevent possible contamination through corrosion. Graphite coatings, precious-metal films, metal nitride/carbide films and conductive polymer films are often applied to the surfaces of metallic bipolar plates. Manufacturing a stackable bipolar plate unit involves incorporating the flow field, cutting out and coating the bipolar plates, and finally welding together two plates and applying a seal. Manufacturing bipolar plate production requires enormous precision from the forming, cutting and joining technology. At present, the forming technology can produce bipolar plates from sheets 0.07 to 0.1 mm thin with channels up to 0.8 mm deep.

10.2.3 System components To enable a fuel cell stack to provide electrical power, additional balance-of-plant (BOP) components are required. These can typically be divided into three areas:  Process air supply (cathode circuit)  Hydrogen supply (anode circuit)  Thermal management (cooling circuit) Each circuit consists of specific components, as described below (Fig. 10.6). As a rule, the most important components in the cathode circuit consist of a compressor to draw in and compress air from the external environment, a cooler, and a humidifier. The compressor is the component that consumes the most power under standard operating conditions. Upstream from the compressor, there is usu-

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Fig. 10.6 Balance-of-plant components in a fuel cell stack. (Fraunhofer ISE)

ally an air filter that removes dust particles and any corrosive gases from the incoming air. The anode circuit is made up of a recirculation pump or a similar device, a mechanism for water separation, and a blow-off or purge valve. Recirculation ensures a high level of hydrogen utilization, as well as sufficient gas flow to eliminate condensing moisture from the fuel cell. Since (atmospheric) nitrogen and other inert gases can diffuse from the cathode to the anode, these must be regularly removed via a purge valve. This typically happens at timed intervals dependent on the cell’s cumulative power generation. A condensation unit ensures that excess water produced is removed from the anode gas flow. The gas flow ejected through the purge valve will still contain some hydrogen. However, in vehicles, this flow is fed into the cathode exhaust in most cases, for reasons of space. A measurement technique developed by Fraunhofer ICT and certified by the testing agency TÜV Süd AG allows transient monitoring of the H2 concentration in the exhaust gas, in order to ensure the threshold values for safe operation are not exceeded. The cooling circuit consists of a coolant pump, heat exchangers and a device for regulating the coolant flow and stack temperature. Generally, the coolants used are frost-resistant and cannot conduct electricity. Every fuel cell system has a starter and buffer battery. This ensures that during the startup process, the crucial peripheral components of the system can start

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Low-temperature polymer electrolyte membrane fuel cells

263

running even before the fuel cell itself builds up sufficient power. In vehicles, the buffer battery covers extreme load peaks, which prevents fuel cell degradation caused by large gradients in potential or insufficient gas supply. Furthermore, the battery can recover energy from regenerative braking and so increase overall operational efficiency, while reducing mechanical wear and tear during braking. The power electronics adapt the electrical parameters to electrically couple the fuel cell with the battery and electric engine in the powertrain. Compressed gas tanks are used to store hydrogen in vehicles. Global standards for tank pressurization levels have been established: 700 bar for cars; 300 to 350 bar for buses and trains. For trucks, various solutions are under discussion, ranging from compressed gas tanks with pressures of 300, 350 or 700 bar to liquid or cryo-compressed hydrogen tanks. As a rule, multiple cylindrical tanks are used, connected together via valve switches and tubing.

10.2.4

Operational management

A fuel cell’s performance can be mapped based on its current-voltage characteristic (Fig. 10.7). This shows how the individual cell or stack’s current responds to to a particular operating voltage. For a better comparison, current density, meaning current divided by active area, is often used as an indicator. The electrochemical reaction is heavily dependent on local operating conditions within the fuel cell. The concentration of reaction gases is high at the inlet point but decreases along the gas channel on the way to the outlet. The reaction simultaneously generates heat, meaning that usually—depending on the coolant supply—the local operating temperature increases between the gas inlet and outlet. Furthermore, this reaction produces water, resulting in increased gas humidity (Fig. 10.8). The operating voltage of the stack, and consequently also its power output and efficiency, depends on its material properties and geometry, as well as the following parameters:  Stack current: As shown by the current-voltage characteristic, current increases when cell potential is lowered.  Anode and cathode stoichiometry: Higher stoichiometry means increased reaction gas concentration, especially at the gas outlet of a cell, which raises current density to a moderate level. On the other hand, the demand placed on the compressor, anode recirculation pump and humidifier is higher.

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Fig. 10.7 Current-voltage characteristics of various membrane electrode assemblies with different levels of platinum content (mPt ) and ionomer/carbon carrier (I/C) ratios. It is evident that higher platinum content increases power output, while a moderate I/C ratio delivers optimal results. (DEKADE, Fraunhofer ISE)

Fig. 10.8 Typical current density profile of an LT-PEMFC. This graphic depicts the characterization of an along-the-channel test cell produced by Fraunhofer ISE as part of the DEKADE project. The steep current ramp at the cathode inlet is due to the low proton conductivity of a dry membrane and then the humidification of the membrane due to the strong electro-chemical fuel cell reaction with high oxygen concentration. The oxygen concentration and current density decrease simultaneously along the length of the air flowfield channels. (DEKADE, Fraunhofer ISE)

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Low-temperature polymer electrolyte membrane fuel cells

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 Gas pressure at anode and cathode inlets: As a rule, pressure increases cell power output, but it also leads to higher compressor losses in the system.  Gas humidity at anode and cathode inlets: Gas humidity is an important variable in the cell because cell membrane resistance decreases where humidity is higher. At high humidity levels, water can block up the cell, causing output to fall further.  Stack temperature, usually controlled via cooling liquid inlet temperature and cooling liquid flow: As a rule, temperature increases cell power output, due to a rise in electrode activity. However, excessively high temperatures cause the membrane to dry out, leading to degradation.  Anode gas composition and speed: Hydrogen gas is usually circulated around the anode so that the fuel is consumed to the greatest possible extent. Over time, this leads to an accumulation of inert gases in the anode circuit. Gas flow affects desorption of water droplets, gas mixing and the homogeneous supply of hydrogen to the anode.  Dynamic effects that may continue over a long period, e.g., membrane humidity, saturation of the pores with water, catalyst contamination and platinum oxidation. The challenge for operational management and system technologies in a PEMFC lies in how to transport reactants to individual cells so that each cell is supplied on an equal basis. An over-stoichiometric supply leads to an equivalent rise in air compressor performance and a corresponding reduction in system efficiency. On the other hand, gas starvation in the individual cell causes intense degradation and accelerates the aging process. During cooling, it is necessary to avoid rises in local temperature at (individual) cell level, as this can cause membrane damage. Temperatures must be kept within intended levels. The PEM requires high humidity to ensure high proton conductivity. At the same time, condensation can block pores in the catalyst layer, the microporous layer or the gas diffusion layer. This can lead to local gas starvation of reactants to the cell, with a significant rise in local degradation. Water management therefore plays a critical role here. As the parameters influence each other and combine in complex ways that can differ in every stack, manufacturers specify the respective suitable operating conditions for a certain current point. This means that as a rule, all parameters are tailored to the individual stack current. It is important to note that some operating points that produce higher power output from the cell can lead to an elevated degradation rate.

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10.2.5 Service life and degradation Various processes contribute to PEM fuel cell degradation. These occur at different speeds, depending on operational management. The following operational modes and events reduce service life:  Highly dynamic operation. For this reason, a small battery storage device is often used to intercept extremely dynamic fluctuations in power demand.  Repeated start-stop cycles, especially during air/air situations (air on anode and cathode), which occur after long downtime periods, for example  High voltages, high temperatures and dry operation  Undersupply of hydrogen or air The complex process of quantifying these influences is currently the focus of various research projects. In reality, fuel cells operated under stationary conditions in a laboratory experience a degradation rate of below 10 µV/h. As such, operating hours in the many tens of thousands are a realistic prospect. For stationary systems, there are reports of service lives of 40,000 hours, with a decline in performance of below 10 percent. However, even fuel cells that power buses have already demonstrated operating periods in excess of 20,000 hours. Contaminants from incoming air and hydrogen can clog up the catalyst and such cause degradation. Sulfur-based gases, in particular, cause irreversible damage. Carbon dioxide and carbon monoxide can reduce performance, but this is reversible.

10.3 High-temperature polymer electrolyte membrane fuel cells 10.3.1 Overview High-temperature polymer electrolyte membrane fuel cells (HT-PEMFC) work on the same principle as LT-PEMFCs, only at higher operating temperatures, typically of 160 to 180 °C. Their tolerance of impurities, especially in fuel, is therefore significantly higher than that of LT-PEMFCs. They can tolerate up to 3 vol% CO in fuel gas [1]. For this reason, HT-PEMFCs are particularly suitable for applications where fuel cells are powered by reformed hydrocarbons or alcohols. Using HTPEMFCs in combination with methanol steam reformers has proven particularly

10.3

High-temperature polymer electrolyte membrane fuel cells

267 1.6

0.75

1.2

0.70

1.0 0.65 0.8 0.6

0.60

stack power / kW

average cell voltage / V

1.4

0.4 Ref 1 (55vol.% H2; 0.5 vol.% CO; 5 ppm H2S)

0.55

λ A = 1.4, T = 165 °C λ A = 1.7, T = 165 °C λ A = 1.4, T = 175 °C

0.50 50

100

150

200

250

0.2 0.0 300

350

400

450

500

current density / mA cm-2

Fig. 10.9 Testing how the operating conditions of anode stoichiometry and operating temperature affect the operational performance of a commercial HT-PEMFC stack of type Serenergy S165L-35 with NATO F-34 reformate as a substitute; this test was carried out as part of the EDA project IAPUNIT. Increasing anode stoichiometry and/or operating temperature makes it possible to achieve a nominal power of 1.5 kW using this fuel gas

effective, as the gas flow produced by the reformer can be fed in directly without further purification. There are many such combined systems in development or already available on the market. These range from 55 W portable energy supply devices to range extenders for battery-powered cars and commercial vehicles (Fig. 10.9).

10.3.2 Stack components As previously mentioned, the HT-PEMFC resembles the LT-PEMFC in its basic structure. In most commercial stacks, however, graphite-based bipolar plates are used, as these can better withstand highly corrosive conditions at temperatures of up to 180 °C and potential light wetting with phosphoric acid. A major difference between the HT-PEM fuel cells and the LT-PEMFCs is the type of membrane electrode assembly used. In the current state-of-the-art technology, polybenzimidazole (PBI) membrane are used, with the addition of phosphoric acid as an electrolyte.

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Ionic interaction between the weakly alkaline PBI and the phosphoric acid activates proton conductivity, which is higher than that of a conventional PAFC. In addition, the membrane can be made much thinner than the ceramic matrix used in the PAFC. During cell activation, phosphoric acid is deposited on the catalyst layer, among others. In HT-PEMFCs, the catalyst is typically applied to the gas diffusion layers (GDL), where it is mainly bound with PTFE. Using PBI as a binder leads to excessive phosphoric acid deposition and so to mass transportation losses when the current is high.

HT-Linked project: High-performance, aging-resistant HT-PEMFC membrane electrode assemblies based on new connection methods for catalysts, carriers and proton conductors

Scientific objectives The aim here is to improve performance and stability of membrane electrode assemblies for HT-PEMFCs by modifying the connections between catalyst and carrier, catalyst system and electrolyte, and electrode and membrane. In this project, Fraunhofer ICT investigated carrier modifications aimed at improving the electrolyte connection, as well as methods for testing and evaluating HT-PEMFC membrane electrode assemblies. Project partners: Freie Universität Berlin (free university of Berlin), Fraunhofer ICT, Technische Universität Berlin (technical university of Berlin), University of Freiburg, University of Stuttgart, Freudenberg Sealing Technologies, Fischer Eco Solutions, Riva Batteries Funded by the German Federal Ministry of Education and Research (BMBF) Implementation: October 1, 2015 to March 31, 2019 Contact: Prof. Christina Roth, FU Berlin (currently University of Bayreuth), coordinator Dr. Carsten Cremers, Fraunhofer ICT, deputy coordinator

The catalysts used correspond to those currently used in the LT-PEMFC. Studies conducted in the HT-Linked project have shown that carbon support corrosion does not exponentially increase alongside temperature, as had been assumed (Fig. 10.10).

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High-temperature polymer electrolyte membrane fuel cells

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Fig. 10.10 Investigation of corrosion in a 40 percent Pt/C catalyst using differential electrochemical mass spectrometry (DEMS) under LT-PEMFC conditions (left) and under HAT-PEMFC conditions (right) [2]

10.3.3 System components An important characteristic of HT-PEMFCs is their high proton conductivity, which can occur even without water thanks to the Grotthuss mechanism. It is not generally necessary to include a humidifier in the system structure. These days, most HT-PEMFCs are used in systems with an upstream fuel reformer. Systems featuring inline reforming always differ in structure from those powered by pure hydrogen. This difference will always apply to fuel cells in cases where reformate is fed directly into the stack as fuel gas, in place of pure hydrogen production within the system via a separation process. Due to the high proportion of inert gases present, closed-loop fuel cycles are generally not possible here. As the anode exhaust gas always contains residue from unconsumed hydrogen and other flammable gases, it must be burned off before it exits the system, for safety reasons. In systems featuring allothermal reformer processes, this burn-off should ideally take place in the reformer’s heating system. In terms of fuel inlets, HT-PEMFC systems have the advantage over LT-PEMFC systems in that there is no need for intense purification to remove carbon monoxide from the reformate. To reduce

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CO content in the fuel gas to tolerable levels, a simple water-gas shift reaction will suffice. In the case of a methanol steam reformer working at up to 300 °C, no further measures are required.

IAPUNIT project: Development of an innovative auxiliary power unit for military purposes based on high-temperature PEM fuel cell and reforming technology for military logistic fuels (Phase I)

Scientific objectives Developing a fuel cell APU for armored wheeled vehicles like the GTK Boxer. Phase I of the project saw the development and validation of the central components: fuel desulfurizer, fuel processor and fuel cell. In the process, Fraunhofer ICT developed operating strategies for commercial HTPEMFC stacks in this type of systems and evaluated possible forms of packaging. The planned second phase is set to focus constructing and testing an integrated system with power output of 8 kW.

Fig. 10.11 Flowchart showing a simplified version of the basic IAPUNIT system structure

Project partners: Fraunhofer ICT (Germany), AVL List GmbH (Austria), Catator A.B. (Sweden), Jožef Stefan Institute (Slovenia), National Institute of Chemistry (Slovenia), Eindhoven University of Technology (Netherlands), Graz University of Technology (Austria)

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Direct methanol fuel cells

271

Clients:

European Defence Agency, based on an agreement between the Federal Republic of Germany, the Republic of Austria, the Kingdom of the Netherlands, the Republic of Slovenia and the Kingdom of Sweden Implementation: January 29, 2019 to January 28, 2021 Contact: Dr. Carsten Cremers, Fraunhofer ICT

10.4 Direct methanol fuel cells 10.4.1 Overview Another variant on this type of system is the direct methanol fuel cell (DMFC), which offers advantages such as the high energy density of methanol and the ease of using and refueling the system. Methanol in the form of an aqueous solution is supplied directly to the cell, where it undergoes electrochemical oxidization. The following cell reactions arise in acid and alkaline cells (Table 10.2). At normal operating temperatures of up to 80 °C, the cell’s power density lags far behind that of hydrogen systems, meaning that the DMFC is only advantageous for applications with lesser power requirements of up to 1 kW.

10.4.2

Stack components

DMFC stacks differ from PEMFC stacks at the fine-detail level. On the anode side, DMFC membrane electrode assemblies use catalysts made of a platinumruthenium alloy. These accelerate methanol oxidation via a bifunctional mechanism, i.e., they provide an extra catalytic center for splitting water. Studies by

Table 10.2 DMFC: cell reactions in acidic and alkaline cells Acid

Alkaline

Anode Cathode Total Anode Cathode Total

CH3 OH C H2 O ! CO2 C 6 HC C 6 e 1:5 O2 C 6 HC C 6 e ! 3 H2 O CH3 OH C 1:5 O2 ! CO2 C 2 H2 O CH3 OH C 6 OH ! CO2 C 5 H2 O C 6 e 1:5 O2 C 3 H2 O C 6 e ! 6 OH CH3 OH C 1:5 O2 ! CO2 C 2 H2 O

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Fraunhofer ICT have shown that this bifunctional mechanism can work in alkaline environments too [3]. Furthermore, the catalyst loading is also significantly greater on each side because the methanol oxidization rate is slow. This hinders oxygen reduction, partly due to methanol crossover, but mainly due to a pronounced tendency to flooding caused by very large water flows. For this reason, unsupported catalysts are often used. In addition, membranes up to 180 m thick are used to limit the damaging effects of methanol crossover. The bipolar plates are also fundamentally different. Since aqueous methanol solution, which is a good heat carrier, is already being pumped through the stack, there is no need for a supplemental coolant. As such, milled graphite-compound bipolar plates can be manufactured in one piece from solid materials, meaning the costly process of joining half-plates can be omitted.

10.4.3 System components The DMFC stacks differ fundamentally from the LT-PEMFC at a system level. An aqueous methanol solution serves as the fuel. To limit methanol crossover to the cathode, methanol concentration in the stack does not usually exceed 3 wt%. As these very dilute methanol solutions have such low energy density, pure methanol or a methanol-water mixture of about 60 wt% methanol is added from outside. This is achieved by bringing the heavily-diluted methanol solution within the stack into a closed-loop cycle, while methanol that has been consumed is added from outside. This allows the stack to operate with extremely high anode stoichiometries. In modern systems, to further limit methanol crossover, methanol concentration in this inner closed-loop cycle is dynamically aligned with the load. When loads are lower, concentration is reduced by suspending the addition of methanol until the desired level is reached. DMFCs’ low current density, which normally lies in the region of 200 to 300 mA/cm2 , means they require significantly less air supply than a high-performance PEMFC system. For this reason, a membrane pump is often used for air supply, particularly in portable systems. Over-stoichiometric quantities of water accumulate on the cathode side, which results in the consumption of water from the anode circuit. To achieve the required high energy densities, it is therefore necessary to separate water from the cathode exhaust air and feed it back into the closed anode loop. In today’s systems, this can be achieved at ambient temperatures of up to 45 °C for the most part. At higher ambient temperatures, it is not possible to achieve sufficient water recovery levels. In this case, a mixture of methanol and water must be used as fuel. This is also referred to as “desert fuel.”

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Alkaline fuel cells

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10.5 Alkaline fuel cells 10.5.1

Overview

Reactions within a fuel cell are influenced not only by temperature, but also by pH value and the materials selected for the electrocatalysts and other structural elements. This last factor can be attributed to the fact that when pH values are low, protons can oxidize non-precious metals. For this reason, only “adequately precious” materials can be used in acid cells. M C nHC ! Mn C

n H2 2

The alkaline fuel cell category includes classic alkaline fuel cells (AFC) and anion exchange membrane fuel cells (AEMFC), which are still in development. Certain groups in the USA also use the term hydroxide exchange membrane fuel cells (HEMFC), in order to illustrate that such cells are the exact opposite to a protonexchange membrane fuel cell. Alkaline fuel cells use an alkaline solution as an electrolyte—usually a KOH solution, although NaOH is also used. In most AFCs, this solution is fixed in a porous ceramic matrix. In the past, alkaline fuel cells where the electrolyte was pumped around the stack were produced, similar to the alkaline electrolyzers of today. One major challenge with alkaline fuel cells is absorption of CO2 from the ambient air, which results in the formation of carbonate or hydrogen-carbonate ions. CO2 C 2 OH ! CO2 3 C H2 O CO2 C OH ! HCO 3 In classic AFCs, potassium or sodium carbonate forms during this process and precipitates as a solid, which damages the electrodes. AFCs have therefore mainly only been used in applications where pure oxygen is available as an oxidation agent. Due to the lower overpotential of the oxygen reduction reaction, which is weaker than in PEMFCs, hydrogen- and oxygen-powered AFCs can achieve higher efficiency levels. In contrast to AFCs, AEMFCs use a solid-state ionic conductor based on an alkaline anion exchange membrane. As alkaline groups, these membranes contain  mostly quaternary amines NRC 3 OH . As with PEMs, AEMs build up water during operation, resulting in the formation of aqueous alkaline regions that ions are conducted through. On the other hand, contact with CO2 can lead to the formation

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Table 10.3 Electrode reactions in AEMFCs and PEMFCs Anode-side hydrogen oxidation Cathode-side oxygen reduction

PEMFC AEMFC PEMFC AEMFC

H2 ! 2 HC C 2 e H2 C 2 OH ! 2 H2 O C 2 e 0:5 O2 C 2 HC C 2 e ! H2 O 0:5 O2 C H2 O C 2 e ! 2 OH

 of carbonate- (CO2 3 ) and hydrogen-carbonate (HCO3 ) ions, but these do not form solid salts with the polymer-bound quaternary amines and so do not bring about precipitation reactions. However, carbonation does lead to reduced conductivity [4, 5], which limits cell performance. AEMFC performance has long lagged far behind that of PEMFCs. More recently however, reports have emerged of these cells achieving power densities comparable to PEMFCs, due to the use of catalysts made of a platinum-ruthenium alloy for anode-side hydrogen oxidation, or alternatively the use of ionomers in the electrodes. In the context of this development, it must be noted that electrode reactions in AEMFCs are fundamentally different from reactions in PEMFCs (Table 10.3). The main difference is that water is consumed at the cathode and then reformed at the anode. The positive influence of PtRu on the anode reaction can be explained by the bifunctional mechanism that occurs during water formation, as in DMFCs. There is also a considerable risk of the cathode drying out. This has been identified as a primary cause of premature aging.

10.6 Solid oxide fuel cells 10.6.1 Overview In solid oxide fuel cells (SOFC), the solid electrolyte is made out of zirconium oxide, which enables sufficient oxygen ion conduction at operating temperatures of over 600 °C. The presence of hydrogen or carbon monoxide on the anode side, and oxygen on the cathode side, enables a cell reaction whereby electrons are released and flow to the cathode side (Fig. 10.12). In an external, high-temperature process, upstream from the fuel cell stack, fuel is converted to a reformate with the highest possible hydrogen and carbon monoxide content (reforming). Internal reforming of short-chain hydrocarbons like methane within the stack is possible, but this is rarely carried out due to detrimental effects on energy density and costs. Hydrogen, on the other hand, only requires preheating before it can be fed directly into the stack.

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Fig. 10.12 Idealized visualization of gas supply and material conversion in an SOFC. (see [7])

10.6.2

Stack components

In addition to tubular cell structures, planar cells are also common; these are categorized based on their supporting layer (Fig. 10.13). In this kind of cell, the electrolyte consists of zirconium dioxide doped with yttrium or scandium. Each side is coated with porous, current-conducting electrodes (electrolyte-supported cell, ESC). This allows reactants to diffuse to the electrolyte, as well as enabling supply and discharging of electrons. The combination of an electrolyte with anode and cathode material is called a membrane electrode assembly (MEA) (Fig. 10.14). Researchers are currently endeavoring to develop cell materials, membrane electrode assemblies and entire fuel cell stack systems, with the aim of creating stacks that are stable over long periods of time and multiple thermal cycles and that deliver a high performance in terms of energy output. Fig. 10.15 shows an SOFC stack with electrolyte-supported cells (ESC). Aside from the main components, other elements like glass-ceramic seals and protective and contact layers are also an important part of stack development [8, 9]. ESC

Electrolyte

A SC

Anode

C SC

Cathode

M SC

Porous Metal Substrate

Fig. 10.13 Diagrams of planar SOFC cell types: ESC: Electrolyte-supported cell; ASC: Anode-supported cell; CSC: Cathode-supported cell; MSC: Metal-supported cell

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Fig. 10.14 FESEM image of a membrane electrode assembly in a solid oxide fuel cell (SOFC). (Fraunhofer IKTS)

Glass Sealing

Cathode Contact

Cover Plate Interconnect Plate Cell (MEA)

Nickel mesh Ground Plate Fig. 10.15 Exploded view of an SOFC stack with electrolyte-supported cells

10.6.3 System components Integrating SOFC stacks requires specially developed system components and system designs. These must consider the heating, fuel preparation, afterburning and thermal management processes (Fig. 10.16). A system concept is developed to suit the specification (e.g., fuel, heat extraction) and requirements (e.g., high electrical efficiency) of the particular area of application. The fuel preparation concept must be studied separately and has major implications for both system efficiency and the complexity of system integration [10]. Depending on the fuel, different reforming processes are conducted outside the

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Fig. 10.16 SOFC system components for a portable system (100 We ) based on propane/ butane

Fig. 10.17 Examples of SOFC system components. Left: Reformer with cordierite honeycomb for partial oxidation of a propane-butane mixture. Center: ceramic foam afterburner. Right: Ceramic foam ignition burner. (Fraunhofer IKTS)

SOFC stack, using air (partial oxidation), steam (steam reforming) or carbon dioxide (dry reforming). Catalyst-supported partial oxidation is a simple option for reforming shortchain hydrocarbons like methane or propane/butane and can be implemented in systems with relative ease. Reformer and catalyst design and targeted thermal integration of these components are crucial to achieving the desired temperature profile for the required operating points. Fig. 10.17 (left) shows an example of a reactor used for partial oxidation of propane/butane. Afterburner design must also be considered, including suitable flow management, good combustion properties, and appropriate heat management. In the afterburning process, equipment such as porous burners consisting of ceramic foam

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Fig. 10.18 Left: SOFC system cathode air heat exchanger with a multilayer structure. Right: Gas flow through a 3D simulation model of a cathode air heat exchanger with corresponding gas temperatures. (Fraunhofer IKTS)

can be used (Fig. 10.17, center). Electrical preheaters and—especially in portable devices—ignition burners are used to heat up SOFC systems. Porous substances (in this case, silicon carbide foam prepared via pressure-less sintering, Fig. 10.17, right) also play an important role in ensuring secure operation with good combustion properties. Heat exchangers are used for internal heat transfer. One target of thermal management in SOFC systems is to use exhaust gas heat within the system (regeneration) in such a way that the system is thermally self-sustaining, i.e., no further heating is required to operate it. This makes it possible to achieve high levels of electrical efficiency. A high degree of heat extraction is important in stationary heat and power cogeneration facilities, for example. Usually, the exhaust gas heat is used to preheat the cathode air as required. Therefore, the thermal management in SOFC systems via heat exchangers must ensure efficient heat transfer while also

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Fig. 10.19 Left: A compact assembly of the hot system components of an SOFC, including the ignition burner, reformer, stack, afterburner and heat exchanger. Right: Cross section of a hotbox. (Fraunhofer IKTS)

being well integrated, to keep heat losses to a minimum and to achieve high levels of thermal efficiency. Fig. 10.18 shows an example of an air preheater with a multilayer structure. A 3D simulation model is used to study the gas flow through the device and its effect on gas temperatures. In the most advanced technology available in SOFC system development at present, all hot components are integrated in such a way as to minimize external heat losses where possible, e.g., by using a shared insulation box (hotbox). To achieve this, it is important for the hotbox to have a compact structure and for the components to be closely integrated. Multiple layers of microporous insulation are arranged around the components to maintain operating temperatures of over 700 °C (Fig. 10.19).

M3 foundation project: developing a portable fuel cell device

Research objective The aim of the M3 project was to develop a portable fuel cell device based on camping gas (propane/butane) with an electrical output of 100 Wel , as well as high efficiency and high energy density (Fig. 10.20). This involved the following steps:

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 Stack development  Component development (reformer, ignition burner, heat exchanger, afterburner)  System development  Optimization of component and integration design, with the aim of increasing system-wide volumetric and gravimetric energy density Fig. 10.20 The portable 100 Wel eneramic® SOFC system

The component optimization and integration achieved in this project brought about a significant reduction in volume (approx. 69 percent) and weight (approx. 68 percent). The project participants successfully brought the required control system and the eneramic® system (TRL 8) to production readiness. Project partners: Fraunhofer IKTS Implementation: January 1, 2006 to December 31, 2015 Contact: Daniela Herold, group manager, Fraunhofer IKTS

10.6.4 Operational management SOFC stacks can operate efficiently over a wide partial-load range. Fig. 10.21 illustrates the efficiency of a 1000 Wel SOFC system powered by natural gas. In contrast to the full-load operating point of 1000 Wel , the (net) electrical efficiency of 38.8 percent at 600 Wel declines by only 2.4 percent. Stack modeling is used here to estimate stack output, facilitate dimensioning and run system analyses [11, 12]. This allows modeling of stack performance at various temperatures as well as dif-

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Fig. 10.21 Electrical efficiency (gross and net) and internal consumption by BOP components in a 1000 Wel SOFC system based on natural gas, with partial oxidation. (Fraunhofer IKTS)

ferent gas compositions and quantities, e.g., in cases of partial load. The goal is to ensure efficient, secure, low-degradation operation of the SOFC stack and its system components at different load points. Characterizing stack performance under different conditions is necessary for stationary and transient process analyses. This characterization can be used in various software tools [10, 11]. For example, a 3D thermofluidic model can be used to analyze the stack’s thermal properties within the hotbox. This sheds light on internal mass flow distribution and the temperature profile to be expected within the stack (Fig. 10.22; [13]). These insights allow optimization of the specific design of the stack and its thermal integration. Essentially, it is necessary to aim for a temperature profile as homogeneous as possible, to facilitate homogeneous material conversion and uniform conditions across the entire stack. If certain zones are permanently hot, this can bring about thermomechanical stress and cracks, causing more severe degradation.

10.6.5 Service life and degradation SOFC stacks have already demonstrated the levels of long-term stability and durability across cycles necessary for the use of these SOFC systems in electricity and

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Fig. 10.22 Illustration of the temperature profile in a SOFC stack using a 3D thermofluidic stack model, with indicators showing the cathode air flow. (Fraunhofer IKTS)

heat supply. To prove their capacity to withstand long-term use, SOFC stacks are being tested during continuous operation and across thermal start-stop cycles. In continuous operation over 20,000 hours, degradation rates as low as 0.4 to 0.7 percent per 1000 hours have been achieved [13]. In start-stop cycle tests of more than 100 full thermal cycles, scientists have demonstrated degradation rates of 0.5 to 0.7 percent per 10 cycles [14–17]. The aim of future development activities is to bring down these rates and increase the number of possible thermal cycles. Other strategies and application scenarios under discussion involve bypassing thermal cycles, either by conducting targeted dimensioning of the SOFC system in combination with storage devices like batteries or thermal storages or by including hot-standby operation [18].

10.7 Molten carbonate fuel cells 10.7.1

Overview

Molten carbonate fuel cells (MCFC) use molten alkali carbonates suspended in a microporous membrane as an electrolyte. Operating temperatures for MCFCs range from 580 to 650 °C. In the most common cell types, short-chain hydrocar-

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Fig. 10.23 Diagram of an individual MCFC’s mode of operation

Consumer Load eH2 CO

-

-

e

O2 CO2

e CO32CO32-

H2 H2O CO2

O2

Anode

Cathode

Electrolyte

bons like methane can be reformed (indirectly or directly) within the stack, while high-value hydrocarbons must normally undergo external pre-reforming. Stationary MCFC systems are used in the higher output ranges of 0.3 to 4 MW. They can reach electrical efficiency levels of up to approximately 47 percent. These systems have reached a high level of technological advancement (TRL 8) and have many possible areas of application. They can be used simply as optimized power generators, or for process steam extraction during heat and power cogeneration. Developments around MCFC applications in the field of carbon capturing are of interest to the steel and cement industries, as well as coal- and gas-fired power plants. This prospect of actively separating CO2 from gas flows arises from MCFCs’ method of operation (Fig. 10.23). Carbonate ions (CO2 3 ) are passed through the liquid electrolyte. These ions form at the cathode when oxygen reacts with CO2 , which must be added to the cathode gas. On the anode side, carbonate ions transported through the electrolyte react with hydrogen to form CO2 , which can be concentrated, and water. In contrast to other methods of CO2 separation, this process generates electrical energy instead of consuming it, because it takes place during standard MCFC operation. This leads to an even greater reduction in CO2 emissions. While the MCFC system has its advantages, it also presents certain technical problems that have yet to be resolved; these restrict its potential for wider commercial use. Some of the most pressing problems include the cell components’ degradation and aging mechanisms, which are caused by the liquid electrolyte’s high reactivity. This limits the service life of today’s cell stacks to five years. Many ongoing development projects aim to increase service life to seven to ten years.

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Stack components

The planar structure of MCFC cells allows multiple cells (consisting of cathode, electrolyte and anode) to be stacked together with current collectors and contact plates. Fig. 10.24 shows a typical repeating unit in a fuel cell stack. Like SOFCs, MCFCs feature an electrical series circuit and a fluidic parallel circuit. Compared to SOFCs, MCFC technology takes up significantly more floor area: approx. 0.7 m2 . The cathode consists of nickel oxide, which is doped with lithium from the electrolyte when it is first put into operation. The cathode material must have a porosity of 60 to 70 percent to allow the triple phase boundary (TPB) between electrode, electrolyte and gas phase to form. This is important, as this is the site of the electrochemical reaction between CO2 and O2 . The anode is made of nickel, with some aluminum and chromium content to ensure mechanical stability under the operation conditions. The anode porosity of 45 to 70 percent is a crucial factor and must be adjusted precisely to modulate electrolyte distribution inside the cell. The electrolyte is a mixture of different alkali carbonates, mainly lithium, sodium and potassium, which are in molten state at the cell’s normal operating temperature. This molten electrolyte is immobilized between the electrodes in a solid, porous ceramic structure (matrix). The matrix consists of a lithium aluminate nanopowder. Severe material degradation in modern MCFCs principally affects the active (anode and cathode) and passive cell components (matrix). There are various chemical mechanisms in the active components that lead to loss of stack output and ultimately make these systems uneconomical. In the electrolyte, the degradation of matrix materials plays a particularly important role. As operating periods lengthen, the matrix powder is coarsened and capillary forces are weakened. The matrix can no longer securely hold the molten electrolyte, resulting in electrolyte loss. This in turn leads to a loss of output power up to the complete breakdown of the cell and its entire system.

Fig. 10.24 Diagram of an individual MCFC repeating unit. When these individual cells are stacked one on top of another, they form a complete stack

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To combat matrix degradation, stable phase-pure powders must be developed to serve as passive matrix components. This helps to reduce coarsening. This requires various synthesis steps. By using radiographic and nuclear magnetic resonance spectroscopy to characterize the intermediate products, it is possible to adapt process steps to obtain a stable powder.

Fraunhofer Attract project—INNOVELLE: Innovative ceramic layer systems for molten carbonate fuel cells with extended long-term stability and lifetime

Research objective The aim of the INNOVELLE project was to lay the foundations for extending MCFC service life, and as such, the project addressed various MCFC components. This included manufacturing and optimizing matrix materials and characterizing active materials, as described below:  Fundamental analysis of MCFC degradation processes  Reduction of matrix material coarsening  Development of advanced processes for evaluating the electrochemical impedance spectra of active MCFC components  Research into new high-temperature anti-corrosion coatings for applications involving molten salts  Research into non-stick coatings for applications involving molten salts Project partners: Fraunhofer IKTS Implementation: March 1, 2013 to February 28, 2019 Contact: Mykola Vinnichenko, Fraunhofer IKTS

The active components can be studied during operation in half-cell configuration (Fig. 10.25a). To investigate electrochemical processes and the influence of various process parameters on them, as well as the effect of degradation mechanisms on the performance of active components, the cells are characterized using electrochemical impedance spectroscopy (Fig. 10.25b). Based on the impedance spectra, classic equivalent circuit diagram modeling can be used to determine the characteristic parameters at different operating conditions to show their influence on the limiting processes (Fig. 10.25c). New methods for evaluating spectra based on the

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b

d c

Fig. 10.25 (a) Structural diagram of a half-cell; (b) impedance spectrum for a cathode halfcell under standard operating conditions; (c) processes in the identified frequency ranges; (d) evaluation of relaxation times with improved separation of reaction steps

distribution of relaxation times (Fig. 10.25d) are being used to achieve a better separation of reaction steps in the spectrum. This method enables improved identification of limiting processes, which in turn allows targeted optimization of the active components. This development can be scaled up from half-cells to full cells. In the context of manufacturing new materials (e.g., matrix powder) in particular, the transition from the laboratory-scale (10 to 20 g) to the pilot-plant scale (approx. 25 kg) is an important factor for verifying the cell’s extended service life. Upscaling in this way requires the creation of suitable cell- and stack structures, so that conditions in these cells and stacks are similar to those of large commercial setups (Fig. 10.26). Using this methodology, it is possible to conduct laboratory-scale studies regarding the possibility of service life extensions for other new MCFC materials, e.g., different types of anode, cathode and matrix materials. This makes it possible to draw conclusions about the suitability of materials without the costly and resourceintensive process of constructing an entire stack.

References

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Fig. 10.26 A ten-cell MCFC test stack for investigating new MCFC materials: photograph (left) and simulation (right) illustrating the temperature profile. (Fraunhofer IKTS)

References 1. Schmidt T.J., Baurmeister J. (2006): Durability and reliability in high-temperature reformed hydrogen PEFCs. ECS Transactions 3: 861–869. https://doi.org/10.1149/1. 2356204 2. Cremers C., Jurzinsky T., Meier J., Schade A., Branghofer M., Pinkwart K., Tübke J. (2018): DEMS and online mass spectrometry studies of the carbon support corrosion under various polymer electrolyte membrane fuel cell operating conditions. Journal of the Electrochemical Society 165. https://doi.org/10.1149/2.0331806jes 3. Kübler M., Jurzinsky T., Ziegenbalg D., Cremers C. (2018): Methanol oxidation reaction on core-shell structured Ruthenium-Palladium nanoparticles: Relationship between structure and electrochemical behavior. Journal of Power Sources 375. https://doi.org/ 10.1016/j.jpowsour.2017.07.114 4. Inaba M., Matsui Y., Saito M., Tasaka A., Fukuta K., Watanabe S., Yanagi (2011): Effects of carbon dioxide on the performance of anion-exchange membrane fuel cells, Electrochemistry 79: 322–325 5. Siroma Z., Watanabe S., Yasuda K., Fukuta K., Yanagi H. (2011): Mathematical modeling of the concentration profile of carbonate ions in an anion exchange membrane fuel cell, Journal of the Electrochemical Society 158: B682–B689. https://doi.org/10.1149/1. 3576120 6. Steele B.C.H. (1999): Running on natural gas. Nature 400, 6745: 619. https://doi.org/10. 1038/23144 7. Bove R., Ubertini S. (eds.) (2008): Fuel cells and hydrogen energy. Vol. 1: Modeling Solid Oxide Fuel Cells: Methods, Procedures and Techniques. Reprinted. Springer, New York, NY

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8. Trofimenko N., Kusnezoff M., Michaelis A. (2011): Recent Development of Electrolyte Supported Cells with High Power Density. ECS Transactions 35 (1): 315–325. https:// doi.org/10.1149/1.3570006 9. Kusnezoff M., Trofimenko N., Müller M., Michaelis A. (2016): Influence of Electrode Design and Contacting Layers on Performance of Electrolyte Supported SOFC/SOEC Single Cells. Materials 9 (11): 906. https://doi.org/10.3390/ma9110906 10. Nousch L., Pfeifer T., Hartmann M. (2018): Development of a Modeling Platform for Dynamic SOFC-System Simulation in a Wide Operational Range. In: Proceedings of the 13th European SOFC & SOE Forum (A1320), Lucerne. ISBN 978-3-905592-23-8 11. Kusnezoff M., Beckert W., Trofimenko N. et al. (2015): Electrochemical MEA Characterization: Area Specific Resistance Corrected to Fuel Utilization as Universal Characteristic for Cell Performance. ECS Transactions 68 (1): 2555–2563, https://doi.org/10. 1149/06801.2555ecst 12. Pfeifer T., Nousch L., Lieftink D., Modena S. (2013): System Design and Process Layout for a SOFC Micro-CHP Unit with Reduced Operating Temperatures. International Journal of Hydrogen Energy 38 (1): 431–439. https://doi.org/10.1016/j.ijhydene.2012. 09.118 13. Reuber S., Megel S., Jürgens C. et al. (2015): Application-Oriented Design and Field Trials of the eneramic Power Generator. ECS Transactions 68 (1): 131–141. https://doi. org/10.1149/06801.0131ecst 14. Megel S., Dosch C., Rothe S. et al. (2013): CFY Stacks for Use in Stationary SOFC and SOEC Applications. ECS Transactions 57 (1): 89–98. https://doi.org/10.1149/05701. 0089ecst 15. Brandner M., Bienert C., Megel S. et al. (2013): Long Term Performance of Stacks with Chromium-Based Interconnects (CFY). ECS Transactions 57 (1): 2235–2244. https:// doi.org/10.1149/05701.2235ecst 16. Bienert C., Brandner M., Skrabs S. et al. (2015): CFY-Stack Technology: The Next Design. ECS Transactions 68 (1): 2159–2168. https://doi.org/10.1149/06801.2159ecst 17. Megel S., Kusnezoff M., Beckert W. et al. (2016): CFY-Stacks: Progress in Development. In: Proceedings of the 12th European SOFC & SOE Forum (A0908), Lucerne. ISBN: 978-3-905592-21-4 18. Nousch L., Hartmann M., Michaelis A. (2021): Improvements of Micro-CHP SOFC System Operation by Efficient Dynamic Simulation Methods. Processes 9 (7): 1113. https://doi.org/10.3390/pr9071113

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Production of PEM systems, upscaling and rollout strategy

Ulrike Beyer  Sebastian Porstmann Fraunhofer Institute for Machine Tools and Forming Technology IWU Christoph Baum  Clemens Müller Fraunhofer Institute for Production Technology IPT Abstract

Fuel cells can ensure substantial reductions in CO2 emissions within the transportation sector in the future. While individual products are already available or are close to market maturity from a technical point of view, cost parity with fossil fuel-powered drive systems must be achieved without delay. Expensive materials and manual manufacturing are preventing production from being costeffective. No technology capable of high production rates is currently available for the large-scale production of several hundred thousand units per year; this would allow production to be scaled to a mass industrial level. The production processes necessary for upscaling are presented in this section and linked to a rollout strategy.

11.1 Fuel cells Proton-exchange membrane fuel cells (PEMFC) can play an important role in substantially reducing CO2 emissions within the transportation sector in the future. While individual products are already available or are from a technical point of view close to market maturity, costs represent a significant barrier to market entry. Achieving cost parity with fossil fuel-powered drive systems is therefore imperative. © Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_11

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Expensive materials and manual manufacturing are preventing PEMFC production from being cost-effective. The few manufacturers that operate in this area still cater to niche markets. Future scenarios envisage the mass production of several hundred thousand units per year [1]. There is currently no technology available with the production capability needed to scale to a mass industrial level. Developing this technology would give Germany a unique opportunity to consider hydrogen not just from the perspective of climate politics, but also to establish it within the context of sustainable value creation. It is precisely the key component of hydrogen system technology—fuel cells and their use in mobility solutions for different performance categories—that presents enormous potential for value and job creation. Potential manufacturing locations across Germany, in particular automotive industry locations, can also benefit from the broad spectrum of application scenarios [2].

11.1.1 Production elements Single cells within a fuel cell comprise a bipolar plate with an anode and a cathode side as well as a membrane electrode assembly. When several single cells in a row are activated, stacked, compressed, braced, and if balance-of-stack components are included (such as end plates, current collectors, distribution plate and monitoring unit), this creates a fuel cell stack. The number of single cells and their active area allow for performance levels to be varied. Supported by balance-of-plant components including air compressor, humidification, hydrogen supply, purge valves, thermal management module and power electronics, the fuel cell stack forms the fuel cell system [3]. Fig. 11.1 illustrates the essential process steps for PEMFC production. The high cost of fuel cell systems (e.g., 38 percent for 10 kW PEMFC) and lack of high-throughput production capability results in labor- and cost-intensive processes across all component types, particularly in terms of single-cell component manufacturing [4]. For this reason, the analysis below focuses on the production of single fuel cell components. The following is a closer analysis of the cost reduction potential of technology optimization and market-based economies of scale.

11.1.2

Technology optimization

Producing single cell components involves various production steps. The primary cost drivers are the manufacturing of membrane electrode assemblies and bipolar

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Fig. 11.1 Essential production elements for PEMFC [3]

plates. While the high price of catalysts in catalyst-coated membranes (CCM) is down to raw material costs and processing into platinum catalysts, the high cost of gas diffusion layers (GDL) and bipolar plates (BPP) results from technologically immature process engineering that is incapable of high throughput rates [5]. Cost reduction potential resulting from the optimization of industrial production has so far only been exploited to a limited extent for fuel cell production. It can be assumed that costs will be significantly reduced along the entire value chain in the future. One area with particular cost reduction potential is batch process. This is a discontinuous process that to some extent causes rejection rates, which increase costs. This must be converted into robust process steps that allow for high throughputs and automation [6]. Within the context of stacking, shortening cycle times is an additional focus area. Production technology prerequisites for substantially reducing costs are offered by the targeted optimization of manufacturing processes, automation and a conversion to continuous processes. Concepts for the above are described in detail in Sects. 11.1.3,11.1.4 and 11.1.5.

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11.1.3 Manufacturing processes To illustrate cost reduction potential during the manufacturing of membrane electrode assemblies and bipolar plates, these production modules are contextualized and described in terms of process here. Research challenges in terms of developing these areas of activity further will also be deduced.

Membrane electrode assembly (MEA) A single fuel cell stack currently costs 800 EUR/kW. At 510 EUR/kW, MEA costs are the primary cost drivers, with 210 EUR/kW allocated to catalyst materials. Optimizing the process could reduce these costs by almost 50 percent if the quality and performance of the membrane electrode assembly is improved with no change to the precious metal content. Combining design and manufacturing could potentially shrink the area of the membrane electrode assemblies used during stack building. Likewise, many of the materials used today to build membrane electrode assemblies are overdimensioned, which also adds unnecessary costs [4]. To produce a membrane electrode assembly (Fig. 11.2), catalyst ink, which usually consists of a platinum alloy, powdered carbon, nafion, distilled water and methanol, first needs to be prepared via a ball milling process. CCS and CCM methods have become established for the subsequent application. For CCS, the catalyst is applied directly to the gas diffusion layer to form gas diffusion electrodes. Sputtering is one of several suitable coating methods. The anode or cathode are located on the gas diffusion layer. The membrane is inserted between the anode and cathode layers and joined to the gas diffusion layers by hot pressing. Following hot pressing, a calibrated cutting process gives the membrane electrode assembly its final shape. The use of CCM involves either a direct or an indirect process. In the direct method, the coating is applied directly to the membrane. The layer is then dried, and the gas diffusion layers are positioned and bonded to the membrane using hot pressing. For indirect CCM use, the anode and cathode are located on an inter-

Fig. 11.2 Technological insider view of MEA assembly. (Fraunhofer IPT Aachen)

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substrate known as decal transfer film. The electrodes are applied to the membrane and then pressed together with the gas diffusion layer. Similar to CCS, the final step in the process is to cut the MEA into its final shape. The challenges posed by the MEA production process are the catalyst layer and hot pressing. The need to optimize platinum content and to consider a large number of multilateral process parameters yields various areas in which the manufacturing process can be developed further. Optimizing the process of applying the catalyst layer is necessary; this will also enable the continuous production of electrodes. Developing an in-line process monitoring system is also necessary, since defects such as holes and cracks can occur in the catalyst layer that could restrict the conductivity of the cell. Optimizing both the process and the material parameters is essential for hot pressing. This is due to the negative influence of the applied pressure and temperature on the integrity of the mechanical and electrical connection as well as on the material properties of the membrane and electrode [7].

Metallic bipolar plates A further potential starting point for cost reduction is offered by processes that have not reached technological maturity for industrial production. At 25 percent, the production of bipolar plates from impervious graphite is the second-biggest cost element. High reject rates resulting from shape errors lead to these high costs. Using metallic bipolar plates results in huge cost reductions. However, this requires an additional optimization of the cost-effective metallic system including a coating that has long-term stability in cells [4]. Implementing this robust production process could facilitate a technological leap that offers a foundation for further progress in automation or in continuous processes. The BBP production process (Fig. 11.3) starts with the production of the metallic semi-finished product. Molten metal is poured between rollers with parallel axes and is shaped into sheet metal. During the second step, flow channels are applied to the sheets using a precise microforming process such as hollow embossing or hydroforming. This creates bipolar half plates. The inserted channel structures

Fig. 11.3 Technological insider view of BPP assembly. (Fraunhofer IPT Aachen)

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have an influence on cell functionality. Subsequently, the bipolar half plates are coated either using physical vapor deposition (PVD; also known as sputter deposition) or chemical vapor deposition (CVD). This coating process makes them corrosion-resistant and capable of conducting electricity. It thus prevents the release of ions from metallic bipolar plates, which would result in the contamination of the membrane and bring about a reduction in fuel cell performance. Following forming and coating, the anode and cathode half plates (BP-HPs) are joined to the bipolar plates using laser welding. During this step, laser marking can be used to apply temperature-stable and corrosion-resistant marks to the bipolar plates [7]. The challenges of the bipolar plate (BPP) production process relate to forming, coating and joining the delicate sheets, since this requires an extraordinary high level of precision. High accuracy is required during the forming process to insert the flow field channels into the thin metallic foils (50 to 100 µm thickness) in a way that meets quality standards. It is therefore necessary to further develop the flow field, which has so far been designed to maximize efficiency, for industrial mass production and to optimize it with a view to production requirements [2]. A deviation from the nominal shape, e.g., in channel geometry or the parallelism of a planar surface, has a negative impact on its subsequent operation. Geometrical deviations must be identified in order to prevent damaged cells from being used in stack assembly. This necessitates a high-performance quality monitoring system. In addition, expensive materials such as gold or gold-plated titanium are currently used as coating material for bipolar plates. Developing cost-effective alternatives is therefore necessary to produce a high level of corrosion resistance and electrical conductivity even at lower costs. Laser welding is used for the joining process, but the low speed at which it produces complex structures limits the application rate of the BPP production process. Developing technologies with high-throughput production capabilities is therefore necessary here too [7].

11.1.4 Automation Automation primarily relates to aspects of transfer, handling and assembly and aims to intensify processes. Automating the MEA assembly process has already reduced costs by up to 70 EUR/kW [4]. One process suitable for conversion from manual to automated production steps is the stacking of individual components and cells to assemble fuel cell stacks. This could significantly increase repeatability and precision for sensitive, flexible and partly acidic components with low material thickness.

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It is necessary to seal the individual cells or stack to prevent internal and external leakage and to eliminate tolerances caused by upstream component manufacturing processes. As a component that connects MEA and BPP, the sealing material has a significant influence on the service life of the fuel cell. Sealing can take place in a liquid or solid state. This requires the application of pre-fabricated sealing layers, dispensing, or a suitable form of injection molding. The temperature of the sealing units is maintained in a continuous furnace. Sealing quality is dependent on material properties and pressing following the stacking process. During these steps, synchronized transfer and a very careful handling of components as well as the joining of BPP and MEA is required to prevent leakage. Further areas for potential automation are the handling of semi-finished products and components between individual processing steps and the positioning of the workpiece in the tool. Specialized stack robots with flexible workpiece carriers must be designed that can handle fuel cells made of metallic and graphite bipolar plates of different dimensions. Within this field of action, initial results show a reduction potential of around 90 percent in terms of time and costs [8]. Stacking BPP and MEA in an alternating sequence is still in part performed manually. Robots and gripper technologies are increasingly in use for this purpose. In this context, high-precision automation is the critical factor for implementing a cost-efficient stacking process or for producing a fuel cell stack in a way that meets quality standards. The stacked single cells then undergo extensive testing for leaks, using water bath testing, pressure testing or exposure to hydrogen. Visual inspection and selective sensors may also be used. An automated test stand is used to test differential pressure and standard channel structures (flow fields). Following a successful inspection, the single fuel cells are connected in series. Two end plates seal the stack, which consists of several hundred individual cells, and provide adapters for electric current as well as gas and cooling water. Cost efficiency and reproducibility are the most important design factors for these steps. The process steps are presented in Fig. 11.4.

Fig. 11.4 Technological insider view of stack assembly. (Fraunhofer IPT Aachen, [7])

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Fit-4-AMandA project—fit for automatic manufacturing and assembly [8]

Project objective The project focused on the industrialization of the production and assembly of PEMFC stack components. It also developed a novel automation solution that reduced PEMFC stack assembly costs to approx. 7 percent at 10,000 units annually and to approx. 1 percent at 100,000 units annually compared to manual production costs. A demonstration machine was specified, designed and manufactured to test and verify the fundamental technology (Fig. 11.5).

Fig. 11.5 3D CAD layout of machine for the automated production and assembly of PEMFC stacks [9]

Project partners: Uniresearch B.V.; UPS Europe SA; Proton Motor Fuel Cell GmbH; Aumann Limbach-Oberfrohna GmbH; Fraunhofer IWU; Chemnitz University of Technology/ALF; IRD Fuel Cell A/S Project duration: March 2017 to February 2020 Funding: The Fuel Cells and Hydrogen 2 Joint Undertaking is supported by the European Union’s funding program for research and innovation, Horizon 2020, as well as Hydrogen Europe and N.ERGHY.

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11.1.5 Continuous process management There is a particular need to develop continuous production strategies in preparation for mass production. This primarily involves reducing the technological barriers for converting batch processes to roll-to-roll processing (R2R). We also synchronizing the speed or parallelizing the accompanying processes is also necessary. Using metallic bipolar plates in combination with a rolling method offers new possibilities for continuously manufacturing standard flow fields. To be able to use these positive effects holistically to increase the process speed, it is necessary to integrate or synchronize the subsequent coating and joining processes in order to adapt them to high output rates. Quality checking must be conducted in-situ and the results delivered in real time. The previously used procedure thus requires significant development.

HOKOME project—developing highly productive and cost-efficient R2R fabrication processes for the components of fuel cell stacks

Fig. 11.6 Numerical simulation of roller embossing—the basis for developing an R2R manufacturing concept into continuous BPP production. (Fraunhofer IWU Chemnitz)

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Project objective The objective is to optimize production for the two main components of fuel cells—BPP and MEA. Efficient production processes and methods are being developed for both components as part of the project. A key area here is the coupling of rolling technology (Fig. 11.6) with upstream and downstream process steps. One project focus is on developing comprehensive R2R manufacturing concepts with coordinated sub-processes to enable the integration and combination of subsystems even in different design variants. As a result, output quantities can be realized that correspond to industrial production and achieve a substantial cost reduction for fuel cells. This manufacturing technology allows for cost savings of up to 50 percent, which in the future can reduce the price of a typical 100 kW fuel cell system for a car to 5000 euros, the comparable cost of a fossil-fuel powered drive system. Project partners: Fraunhofer IWU, IPT, IWS, IKTS and ISE Project duration: 2020 to 2022 Funding: 3.5 million euros in funding from the internal Fraunhofer-Gesellschaft research program PREPARE

11.1.6 Economies of scale “Around 200,000 units per year would achieve economies of scale that would allow the required materials to be purchased at a price that could result in a hydrogen car costing the same as a battery-electric vehicle today. With current demand levels, this is set to happen within five years.” Sae Hoon Kim, Head of the Fuel Cell division at Hyundai 2020 [1]

Expected future market growth will be accompanied by a significant reduction in current costs, with fuel cell technology becoming increasingly economically competitive. German companies should therefore secure market shares in order to implement economies of scale and thus reduce costs further as well as to increase their competitiveness internationally. In the next two to five years, developing and expanding expertise further through investment will be crucial [1]. With significant market growth forecast, particularly in terms of fuel cell use in transportation, PEMFC offer the greatest potential for cost reduction from an economies of scale perspective. In the long term, it will be possible to reach

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Produktionsrate 1.000 Units/Year Produktionsrate 10.000 Units/Year Production rate 100.000 Units/Year Produktionsrate 500.000 Units/Year

BPP

CCM

GDL

100 %

100 %

100 %

37 %

36 %

24 %

26 %

27 %

8%

25 %

25 %

5%

100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% BPP

CCM

GDL

Fig. 11.7 Fuel cell production and economies of scale. (Fraunhofer IWU Chemnitz)

30 EUR/kW—a production cost comparable to that of an internal combustion engine drive [10]. The PEMFC stack example in Fig. 11.7 depicts the cost-saving potential (dependent on production rate) for fuel cell components BPP, CCM and GDL. The significant potential for cost reduction becomes apparent when output quantity is increased from 1000 to 100,000 fuel cell stacks per year. Manufacturing costs (excluding material costs) can consequently be reduced for CCM by around 73 percent, for BPP by 74 percent and for GDL by even up to 92 percent. Additional economies of scale are achieved when annual production is further increased to 500,000 stacks. In this scenario, process costs for CCM fall by 75 percent, for BPP by 75 percent and for GDL by 95 percent compared to the initial volume (1000 units/year) [5]. Economies of scale also have an impact on fuel cell stack costs. Further analysis of the calculations used in Fig. 11.7 indicate an expected reduction in process costs of 82 percent—or 84 percent of the production rate is increased from 1000 to 100,000 or 500,000 units annually. Costs for the fuel cell system can also benefit from economies of scale. Increased purchase volume can also result in savings in the area of BOP element procurement [5].

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Batch-scalable technologies The entire fuel cell industry is preoccupied with identifying technology that can deliver the most promising results in terms of cost efficiency, component properties and robustness (process reliability). The focus is on evaluating which combination of technologies is possible, determining what is necessary and calculating how much this will ultimately cost. This requires an open-ended approach that uses diverse technologies. For instance, various input parameters and usage scenarios in BPP manufacturing necessitate the development of production technology with high-throughput production capabilities. Apart from hollow embossing or hydroforming forming processes, which enable high BPP quality to be achieved, only rolling permits a significant increase in output to over 100 bipolar half plates per minute. New solutions are also required for using already pre-coated sheets; this will result in another significant reduction in processing time and can increase the service life of BPP. A batch-scalable technology kit for BPP production is being developed specifically for this optimization challenge. This enables measurable, fit-for-purpose solutions to be identified for the first time, through evidence-based analyses of the multilateral dependencies between BPP geometry, manufacturing process, output quantity, costs and service life. Pertinent BPP manufacturing processes are described below along with their fundamental characteristics for better classification, and are then compared in terms of planarity, quality, service life, costs and production rate [11].

Compression molding (graphite bipolar plates) Compression molding requires a molding press, molding tool and molding compound that can be used for different designs (powder, puck, plate). A range of sensitive process parameters must be taken into account during the process. Excess molding compound material must be applied to ensure that all cavities are filled. The material hardens by means of a chemically irreversible process. The high process reject rate and this surplus represent an intrinsic loss. Fig. 11.8 de-

Fig. 11.8 Compression molding process principle: Variant with a plate as preform material (FBH = blank holder force, FP = press force) [11]

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Fig. 11.9 Injection molding process principle (FCLOSE = clamping force) [11]

picts a variant for implementing this process. Here, the composite is inserted as a semi-finished product in the form of a planar mat. This allows for geometries similar to those of hollow embossed sheet metal forming to be achieved [11].

Injection molding (graphite bipolar plates) Injection molding requires a mold, a preheated rotating screw conveyor (extruder) and a container for raw material. A simplified version of this process principle is illustrated in Fig. 11.9. The process is conducted close to the glass transition temperature of the thermoplastic molding compound in order to achieve short cycle times. Almost no excess raw material is required, and scrap material can be recycled to a certain extent, resulting in less waste than compression molding. One drawback compared to compression molding is that the graphite and fiber content must be relatively low for production reasons. This leads to reduced conductivity (even if the alignment of the graphite particles offers an advantage) and possible fiber breakage also leads to lower bending strength [11].

Hollow embossing (metallic bipolar plates) During this process, the sheet metal is preferably embossed hollow with two rigid tool counterforms, and a rubber buffer can also be pressed against a metallic die. However, this can only be used at the plate edges, since the flow field structure is too intricate to separate it for the bridge area (rib) in order to clamp the sheet there. In theory, the range of the sheet metal holders could also be extended to

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Fig. 11.10 Single-stage hollow embossing process principle (FBH = blank holder force, FP = press force) [11]

the flow field area, but the flow field structure—especially the bridge or channel width—must be sufficiently abrasive and large to allow this. A simplified version of this process principle is illustrated in Fig. 11.10. Embossing is one of the most robust forming processes and can be easily automated using progressive dies or transfer dies. Since the process subjects the material to gradual stress, it is also advantageous in terms of achieving higher degrees of deformation and better-formed channel structures. The cutting process can also be integrated, and implemented using the same die. Production scenarios are calculated using a rate of 60 strokes/min; this results in a production rate of 60 bipolar half plates per minute using a BP–HP tool. Calculation results indicate that enough bipolar half plates for over 97,000 100-cell PEM stacks could be produced annually. Simultaneous production of both bipolar plate halves—anode and cathode—using an adapted press and in one press stroke is also possible. This would double the assumed production rate [11].

Hydroforming The functional principle of hydroforming, also known as high-pressure sheet metal forming, is illustrated using a diagram in Fig. 11.11. The advantage of this principle is that it allows for better utilization of a material’s forming capacity, which enables an extension of forming limits compared to single-stage hollow embossing under cold forming conditions, for example.

Fig. 11.11 Sheet hydroforming process principle (FCLOSE = clamping force) [11]

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The comparatively low production rate is a disadvantage if high quantities are required. The calculation result indicates that under the given assumptions, bipolar half plates for around 11,000 100-cell PEM stacks could be produced annually. Hydroforming would enable the stroke rate and therefore the production rate to be increased further. This process is more complex than conventional hollow embossing due.to the higher number of aggregates. Producing anode and cathode plates simultaneously therefore requires greater effort in terms of adapting the press and separate dies within one press stroke or closing operation [11].

Hollow embossing rolling Production rate is a decisive factor in terms of production costs (effectiveness) and meeting high market demand, which makes it an important decision-making criterion. As outlined in Sect. 11.1.6, metallic bipolar plate rolling offers significant potential in this respect. A simplified version of this process principle is illustrated in Fig. 11.12. Initial projections show that, in comparison to conventional manufacturing strategies (such as the injection molding of impervious graphite) and at lower investment costs for plant technology, roller embossing can significantly increase production rates from three to well over 60 bipolar half plates per minute. However, additional research is needed in this area to examine whether this process restricts design flexibility in terms of BPP design and performance. Experimental hollow embossing rolling tests were conducted to determine the feasibility of designing parallel flow field channels. The results obtained can be summarized as follows: The rolling forming process is in principle suitable for producing bipolar plate channel geometries on an industrial scale. The need to reduce unwanted side ef-

Fig. 11.12 Roller embossing process principle. (Fraunhofer IWU Chemnitz) [11]

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fects such as wrinkling and springback as well as transfer acquired knowledge into real geometries with regard to complexity and dimensions represent challenges and thus future development potential [11].

Other methods and approaches Another potential process involves injecting a thermoplastic polymer composite material into a partially open mold (i.e. into a pre-magnified molding cavity). Here, the embossing process uses an extruder to close the mold into the required shape. The cooling, opening and ejecting stages are implemented in the same way as in a normal injection molding process. Since the polymer used does not need to harden, holding time is not required, meaning that the time needed for the process is comparable to that for injection molding. Known as injection compression molding, this process would in principle be suitable for use, but is not yet planned for mass production.

11.1.7 Comparison of selected BPP production processes A comparison was made of the currently most frequently used manufacturing processes or those with the biggest cost reduction potential for future production processes, using various evaluation criteria. The focus was on determining process engineering limits and further developing processes for industrial mass production. In addition, the required machinery and tools were considered from the aspect of simultaneous production i.e., the parallel production of cathode and anode plates per forming sequence. The reason for this is to combine the production process more efficiently with the subsequent joining process, so that bipolar half plates can be used again immediately after forming without slowing down the process. The spider chart in Fig. 11.13 offers a qualitative comparison of selected parameters for evaluating individual processes. Each higher value (on a scale of 0 to 1) means a positive measurement; thus, lower costs yield a higher value. To standardize, the best value from the table was defined as 100 percent (default value = 1). This value represents the benchmark for comparison. The qualitative evaluation of the parameters “plate quality” and “plate durability” was based on experience-based assumptions, due to the wide range of contributing factors. From the diagram in Fig. 11.13 it can be deduced that for four out of six evaluation criteria (corner points), compression molding sets the benchmark. Only in terms of production rate and investment costs does this process fall behind the

11.1

Fuel cells Evaluation criterion System costs [€ million] Value Tool costs [€] Value Clamping force [kN] Forming pressure [bar] Plate material Plate price [€/kg] Plate surface area [cm2] Value* Output quantity [BPP/min] Value BP-HP quality value BP-HP planarity value

305 Compression molding ~1.5 0.87 ~80,000 1.00 10,000

Hydroforming

Composite 12–18 500 1.00 0.5 0

Injection molding ~3.0 0.43 ~120,000 0.67 15,000 3,500 Composite 12–18 300 0.60 3.0 0.03

1.00 1.00

0.50 0.90

0.80 0.20

~3.5 0.37 ~250,000 0.32 50,000 3,000 Steel 2–10 500 1.00 6.7 0.06

Hollow embossing ~1.3 1 ~300,000 0.27 8,000

~2.0 0.65 ~150,000 0.53 500

Steel 2–10 500 1.00 60 0.50

Steel 2–10 500 1.00 120 1.00

0.60 0.20

0.20 0.20

Rolling

* determined value for use in diagram

Fig. 11.13 Evaluation criteria for selected scalable BPP production processes. To standardize, the best value from the table was defined as 100 percent (default value = 1). This value represents the benchmark for comparison [11]

forming processes for metallic bipolar half plates. While the production rate for hydroforming is only slightly higher than that of the two molding processes, hollow embossing and rolling are significantly more productive processes.

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This approach may be used as a blueprint for further comparisons. For instance, specified production scenarios could be used to define target values as 1 (100 percent), which represent the corner point goals in the spider chart. Parallelization is essential for hollow embossing and compression molding. The additional costs (due to the press size at constant press rigidity or increased press force) for making these processes parallel by increasing machinery capital costs for the presses must be taken into account. Existing machinery can be used for production over several decades, resulting in a long depreciation period. However, each new stack and generation of bipolar plates requires a new tool kit, which comes with corresponding costs.

Technology kit for BPP production

Fig. 11.14 H2@IWU bipolar plates for mass production; prototype manufactured using hydroforming. (Fraunhofer IWU Chemnitz)

In hydroforming, thin metal foils (50 to 100 µm thickness) are pressed into the flow channels using water at a pressure of 200 MPa. Bipolar plates can be shaped more precisely this way than with previously used methods. Additionally, springback effects are minimized. This creates high-quality bipolar plates that also only require a single mold (Fig. 11.14). In order to bring about the next technological step towards the mass production of bipolar

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plates, the geometry of the flow field must be developed further. This must be optimized both in terms of efficiency and technical production aspects. The new H2@IWU bipolar plate design has been developed at Fraunhofer IWU for this purpose. It has been specially designed for high-throughput mass production using roller embossing and enables flow channel insertion based on a continuous process method. In theory, the efficiency of fuel cells with H2@IWU bipolar plates should remain stable and at a high level. The objective is to achieve a production rate of at least 120 bipolar plates per minute with this new design—double what industrial companies can currently produce using conventional methods. Production processes for maximum output rates are not the only focus of this research field. Depending on the subsequent field of application (stationary or mobile), there may be a need for processes that have different requirements of the semi-finished bipolar plate. Thus, the optimum manufacturing process must be determined using framework conditions or input variables and by taking into account the usage scenario. Whether this is incremental forming or hydroforming for a product mini-series, conventional embossing for medium quantities or roller embossing for large quantities depends on the respective requirements of the industrial companies.

11.1.8 Rollout strategy From an ecological and user-focused perspective, the fuel cell has a clear advantage over other energy converters in many areas of application and has the potential to displace them. However, when replacing technologies that have been established over a long period of time, e.g. batteries or internal combustion engines, the fuel cell must deliver clearly definable economic and technical benefits. In addition to a small number of technical challenges, cost factors such as selling price or infrastructure are primary barriers to market entry. Additional significant cost reductions must be achieved in the short and medium term to enable the development of a commercial market for fuel cell application. Cost, which is still high across all areas, is one of the main factors that is currently preventing broader market penetration of fuel cell technology. The industry is confronted with the challenge and the risk of considerably reducing current costs without the existence of demand

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volume, which would allow for significant economies of scale and thus a major reduction in costs. Political and financial investments should therefore be made to aid the development of local products and enhance technological production capacity. This must be accompanied by support for establishing national production infrastructures for developing and researching suitable manufacturing processes for large-scale production. This would make it possible to make fuel cell production suitable for mass production for the first time, which would reduce production costs on a large scale and accelerate the commercial breakthrough of fuel cell technology. German industry stakeholders can benefit from a national action plan for the research and rollout of fuel cell technology. This aims to merge research expertise and infrastructure to work in a targeted manner on the fundamental challenges and current issues facing companies. These initial challenges were     

highly scalable production and testing technologies, materials engineering, international cross-sectoral standards, evaluation as well as a consideration of the most valuable and fragile parts of the value chain in an economic context.

Other benefits offered by the action plan include advice and guidance for industry stakeholders, e.g., in production system integration and supply chain development. In this way, establishing effective national value creation networks and immediately enhancing socio-economic effects is feasible.

National action plan for fuel cell production

The national action plan develops solutions that enable substantial upscaling and cost reduction for fuel cell production. Additionally, key elements or process steps and the main sensitivities of fuel cell production are evaluated in order to demonstrate the feasibility of mass production in industrial series. The action plan is intended for companies of various sizes that represent the entire fuel cell production value chain, and cover applications in load mobility right up to the system environment, including construction of the necessary machinery and equipment.

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Fig. 11.15 National action plan for the industrial rollout of fuel cell technology for use in transportation. (Fraunhofer IWU Chemnitz)

Behind the action plan are 18 Fraunhofer institutes (IWU, IPT, ISE, IPA, IWS, ENAS, IMWS, IFF, IGP, IPK, UMSICHT, ILT, ICT, ISI, IGCV, IST, IFAM, IKTS) from a total of nine federal states who are applying their research expertise and infrastructures as well as local networks to the development of new manufacturing solutions in regional technology hubs. These are integrated into the four technology networks R2MEA, R2HP, HP2BPP and ST2P and enhanced in a targeted manner by incorporating emerging state and federal initiatives. The superordinate NEXUS network: ViR uses digital images of the developed production solutions to combine synergies in a virtual reference architecture for fuel cell production (Fig. 11.15). C90 million Funding volume: Project coordination: Professor Welf-Guntram Drossel, Dr. Ulrike Beyer, Fraunhofer IWU Chemnitz Information: h-2-go.de

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11.2 Electrolyzers The future technical and cost-related development of individual electrolysis technologies is subject to substantial uncertainty. The differences in the characteristics of these technologies are to some extent rudimentary. Construing them as a single, market-dominating technology would therefore not be appropriate. It can be assumed that the development of electrolysis is in principle technology neutral and that market shares will be obtained in line with competitiveness. However, market share is set to gradually evolve from the current focus on alkaline electrolysis to a combination of technologies (Fig. 11.16). Since proton exchange membrane water electrolyzers (PEMEL) offer major development potential in the short and medium term, subsequent analysis is focused on this type of electrolyzer [12].

11.2.1

Cost components and cost reduction potential

An electrolyzer currently costs between 1000 and 1500 EUR/kW depending on type. In the future, a CAPEX value of between 500 and 700 EUR/kW is requiring for realizing the full potential of the electrolyzer technology. There is a fundamental lack of clarity in current studies on the main costs of system components

Fig. 11.16 Annual growth of electrolysis technologies [13]

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Fig. 11.17 Proportion of essential PEMEL components to entire system costs [13]

for various types of electrolyzers, since different weighting may be applied within individual processes and size classes depending on the design concept. An underlying trend can nonetheless be identified—namely, that costs for the stack take up a predominant share of the total electrolyzer costs:  PEMEL system 50%  AEL system (alkaline electrolysis) 40%  HTEL system (high-temperature electrolysis) 30% Fig. 11.17 shows the proportion of essential PEMEL components to entire system costs [13]. Stacks are themselves limited to a certain level of power output in large systems. As a result, only single-digit megawatt ranges are expected in the future as well. The stacks are thus arranged parallel (known as “numbering up”) to allow for higher system capacity. Correspondingly, the relative proportion of stack costs to the other components increases steadily as system size grows. Since the targeted application areas and orders of magnitude give rise to the expectation that 100 MW systems will increase in importance in the future, numbering up and the associated mass production of standardized parts represent a major challenge. Fig. 11.17 clearly shows that a very high cost reduction potential for stacks is expected in the years before 2030 and again before 2050. Cost components and thus the entire

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system costs should fall significantly as a result [13]. Economies of scale as a cost reduction strategy have already been presented using the example of the fuel cell in Sect. 11.1 and are also valid for the electrolyzer sector due to high technological compatibility; however, the technologies specific to electrolyzer production are analyzed in detail below.

11.2.2

Technologies

Membrane electrode assembly (MEA) Similar to MEA manufacturing for fuel cells, there are two fundamental approaches for electrolyzers. Generally, an electrode layer in the form of a liquid ink or wet paste (consisting of catalyst, PFSI and solvent) is applied to a substrate. The PTL-based approach uses a porous transport layer (PTL; referred to as GDL in PEMFC) as the substrate, whereas in the CCM-based approach, the membrane is coated. As with the fuel cell, the CCM approach makes a distinction between direct and indirect processes. The indirect process uses decal transfer film, with the ink first applied to this transfer film (usually Teflon or PTFE). This film is then used to transfer the catalyst to the membrane. The direct CCM approach skips this step, and the membrane is coated directly. To enable continuous control of the process, hot pressing partly relies on roller calenders, which means roll-to-roll processing can be implemented. In principle, all three processes offer potential for mass production, and are already in use in PEMFC manufacturing to a certain extent. However, it is important to note the comparatively high rigidity of the porous titanium transport layer (PTL) used in electrolysis. The integration of these components into a continuous production process requires close consideration. The decal process circumvents disadvantages such as the penetration of catalyst ink into the porous PTL (PTL approach) or membrane wrinkling during moistening with the solvent (direct CCM approach), since the electrode ink is already cured on contact with the membrane. However, the additional process step of using decal transfer film results in extra costs. Reinforcing membranes and using appropriate solvents are approaches that have already been adopted to prevent the aforementioned wrinkling of the membrane during the direct CCM process. Membrane reinforcement also enables the application of higher tensile forces, resulting in higher feed rates in the production process. Nevertheless, the decal transfer film process is the one mostly used in industrial production, since the process parameter settings are well understood and comparatively easy to control [13].

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Porous transport layer (PTL) The porous transport layer on the anode side in the PEMEL is currently exclusively made using titanium materials due to their high corrosion resistance. There are three different concepts for this process. During the production of titanium fiber felt, the first step is to make metal fibers using processes such as bundle drawing, foil shaving or melt spinning. These are processed into felt using sintering. Subsequent roller embossing ensures uniform thicknesses and surfaces [13].

Bipolar plates (BPP) Bipolar plates for electrolyzers are produced from either graphite composite materials or metallic materials. A subsequent plate coating for corrosion protection is often necessary. Titanium is used almost exclusively for the PEMEL, since this material allows for sufficiently high corrosion protection at standard electrode potential. While bipolar plates are primarily manufactured in compression molding or injection molding processes using composites, a sequential stamping process is often used for metallic titanium bipolar plates. Hydroforming is also viewed as a promising process option. Implementing a continuous process can optimize this manufacturing method further. Compared to a sequential stamping process, a continuous process allows for reduced system and tool costs and a finer degree of detail for flow field structures. In addition, a bipolar plate can be manufactured in a single process step—apart from the precise cutting and punching of holes for ducts (known as manifolds). In small batch sizes, these tasks are performed downstream using laser cutting. A mechanical stamping system could be used for large batch sizes. Winding up the shaped bipolar plate into a coil directly after the hydrogate process would deform the flow fields, so the aforementioned post-processing must take place directly in-line [13]. The bipolar plates are subsequently coated mainly through physical vapor deposition (PVD) in addition to electroplating processes. The process of magnetron cathode sputtering is often used in this context. This process is in principle a variation on cathode sputtering, in which a target is bombarded with positive ions from plasma in a vacuum system with constant gas discharge, where direct voltage is applied. One of the main cost drivers for bipolar plate coating is the price of electrically conductive material. One innovative approach for cost-efficient coating is offered by “TreadStone Generation 2” [13].

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11.2.3 Scaling In addition to the processes presented in Sect. 11.1.6, which can also be used in this area due to technology compatibility between fuel cells and electrolyzers, a number of special manufacturing strategies for upscaling electrolyzer production are presented below.

Membrane electrode assembly (MEA) The production concept for membrane electrode assemblies illustrated in Fig. 11.18 ensures high throughput, good homogeneity and ink stability. Using decal transfer film prevents solvent from affecting the membrane structure and PTL pores from becoming clogged. Spraying the wet coating creates layers with high performance. Infrared-assisted convection drying has also proven to be an efficient method. A subsequent continuous hot-pressing process ensures the lowest ohmic resistance and best adhesion. Shearing prevents reattachment of evaporated membrane material to the catalyst layer, while hot pressing ensures the highest level of adhesion for sealing.

Porous transport layers (PTL) The production concept illustrated in Fig. 11.19 is a high-precision process capable of high-throughput production rates for PTL. Expanded metal is by far the fastest technology and is highly flexible. This offers an advantage for scaling processes. The coarseness of the mesh prevents direct contact with the catalyst layer. An additional layer is therefore necessary. Laser cutting is used to avoid damage to the

Fig. 11.18 MEA production line concept. (Fraunhofer IPT Aachen)

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Fig. 11.19 PTL production line concept. (Fraunhofer IPT Aachen)

structure along the cutting contour. This method ensures precise shape and positional tolerance of cutting can be used on pre-coated plates and guarantees a fast process time with maximum flexibility. Cleaning with ultrasound achieves the best results. Mechanical pre-cleaning prevents coarse contamination of the ultrasonic bath and mild cleaning avoids mechanical impact. Physical deposition from the gas phase allows for a high deposition rate of 0.01 µm/s (for metals); thus, a suitable form of automation can be used to achieve the highest possible scalability. This is accompanied by a low level of contamination and very dense layers with strong adhesion, which also allows for a wide range of materials to be used.

Bipolar plates (BPP) The production concept illustrated in Fig. 11.20 for manufacturing metallic (and also pre-coated) bipolar plates starts with embossing. This fast-forming process enables a flank angle of approx. 75° between channels. The next production step is laser cutting. This ensures that there are virtually no changes to the structure along the cutting contour and that cutting is carried out based on a precise shape and positional tolerance. It also guarantees a fast process time with maximum flexibility. Sputtering allows for a high deposition rate of 0.01 µm/s (for metals), the greatest possible level of scalability (through automation), a low level of impurities and very dense layers with strong adhesion. Mild cleaning with ultrasound and oil-dissolving cleaning agents achieves the best results. Mechanical pre-cleaning prevents coarse contamination Different methods of resistance measurement (ex situ), leakage testing (in situ or ex situ) and power measurement (in situ) can be successively coupled for testing purposes. The result is a thorough testing system that prevents defective bipolar plates from compromising an entire stack. It also supports data-driven quality assurance.

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Fig. 11.20 BPP production line concept. (Fraunhofer IPT Aachen)

11.2.4

Rollout strategy

In addition to creating solutions for the industrial production of electrolyzers at qualities and costs that can be borne by the market, achieving technological sovereignty and a leading, globally competitive role for German companies is another key success factor. Continuously developing local product and value creation networks can enhance national production infrastructure in Germany and secure high market shares for German industry. Due to the market presence of Asian and North American companies, German companies can only currently assume a very small production share of the global electrolyzer market. Strategic investments and cooperation between politics, industry, research and investors would enable a firm foothold in the components market or on the machine and equipment construction market required for the production of components. The aim is to gain market share from current market leaders and increase it further. This would also significantly expand technological dimensions for German manufacturers in terms of component and subsystems production, system integration and other areas. One example of a project that aims to solve this challenge is the “Hydrogen Republic of Germany” ideas competition launched by the German Federal Ministry of Education and Research (BMBF). The objective is to develop technology for gigawatt-scale water electrolysis. The technology platform H2Giga was designed for this purpose. This enables information exchange and also communication between the areas of industry and research. In the start phase, there are 24 networks

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with over 130 project partners. The platform, which has an initial duration of four years, will cover the entire value chain and various electrolysis technologies. The H2Giga platform collates and centralizes information and fosters dialog that supports research and technology development partners in the participating projects by enabling them to contribute to or implement technological developments for mass production and the upscaling of electrolyzers in a more rapid and comprehensive way.

H2Giga platform Fraunhofer FRHY joint research project—Reference Factory for Electrolyzer Mass Production

The reference factory is designed to provide a flexible, multidirectional, open-ended technological solution for the large-scale production of electrolyzers (Fig. 11.21). New production and testing concepts are being developed within the scope of the project. Digital images are also createdand linked via a central virtual reference architecture. This not only results in new solutions for production, but also provides a technology toolkit that allows for a wide range of approaches. In this way, individual approaches can be compared in terms of production quality, scalability and cost. Assigned to process steps in the reference architecture, they can be used for calculating production variants and even entire value chains. This makes the comparison and evaluation of strategies for parallel processes, automation and vertical integration possible. In addition to investment costs, return on investment projections can thus be validated based on the planned production volume. This creates a solid basis for high-throughput, repeatable production, which ensures the ongoing development and enhancement of electrolyzer quality as well as the optimization of service life and can also be dynamically and flexibly adapted to changing conditions. Fraunhofer institutes involved: IWU, IPT, IPA, ENAS, IMWS C22 million Planned research funding: Planned project duration: April 1, 2021 to March 31, 2025

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Fig. 11.21 Fraunhofer FRHY joint research project—Reference Factory for Electrolyzer Mass Production (Fraunhofer IWU Chemnitz)

References

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References 1. Weichenhain U., Lange S., Koolen J. et al. (2020): Potenziale der Wasserstoff-und Brennstoffzellen-Industrie in Baden-Württemberg (Potential for the hydrogen and fuel cell industry in Baden-Württemberg). Roland Berger GmbH (ed.). https://um.badenwuerttemberg.de/fileadmin/redaktion/m-um/intern/Dateien/Dokumente/6_Wirtschaft/ Ressourceneffizienz_und_Umwelttechnik/Wasserstoff/200724-Potentialstudie-H2Baden-Wuerttemberg-bf.pdf, last viewed on December 7, 2021 (available in German only) 2. Fraunhofer IWU (2020): Fuel cells: Bipolarplatten für Stacks der nächsten Generation kommen aus Chemnitz. (Fuel cells: bipolar plates for next-generation stacks made in Chemnitz.) https://www.iwu.fraunhofer.de/de/presse-und-medien/presseinformationen/ PM_2020_Bipolarplatte.html, last viewed on March 17, 2021 (available in German only ) 3. RWTH Aachen und VDMA (2020): Produktion von Brennstoffzellen-Systemen (Production of fuel cell systems). ISBN 978-3-947920-13-6 4. U.S. Government/ACI Technologies (2011): Manufacturing Fuel Cell Manhattan Project. https://www.energy.gov/sites/prod/files/2014/03/f12/manufacturing_fuel_cell_ manhattan_project.pdf, last viewed on December 8, 2021 5. Porstmann S., Petersen A.C., Wannemacher T. (2019): Analysis of Manufacturing Processes for Metallic and Composite Bipolar Plates. Fuel Cell Conference FC3, November 26–27, 2019, Chemnitz 6. VDMA: Industrialisierung der Produktion von Brennstoffzellen-Systemen beginnt (Starting the industrialization of fuel cell system production). Press release dated July 10, 2020 7. Baum C., Janssen H., Brecher C. et al. (2020): Future Energy Storage Systems for Mobility Applications. Discussion paper, Fraunhofer IPT. https://doi.org/10.24406/ipt-n590461 8. Porstmann S., Wannemacher T., Richter T. (2019): Overcoming the Challenges for a Mass Manufacturing Machine for the Assembly of PEMFC Stacks. Machines 7 (4): 66. https://doi.org/10.3390/machines7040066 9. Richter, T. (2018): Skalierbarkeit und Effizienz im Visier (Setting sights on scalability and efficiency). Autoland Sachsen 1/2018: 18–19. https://www.autoland-sachsen.com/ skalierbarkeit-und-effizienz-im-visier/, last viewed on September 5, 2019 (available in German only) 10. Balzer C.H., Louis J., Schabla U. et al. (2017): Shell Wasserstoffstudie: energie der Zukunft? Nachhaltige Mobilität durch Brennstoffzelle und H2 (Shell hydrogen study: the energy of the future? Fuel cells and hydrogen for sustainable mobility). Shell Deutschland Oil GmbH, 37 p. 11. Porstmann S., Wannenbacher T., Drossel W.-G. (2020): A comprehensive comparison of state-of-the-art manufacturing methods for fuel cell bipolar plates including anticipated future industry trends. Journal of Manufacturing Processes 60: 366–383. https://doi.org/ 10.1016/j.jmapro.2020.10.041 12. Hydrogen Council (2020): Path to hydrogen competitiveness. A cost perspective. https://hydrogencouncil.com/wp-content/uploads/2020/01/Path-to-HydrogenCompetitiveness_Full-Study-1.pdf, last viewed on December 8, 2021

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13. Smolinka T., Wiebe N., Sterchele P. et al. (2020): IndWEDe study: Industrialisierung der Wasserelektrolyse in Deutschland: Chancen und Herausforderungen für nachhaltigen Wasserstoff in Verkehr, Strom und Wärme (Industrialization of water electrolysis in Germany: opportunities and challenges for sustainable hydrogen in transportation, electricity and heat). NOW GmbH, 200

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Klemens Ilse Fraunhofer Institute for Microstructure of Materials and Systems IMWS Jan Wenske  Andreas Reuter  Fabian Pascher  Sylvia Schattauer Fraunhofer Institute for Wind Energy Systems IWES Sebastian Schmidt  Herman Hilse  Welf-Guntram Drossel Fraunhofer Institute for Machine Tools and Forming Technology IWU Abstract

As part of our economic and legal systems, standards and certification processes lay the foundations for important issues such as occupational safety and environmental protection. They make it possible to combine components to form systems, as well as ensuring quality and compatibility, creating transparency and protecting consumers. Standards and certification are also decisive factors in knowledge and technology transfer. Germany is a pioneer and key driver of standardization in a large number of sectors, from mechanical and plant engineering to energy technology. There are also numerous national and international initiatives aimed at standardizing hydrogen technologies. This chapter gives an overview of existing standards from a variety of fields that relate to hydrogen technologies, and thus also outlines the complexity of this field of technology.

© Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_12

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12.1 The importance of standardization for hydrogen technologies Standardization and certification are central components of any innovative industry policy, as well as an essential tool for the knowledge economy. They play a decisive role in accelerating the implementation of new developments and in economic performance as a whole [1]. In addition, as part of our economic and legal systems, standards and certification processes lay the foundations for important issues such as occupational safety and environmental protection [2]. Standards are drawn up by bodies such as councils and committees, for example, and define what constitutes the technological state of the art, along with requirements for products and services. They make it possible to combine components to form systems, as well as ensuring quality and compatibility, creating transparency and protecting consumers. They are also a decisive factor in knowledge and technology transfer [2]. Certification processes are carried out by impartial third parties with the aim of demonstrating that products, processes and services conform to a specific standard [3]. Germany has been and continues to be a pioneer and key driver of standardization activities in many sectors, including the automotive industry, mechanical and plant engineering, and energy technology. However, at present, advancements in the work on standardization and certification for hydrogen technologies in Germany and Europe are much more limited when compared to the abovementioned sectors. This is in spite of the fact that industry, politics and science are all expressing an immense level of need in this area. This is because formulating and implementing standards and certification processes for the field of hydrogen technologies and the associated production processes can and will make a significant contribution to the successful establishment of a hydrogen economy and, furthermore, to achieving the transformation of German, European and global energy systems. Working on and implementing these standards and certifications in an intensive, targeted manner will result in many benefits for stakeholders ranging from manufacturers and users to banks and insurance companies in the future. Standards and certification processes are a vital factor in bringing hydrogen systems and technologies from the prototype stage to market-readiness in the fields of production and manufacturing. They also make it possible to draw verified, reliable conclusions about a technology’s long-term performance, service life and maintenance. In addition, standards can play a key role in ensuring that increasingly important topics such as recycling and the circular economy are integrated into the field of hydrogen technologies. This generally involves key elements of sus-

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tainable economic management that span multiple different kinds of technology as well as giving equal consideration to environmental and economic concerns. Other benefits include creating considerable competitive advantages for the domestic industry sector, guaranteeing transparency and quality, and establishing a reliable foundation for investors, operators, banks and insurance companies. Finally, standardization and certification in the field of hydrogen technologies is extremely important for individual national economies. This is because they ensure that essential energy systems will not break down in the future, thus guaranteeing a secure energy supply for industry and society.

12.2 Standardization overview: stakeholders and processes There are various established terms and processes in use in the field of standardization, and in order to understand these properly, it is important to know how they are defined and who is involved. Consequently, the following sections describe and explain the concepts and stakeholders involved in standardization in the field of hydrogen technologies.

12.2.1

Terminology and processes

Standards are formulated in committees involving interested parties, e.g. companies, government authorities and institutes. They are then adopted by consensus and published by recognized standardization organizations [1]. This systematic process for achieving uniformity in tangible and intangible matters is known as standardization (Fig. 12.1). The result is a document that establishes rules, directives (binding, normative requirements), guidelines (recommended courses of action) and characteristics relating to activities or their results, which are applicable to general and recurring use [4]. However, non-binding standards can also be created by other (temporary) bodies without involving all interested parties or achieving a consensus (as occurred with HTML, mobile communications standards and Bluetooth, for example) [1]. In English, this process for formulating specifications also falls under the term “standardization” (although other languages, such as German, use different terminology for binding and non-binding standardization). Standardization activities are conducted at national, European and international levels. Applying standards is generally voluntary; however, in some cases, there may be a legal obligation to apply them, due to regulations or other forms of legislation [4]. In this instance, a regulation refers to any legislation governing

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Fig. 12.1 The standardization process. (simplified illustration based on [4])

Fig. 12.2 Standards within the legal system. (see [4])

the mandatory execution of a law (Fig. 12.2). Certification refers to a procedure whereby third parties confirm that a product, process or service complies with certain requirements, such as a standard. By contrast, accreditation is a process whereby a third party confirms and formally recognizes that a certain entity has the professional competence required for specific tasks [5].

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12.2.2

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Standardization in Germany

There are various stakeholders involved in standardization processes for hydrogen technologies in the Federal Republic of Germany. The German Institute for Standardization (Deutsches Institut für Normung e. V., DIN, German Institute for Standardization), was originally founded as the “Standards Association of German Industry”. Since 1975, when it signed an agreement with the German federal government which recognized the DIN as the national standards body for Germany, it has been the country’s most important national standards organization. In addition, the DIN and the German Association for Electrical, Electronic, and Information Technologies (Verband der Elektrotechnik Elektronik Informationstechnik e. V., VDE) have joined forces to conduct standardization activities in the fields of electrical engineering, electronics and information technology in the German Commission for Electrical, Electronic & Information Technologies (Deutsche Kommission Elektrotechnik, Elektronik Informationstechnik, DKE). As such, the DKE simultaneously falls under the VDE as a business unit and the DIN as a standardization committee. The DIN and DKE supervise a large number of committees concerned with the standardization of hydrogen technologies. They also represent Germany’s standardization stakeholders at European and international levels (i.e., in CEN/CENELEC and ISO/IEC committees) (Fig. 12.3). Apart from the DIN and DKE, there are many other stakeholders involved in standardization for the field of hydrogen at national and international levels. Notable national organizations here include the Association of German Engineers

Fig. 12.3 Overview of national, European and international institutions for standardization

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(Verein Deutscher Ingenieure e. V., VDI), which describes itself as the largest German association of engineers and scientists and publishes up to 250 VDI guidelines every year. For example, the committee working on VDI 4635 is developing a group of guidelines focusing on power-to-X technologies, which will also include hydrogen production [6]. The German Technical and Scientific Association for Gas and Water (Deutscher Verein des Gas- und Wasserfaches e. V., DVGW) establishes rules for the gas and water industries. Its publications include a licensing guide for power-to-gas plants [7]. Compliance evaluations and accreditation form an essential component of the quality infrastructure for standardization procedures. These processes involve testing products and services and certifying that they fulfill certain, prescribed requirements. In Germany, the German Accreditation Body (Deutsche Akkreditierungsstelle, DAkkS) has legal responsibility for providing accreditation for entities that performance compliance evaluations. As an independent research institution, the DAkkS verifies that such entities have the required technical expertise. Accredition from the DAkkS confirms that these entities can fulfill their tasks competently and in accordance with applicable requirements. By verifying that the results of certificates, test reports and inspections are trustworthy, the accreditation process helps to ensure that they are globally recognized and comparable.

12.2.3

International standardization

The International Organization for Standardization (ISO), which is headquartered in Geneva, is responsible for establishing international industrial standards in all fields apart from electrical engineering and telecommunications, as well as ensuring that existing regional or national standards can be compared at an international level. The term International Standard (IS) indicates a formal, binding standard. The ISO sometimes collaborates with the other major international standardization organization, the International Electrotechnical Commission (IEC), which is responsible for electrical and electronic technologies, and is also headquartered in Geneva. The resulting international standards then start with the designation ISO/IEC, to indicate their origin. Within the IEC and ISO, standards are formulated and revised within working groups that are organized by subject area, known as the technical committees (TC) and their subcommittees (SC). These must report on their results to a central Standardization Management Board (SMB). The European Standards Organisations (CEN, CENELEC), which are headquartered in Brussels, integrates ISO and IEC standards into the European standards system and align European standards. CEN/CENELEC member states then have

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an obligation to implement them as national standards. While adopting international ISO and IEC standards is voluntary at a national level, it is generally an indispensable requirement for free global trade and putting products and services into market circulation. The Joint Research Centre (JRC) is a Directorate-General of the European Commission and acts as the Commission’s expert body for scientific services. The JRC works independently of private or commercial interests and supports European standardization processes and collaborations with third countries (e.g., to help align EU standards). Another group of mostly international organizations is responsible for independent product monitoring and certification, which is aimed at ensuring compliance with technical guidelines and standards. These include Underwriters Laboratories (UL), an American company that tests and certifies the technical safety of products. UL conducts testing to verify whether products, components and materials meet specific requirements; these requirements can include both internationally recognized and in-house standards. The company often performs tests according to its own, more stringent safety requirements, which, depending on the standard, may also take the manufacturing process for the product into account. As such, certification by UL is widely accepted across the world. This means that UL certification not only increases export opportunities for products in Europe, but also in the USA, Canada and Asia, for example. Despite this, UL certification carries no more legal weight than other labels. By contrast, the European CE marking is a legal requirement. Other international inspection, classification and certification companies include DNV (Det Norske Veritas), which also provides technical consulting and engineering services in areas such as the conventional and renewable energy sectors and the oil and gas industries. At a fundamental level, the purpose of classification and certification is to establish consistent, binding rules for assessing and insuring against risks, which in turn creates transparency and inspires trust from stakeholders. Classification and certification measures involve various steps, such as conducting accredited procedures, tests and measurements. The DAkkS represents German interests regarding accreditation within European and international accreditation organizations, as a full member of such bodies. The organizations in question consist of the European co-operation for Accreditation (EA), which is an association of European accreditation bodies, the International Accreditation Forum (IAF), which is a global network of accreditation bodies, and the International Laboratory Accreditation Cooperation (ILAC), the worldwide association for collaboration between accreditation bodies responsible for laboratories and inspection organizations. The Association of Issuing

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Bodies AIB has particular significance for hydrogen technologies, as it will most likely be responsible for the European guarantee of origin system for green and low-carbon hydrogen, just as it is for the proof of origin system for renewable energies (see Example 4 in Sect. 12.4). The primary goal of the international accreditation network is to ensure reciprocal recognition of the accreditations, services and results provided by accredited bodies, in order to prevent a costly requirement for multiple accreditations.

12.3 Existing standards for hydrogen technologies 12.3.1 Overview There has been much activity as regards the standardization of hydrogen technologies at national and international levels. While the purpose of this chapter is not to give an exhaustive account of all these standardization activities, an overview of existing standards from various areas will be provided below, with a view to demonstrating the complexity of the field. Fig. 12.4 gives a visual overview of existing standards in the field of hydrogen technologies, broken down into different fields of application. The standards cover factors such as hydrogen production, transportation, infrastructures and storage, as well as the use of hydrogen in the transportation, industry and heating sectors, and high-level safety measures. This overview is by no means complete, as it cannot depict all the ongoing activities of the numerous national and international standards committees (each of which is turn divided into numerous subcommittees) that are currently working on standardization in the hydrogen sector. The existing standards from this wide range of areas will be presented in more detail in the following sections.

12.3.2

Production

Hydrogen is produced intentionally on an industrial scale or unintentionally as a by-product. Intentional hydrogen production can be divided into processes that are powered by fossil-based or electrical energy. The fossil-based processes are covered by the ISO 16110-1 to 16110-2 standards for production plants that use natural gas, methane-enriched gas, refined petroleum, and hydroxy and ketone compounds. The ISO 22734 standard applies to electrolyzer technologies that use

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Fig. 12.4 An overview of published standards for the hydrogen economy

anion-conducting membranes (AEM) under basic conditions or proton-conducting (PEM) membranes under acidic conditions. When it comes to ensuring climate neutrality, carbon capture and storage processes are particularly important for today’s most commonly used processes, as these are dependent fossil-based hydrocarbons. This is why six of the nine hydrogen production standards cover this technological field. In addition, the DIN EN 13445 standard series addresses requirements for the unfired pressure vessels needed in hydrogen production, distribution and storage.

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12.3.3 Transportation and infrastructure Hydrogen has a very low volumetric energy density under standard atmospheric conditions (273 K, 1 bar), which means that compression is generally required in order to distribute hydrogen efficiently via the supply infrastructure. Therefore, compression is associated with special requirements for piping, instrumentation, gas containers and safety management. These issues have already been covered in existing, published standards (Table 12.1), which not only take into account gas transportation pipelines, but also other transportation options, such as railways.

12.3.4 Storage One decisive advantage of the hydrogen economy is that it makes it possible to store larger quantities of electrical energy in substances with a high density of energy over long periods of time (see also Chap. 8). This means that hydrogen production does not necessarily have to correspond to demand, which could make a decisive contribution to stabilizing the energy networks. The standards that are currently available (Tables 12.2 and 12.3) cover the materials that can used for pressurized vessels, underground storage and refueling stations. Table 12.1 Titles of the production-related standards listed in Fig. 12.4 Short title ISO 22734 ISO 16110-1 to -2 ISO 27919-1

ISO 27913 ISO 27914 ISO/TR 27915 ISO/TR 27912 ISO/TR 27921 DIN EN 13445—series

Full title Hydrogen generators using water electrolysis—Industrial, commercial, and residential applications Hydrogen generators using fuel processing technologies Carbon dioxide capture—Part 1: Performance evaluation methods for post-combustion CO2 capture integrated with a power plant Carbon dioxide capture, transportation and geological storage—Pipeline transportation systems Carbon dioxide capture, transportation and geological storage—Geological storage Carbon dioxide capture, transportation and geological storage—Quantification and verification Carbon dioxide capture—Carbon dioxide capture systems, technologies and processes Carbon dioxide capture, transportation, and geological storage—Cross Cutting Issues—CO2 stream composition Unfired pressure vessels

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Table 12.2 Titles of the standards relating to transportation and infrastructure from Fig. 12.4 Short title DIN CEN/TS 12007-6 DIN EN 10216-1 to -6 DIN EN 10217-1 to -6 DIN EN 12007-1 to -5 DIN EN 12186 DIN EN 12279 DIN EN 12327 DIN EN 12583 DIN EN 12732 DIN EN 13445—series DIN EN 13674-1 to -4 DIN EN 14382

DIN EN 15399

DIN EN 16314 DIN EN 16348

DIN EN 17339 DIN EN 1776 DIN EN 334 DIN EN 10229 DIN EN ISO 11623 DIN EN ISO 15112

Full title Gas infrastructure—Pipelines for maximum operating pressure up to and including 16 bar Seamless steel tubes Welded steel tubes for pressure purposes Gas infrastructure—Pipelines for maximum operating pressure up to and including 16 bar Gas infrastructure—Gas pressure regulating stations for transmission and distribution—Functional requirements Gas supply systems—Gas pressure regulating installations on service lines—Functional requirements Gas infrastructure—Pressure testing, commissioning and decommissioning procedures—Functional requirements Gas infrastructure—Compressor stations—Functional requirements Gas infrastructure—Welding steel pipework—Functional requirements Unfired pressure vessels Railway applications—Track—Rail Safety equipment for gas pressure control set-ups and gas safety shut-off devices for inlet pressure up to 10 MPa (100 bar) Gas infrastructure—Safety Management System for Gas Networks with maximum operating pressure up to and including 16 bar Gas meters—Additional functionalities Gas infrastructure—Safety Management System (SMS) for gas transmission infrastructure and Pipeline Integrity Management System (PIMS) for gas transmission pipelines—Functional requirements Transportable gas cylinders—Fully wrapped carbon composite cylinders and tubes for hydrogen Gas infrastructure—Gas measuring systems—Functional requirements Gas pressure regulators for inlet pressures up to 10 MPa (100 bar) Evaluation of resistance and stability of steel products against hydrogen induced cracking (HIC) Gas cylinders—Composite construction—Periodic inspection and testing Natural gas—Determination of energy (ISO 15112:2018)

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Table 12.2 (continued) Short title Full title DIN EN ISO 80079-36/37 Explosive atmospheres DIN ISO 17533 Welding for aerospace applications—Welding information in construction documents ISO 16111 Transportable gas storage devices—Hydrogen absorbed in reversible metal hydride ISO 17081 Method of measurement of hydrogen permeation and determination of hydrogen uptake and transport in metals by an electrochemical technique ISO/TS 17519 Gas cylinders—Refillable permanently mounted composite tubes for transportation Table 12.3 Full titles of the storage-related standards from Fig. 12.4 Short title DIN EN 1918-1 to -5 DIN EN 10028-1 to -7 ISO 9328-1- to -7 ISO 19880-1

Full title Gas infrastructure—Underground gas storage Flat products made of steels for pressure purposes Steel flat products for pressure purposes—Technical delivery conditions Gaseous hydrogen—Fueling stations

12.3.5 Transportation and industry Direct customers for hydrogen are to be found in the transportation and industry sectors in particular. The relevant standards (Table 12.4) for these areas provide detailed requirements for topics such as the use of hydrogen as a fuel, the efficiency of refueling systems and performance data for vehicles powered by fuel cells.

12.3.6 Heating sector Hydrogen can be used for heat generation in boilers designed for that purpose. The standards (Table 12.5) in this area contain specifications for the boilers, gas piping and gas flow.

12.3.7 Safety Because hydrogen forms highly explosive mixtures with air, oxygen and other oxidizing gases, safety issues are an important factor in standardization.

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Table 12.4 Titles of the standards relating to transportation and industry from Fig. 12.4 Short title ISO 13984 ISO 13985 ISO 14687 ISO 23828 ISO TR 11954 DIN EN 15001-1 to -2

DIN ISO 19880-1 ISO 23273

DIN EN 17124

DIN ISO 21087

Full title Liquid hydrogen—interface of fueling for land vehicles Liquid hydrogen—fuel tanks for land vehicles Hydrogen fuel quality—Product specification Fuel cell vehicles—Energy consumption measurement—Vehicles fueled with compressed hydrogen Fuel cell road vehicles—Maximum speed measurement Gas infrastructure—Gas pipework with an operating pressure greater than 0,5 bar for industrial installations and greater than 5 bar for industrial and non-industrial installations Gaseous hydrogen—Fueling stations Fuel cell road vehicles—Safety specifications—Protection against hydrogen hazards for vehicles fueled with compressed hydrogen Hydrogen fuel—Product specification and quality assurance—Proton exchange membrane (PEM) fuel cell applications for road vehicles Gas analysis—Analytical methods for hydrogen fuel—Proton exchange membrane (PEM) fuel cell applications for road vehicles

Table 12.5 Standards relating to the heating sector from Fig. 12.4 Short title DIN EN 1775

DIN EN 15502—series DIN EN 437

Full title Gas supply—Gas pipework for buildings—Maximum operating pressure less than or equal to 5 bar—Functional recommendations Gas-fired heating boilers Test gases—Test pressures—Appliance categories

Table 12.6 Safety-related standards from Fig. 12.4 Short title DIN EN 16726 DIN EN 676 ISO/TR 15916 ISO/TS 19883

Full title Gas infrastructure—Quality of gas—Group H Forced draft burners for gaseous fuels Basic considerations for the safety of hydrogen systems Safety of pressure swing adsorption systems for hydrogen separation and purification

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12.3.8 Fuel cells There is a comparatively high level of standardization as regards fuel cell applications. One particularly noteworthy example in this context is the DIN EN IEC 62282 series on fuel cell technologies, which comprises more than 20 individual standards. The standards of this series cover definitions of terms (Part 1), fuel cell modules (Part 2), stationary fuel cell power systems (Part 3), fuel cell power systems for propulsion (Part 4), portable fuel cell power systems (Part 5), micro fuel cell power systems (Part 6), test methods (Part 7) and energy storage systems using fuel cell modules (Part 8).

12.4 Use cases Example 1: Test procedures for electrolyzers If electrolyzers for producing green hydrogen are to achieve large-scale market penetration, project managers, investors and users must have a deep trust in the technology. While there are many factors involved in building this trust, one important aspect of the foundation for it relates to recognized and—under ideal circumstances—standardized test protocols and procedures for evaluating the performance and durability of electrolyzers under conditions that are representative of current and future applications. This means realistic, dynamic operating conditions should be simulated during performance and stress tests, e.g., for off-grid electrolyzer applications that rely on fluctuating power sources such as wind or solar energy, or applications that operate in part-load mode in order to stabilize the electrical grid. These tests must be conducted at the level of the cell, (short) stack and especially system. Material- and component-level testing can also be helpful. The only standard currently available, ISO 22734, which defines testing procedures for electrolyzers, is written in relatively general terms and is nowhere near the level of specificity or detail required for the caliber of testing needed to build trust. Consequently, industry representatives and research institutions—including experts from the Fraunhofer-Gesellschaft—are currently working in an EU-wide initiative to compile and align protocols for cell, short-stack and system testing. The results will be presented in a JRC technical report (currently being prepared). Another helpful step involves the development of standardized test hardware that enables the comparison of materials from different manufacturers under realistic operating conditions. This is particularly useful for comparing individual

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Fig. 12.5 Fraunhofer hydrogen research centers involved in fields such as certification

components such as the membrane electrode assemblies from PEM electrolyzers and has already been implemented in the field of fuel cells [8]. A consortium of Fraunhofer institutes working on the hydrogen flagship projects H2 Giga and H2 Mare [9], funded by the Federal Ministry of Education and Research of Germany (BMBF), is planning to develop a similar system for electrolyzers on a stack level. In the medium term, the goal in this context is to align the testing procedures and incorporate them into a certification process for electrolyzers. An ongoing collaborative initiative by the Fraunhofer-Gesellschaft and the international classification society DNV aims to address this by developing a scheme for certifying the different types of electrolyzers, in cooperation with industry partners (see Example 2). Practical testing of this certification scheme will be conducted at a variety of locations, including Fraunhofer’s hydrogen research centers in Bremerhaven, Leuna and Görlitz (Fig. 12.5).

Example 2: Certifying electrolyzer systems As yet, there is no established, universal process for system certification in the hydrogen technology field. Ongoing national and international activities are almost

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exclusively focused on achieving the basic requirements for technical standardization of electrolyzers. Any system certification process should ideally draw on and/or refer to these standards in its official documentation. The ideas involved in, and the advantages offered by, agreeing on a defined scheme for system certification can be best explained using the example of wind energy. In the early 1980s, organizations such as the DNV joined forces with industry representatives and scientific interest groups to launch initiatives aimed at standardizing wind turbines and establishing procedures for testing turbine design and other specified properties, as well as compliance with the newly created standards. This certification scheme covered a variety of factors, including the design and dimensioning regarding loads, demonstrating strength and stability, safety systems and operating performance under specific environmental conditions, such as general wind classes, climate zones, onshore and offshore locations, and emissions together with issues such as noise and electrical grid compatibility. These days, turbine manufacturers have the option and/or obligation to have their turbines be inspected by independent testing organizations (such as DNV, TÜV or Bureau Veritas) in accordance with a particular certification scheme prior to global distribution, in order to obtain a unit certificate for their own product. In some markets and countries, the unit certificate quickly became a certificate of conformity that is required prior to connection to the electrical supply grid. Today, the substantiating documentation required for conformity assessments comprises expert appraisals, calculations, simulations and measurements from field testing of prototypes or large-scale test benches (system and component testing). These must be provided by accredited laboratories or measuring institutes, which must in turn have gone through accreditation for the methods they use, e.g., by the DAkkS. In retrospect, it is apparent that establishing the system certification process enabled wind farm operators, investors, insurers and grid operators to trust that the plant technology had reached a sufficient maturity level and undergone standardized testing; this trust was essential to rapid market ramp-up. The manufacturers had to provide the independent testing companies with in-depth information on their technology, their production processes and the quality management system they used. Consequently, a process that had encountered considerable resistance to begin with quickly became a quality seal and thus a selling point for professional manufacturers, especially in new markets. In late 2020, the DNV and the Fraunhofer-Gesellschaft launched an initial collaborative project aimed at transferring this established approach from the field of wind energy to a scheme for electrolyzer system certification (Fig. 12.6). In this initiative, the partners and a number of industry stakeholders are working together to lay the required foundation in the course of their ongoing activities, with a view

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Fig. 12.6 Diagram of the steps involved in type or unit certification for types and units of electrolyzers

to documenting their results in a technical report in 2022. This will serve as a preliminary step toward creating a future certification standard.

Example 3: Approval procedure for power-to-gas plants Power-to-gas plants are viewed as a promising application area for hydrogen technologies. For example, they can be used to store renewable energy and reduce strain on the power grid. There are already more than 30 of these plants in operation in Germany. With these initial facilities, it became apparent that planning, constructing and operating these plants and in particular, going through the necessary approval procedures and complying with the applicable guidelines, standards, regulations and laws are all very complex and confusing processes. Fig. 12.7 demonstrates this complexity, as well as the hierarchy of the legislation involved (see also Fig. 12.2). The figure lists the laws governing various topics such as planning approval, construction permits, environmental protection, pollution prevention, nature conservation, occupational health and safety, and safety engineering/fire prevention, and shows how the regulations for each law draw on guidelines, standards and rules. It is difficult to estimate how long a given approval procedure will last and whether the outcome will be successful for the various parties involved in the process including planners, general contractors and government authorities. As such, these procedures quickly become a cost factor that it is difficult to assess precisely

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Fig. 12.7 Hierarchical overview of the applicable laws, regulations, guidelines, standards and rules governing the approval of power-to-gas plants (this non-exhaustive list is derived from [10])

for most projects. This shows that clear guidelines would be required for powerto-gas plants to achieve significant market penetration. To provide some direction here, the DVGW and a number of partners produced a comprehensive set of guidelines on approval law, which cover topics such as the planning, construction and operation of power-to-gas plants with the aim of integrating renewable energies. These guidelines were drawn up as part of the publicly funded PORTAL GREEN project (see [7]).

Example 4: Establishing a guarantee-of-origin system for green hydrogen If we are to develop a hydrogen economy that can compete at a global level, then one of the most important regulatory challenges to be tackled is the question of a functional certification and guarantee-of-origin system. This system must be able to prove how a given unit of hydrogen was produced and what environmental impact it has caused, especially as regards greenhouse gas emissions. This is particularly important in light of the fact that a color-based classification system is currently being used to describe how hydrogen is produced.

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CertifHy is a pioneering, EU-wide guarantee-of-origin (GO) system for green and low-carbon hydrogen [11]. Having already undergone pilot testing, the initiative moved on to CertifHy Phase III in October 2020. This phase aims to establish the system across Europe. This system has been developed by the newly established Gas Scheme Group (GSG) in compliance with article 19 of RED II, the standard for guarantees of origin CEN-EN 16325, which is currently undergoing revision, and the general requirements of the Association of Issuing Bodies (AIB), which is already responsible for the European guarantee-of-origin system for energy certificates (AIB EECS standard). Widely acclaimed even at an international level, the CertifHy project has laid vital building blocks in the foundation for a hydrogen guarantee-of-origin system.

References 1. Herrmann P., Blind K. et al. (2020): Relevanz der Normung und Standardisierung für den Wissens- und Technologietransfer (Relevance of standardization for knowledge and technology transfer). https://www.fraunhofer.de/content/dam/zv/de/presse-medien/ 2020/dezember/studie-relevanz-der-normung-und-standardisierung-fuer-den-wissensund-technologietransfer.pdf, last viewed on December 11, 2021 2. German Federal Ministry for Economic Affairs and Climate Action: Standards. https:// www.bmwk.de/Redaktion/EN/Artikel/Technology/standards.html, last viewed on December 11, 2021 3. VOREST AG: Was ist eine Zertifizierung und wie lautet die Definition? (What is a certification and how is it defined?) https://www.din-iso-zertifizierung-qms-handbuch.de/ zertifizierung/, last viewed on December 11, 2021 4. DKE VDE DIN (2020): Basics of Standardization. https://www.dke.de/en/standardsand-specifications/basics-of-standardization, last viewed on December 11, 2021 5. Bayerische Landesanstalt für Landwirtschaft (Bavarian state institute for agriculture): Qualitätsmanagement LfL: Definitionen, Qualitätssicherung.(Bavarian state institute for agriculture quality management: definitions, quality assurance.) https://www.lfl.bayern. de/verschiedenes/qualitaetsmanagement/031139/index.php, last viewed on December 11, 2021 6. VDI (2019): Power-to-X: VDI startet technische Regelsetzung (Power-to-X: VDI launches technical regulations). https://www.vdi.de/news/detail/power-to-x-vdi-startettechnische-regelsetzung, last viewed on December 11, 2021 7. DVGW—German Technical and Scientific Association for Gas and Water (2020): Portal Green—Entwicklung eines Power-to-Gas-Leitfadens zur Integration erneuerbarer Energien (G 201735) (Portal green—development of a power-to-gas guide for the integration of renewable energies (G 201735)). https://www.dvgw.de/themen/forschungund-innovation/forschungsprojekte/dvgw-research-project-portal-green, last viewed on December 11, 2021

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8. Bednarek T., Tsotridis G. (2021): Development of reference hardware for harmonised testing of PEM single cell fuel cells. EUR Vol. 30592 EN. Publications Office of the European Union, Luxembourg. https://publications.jrc.ec.europa.eu/repository/bitstream/ JRC123219/jrc123219__zerocell_report_pubsy_v3_%282%29.pdf, last viewed on December 11, 2021.35012 Standardization, testing and certification 9. German Federal Ministry of Education and Research: Welcome to the Hydrogen Flagship Projects! https://www.wasserstoff-leitprojekte.de/home, last viewed on December 11, 2021 10. Koralewicz M., Glandien J., Hüttenrauch J. et al. (2020): PORTAL GREEN— Genehmigungsrechtlicher Leitfaden für Power-to-Gas-Anlagen—Errichtung und Betrieb (PORTAL GREEN—licensing guidelines for power-to-gas plants—construction and operation). GRS-S-59 Band 1. https://www.grs.de/sites/default/files/publications/ grs-s-59-1_0.pdf, last viewed on December 11, 2021 11. CertifHy. https://www.certifhy.eu, last viewed on December 11, 2021

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Christian Elsässer1  Thorsten Michler1  Peter Gumbsch1, 2 1 Fraunhofer Institute for Mechanics of Materials IWM, Freiburg 2 Institute of Applied Materials IAM, Karlsruhe Institute of Technology KIT, Karlsruhe Abstract

In order for the hydrogen economy to be widely accepted by society, the infrastructure of technical facilities for the storage, distribution and use of hydrogen as an energy carrier must not pose any risks to safety or hazards that may cause accidents. To be economically viable, the systems must have a high level of operational safety and a long service life. During operation of these systems, many H2 -specific local material changes occur due to mechanical, thermal, chemical or electromagnetic loads. These only have a negative impact on the safety, function, reliability and service life of the systems if weak points have not already been taken into account in the design stage and controlled through systematic monitoring of status and process data during the operation of the system, or if these have been avoided altogether by selecting suitable materials when constructing the system. In fact, there is still great potential for optimization in designing systems with appropriate materials that work well with hydrogen as an energy carrier to establish a secure infrastructure for a hydrogen economy that is capable of sustainable development on the energy market. Fraunhofer is taking the initiative to achieve this by working with technology platforms and collaborative projects as part of the National Hydrogen Strategy in Germany. This chapter outlines the interaction of hydrogen with materials and illustrates their importance in terms of accident prevention and extending the service life of technical systems in a hydrogen infrastructure.

© Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_13

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13.1 Motivation: Hydrogen as an energy carrier The decomposition of water into its chemical elements of hydrogen and oxygen requires a great deal of energy. When the two elements are combined again to form water, that energy is released again. As a natural part of air, oxygen is available in large quantities almost everywhere. Hydrogen in elemental form, on the other hand, is not present in its pure form in nature and must therefore be separated from water or other compounds using chemical reactions. Because water is chemically very stable, mixtures of its components of hydrogen and oxygen are highly reactive. They combine completely to form water when given even low thermal or electrical stimuli. The uncontrolled, exothermic reaction from mixing hydrogen and oxygen gases to form steam, known as the oxyhydrogen reaction, releases a large amount of energy very quickly, and is well known and even notorious for its severity. Hydrogen offers great benefits as an energy carrier precisely due to this fact that separated hydrogen and oxygen release energy when combined. The suitability of hydrogen as an energy carrier depends in particular on whether the reaction can be carried out in a controlled manner with correct metering. Various technologies exist that can harness the energy safely in a controlled form of work, rather than in the uncontrolled form of heat as it occurs in the oxyhydrogen reaction. Electrochemical reactors are particularly important for the energy sector: In electrolytic cells, electrical energy is supplied to split the reactant water, and gaseous hydrogen and oxygen are released separately as products of the reaction. Conversely, in fuel cells, gaseous hydrogen and oxygen react to form water again, releasing electrical energy. The electrical energy absorbed by an electrolytic cell can be supplied through means such as the electric generator of a wind turbine. The electrical energy emitted by a fuel cell can, for example, drive an electric motor in a vehicle. In contrast to the oxyhydrogen reaction of combining hydrogen and oxygen gases to form water, in a fuel cell the reaction of the elements takes place inside an inorganic or organic material structure that conducts ions and electrons. Electrolytic cells and fuel cells differ only in the direction of the supply of reactants and the release of products from the electrochemical reaction. An energy infrastructure network should essentially perform four tasks: generating an energy carrier in one location, storing it, distributing it and using it in another location. When hydrogen is used as an energy carrier, one possible way these four tasks can be carried out is as follows: In a wind turbine, gaseous hydrogen is produced using electrical energy in an electrolytic cell. The hydrogen gas

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can be stored in a tank system until it is needed. The gas can be transported via a pipeline system to where it is required. It can be used there for chemical reactions, or, in a stationary or mobile fuel cell, it can be mixed with oxygen from the air in order to create a reaction that produces water again and releases electrical energy. As an energy carrier, hydrogen gas is in competition with ion batteries as an electrochemical energy storage system or with supercapacitors as an electrostatic energy storage system. Electrical voltages and currents flowing outside the system are generated inside supercapacitors using electrostatic charge displacement from easily movable negative electrons to immobile positive ions. In ion batteries, electricity is generated using the electrochemical charge separation of moving ions and electrons, while in hydrogen reactors, this is done using the chemical reaction of the positive hydrogen ions and negative oxygen ions. Hydrogen’s high energy and power density mean there are advantages to using hydrogen as an energy carrier rather than generating electric current from electrons or ions: The space required to store the same amount of energy is significantly smaller for compressed molecular hydrogen in gaseous or liquid form than for other electrical energy storage devices. The time required to release the same amount of energy is also significantly shorter. Further advantages of hydrogen as an energy carrier are its almost unlimited availability and the fact it can be extracted from water in a sustainable way. In addition, the conversion of hydrogen with oxygen to water is not harmful to human health or the environment. This all makes hydrogen an appealing energy carrier for the future. However, particular care must be taken when using hydrogen as an energy carrier in technical systems. Fuel gas escaping from a system can easily ignite in the air (oxyhydrogen reaction) and lead to dangerous accidents that may cause considerable damage. Potential safety risks and accident risks can put general society’s acceptance of a technology into question. For this reason, when it comes to hydrogen infrastructure, it is absolutely imperative that the technical systems are built and operated in such a way that risks of accidents arising from the use of hydrogen are consistently prevented. This will enable hydrogen technologies to not only be economically profitable, but also help them to be accepted by society. It is therefore particularly important to prevent the uncontrolled release of hydrogen gas from a system into the air. For a long time now, accident-proof infrastructure with a high level of technical maturity has been in place worldwide for the use of fossil hydrocarbon compounds as energy carriers in gaseous or liquid forms (natural gas, gasoline or diesel fuels). When compared to the use of hydrocarbon compounds, the main challenge associated with hydrogen in terms of the risk of accidents is not so much its high

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chemical reactivity with oxygen as the fact that hydrogen, the lightest chemical element, can react with many materials used in engineering. This effect that hydrogen has on materials is often referred to as hydrogen embrittlement. Hydrogen molecules can split into hydrogen atoms on material surfaces. Hydrogen atoms can penetrate through a surface into the interior of the material and trigger or intensify small-scale damage processes in the structure, which can cause large-scale damage and cracks in system components. This damage to materials reduces systems’ usability and shortens their service life; the fact that hydrogen gas can escape through these damaged areas also increases the risk of accidents and safety risks. When designing and building system components, it is therefore important to exclusively use materials through which only small quantities of hydrogen atoms can penetrate, or in which hydrogen atoms cause little damage. All systems in the hydrogen infrastructure face the challenge of preventing large-scale damage that occurs in system components due to small-scale interactions between hydrogen atoms and material structures. They are also affected by the problems resulting from such damage: Fractures caused by hydrogen must not occur in metal or ceramic materials used in electrolysis or fuel cells, nor in steel or plastic pipes for storage tanks and transportation lines or in high-temperature alloys for combustion engines and gas turbines. This chapter will focus on systems for the transportation, storage and distribution of hydrogen gas in pipes, containers and fittings made from metallic materials, particularly steel. Two key questions will be addressed regarding the materials. The first is in relation to the safety of steel components:  What fast-acting damage processes does hydrogen cause in steel structures? Regarding the service life of steel components, the question will then be asked:  What slow-acting damage processes does hydrogen cause in steel structures?

13.2 Accident prevention and service life: Hydrogen embrittlement In order to safely operate systems involved in the transportation, storage and distribution of hydrogen gas in the long term, all components that come into contact with hydrogen must be designed to be adequately robust, as well as to have a sufficiently long service life. When designing conventional systems, for example, sound expert knowledge on many steel materials, both in terms of robustness and service life, is

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Fig. 13.1 Macroscale examination of interactions during hydrogen embrittlement. HE: Hydrogen embrittlement. (Diagram according to Fig. 2 in [1])

available in the form of macroscale experimental material properties and empirical material models. However, studies looking at the effects that hydrogen has on materials in the design of components are significantly more limited. Due to the often low concentration and high mobility of atomic hydrogen in the microstructure of the material, it is very time-consuming to perform experiments to analyze and interpret how hydrogen systematically changes macroscale material properties, which are required for component design. There is still only a very limited amount of hydrogenspecific macroscale material properties available for many steel materials. The various aspects to be taken into account when evaluating the suitability of a material for a hydrogen application are outlined in Fig. 13.1. These aspects pose a challenge when designing components—in addition to the macroscale shape and size of the component, the microscale crystal structure and microstructure of the material, its behavior when put under mechanical stress and its behavior in contact with hydrogen have to be taken into account as a whole, rather than separately. A comprehensive knowledge base of material properties is required for this purpose. The current state of knowledge is outlined and discussed in literature such as the two review articles by Michler et al. [2, 3] for austenitic steels (with a face-centered cubic structure), for iron and nickel-based superalloys as well as for ferritic steels (with a body-centered cubic structure). It is also expected that our level of knowledge will be significantly expanded in the near future thanks to initiatives such as research projects on material digitalization as part of the BMBF-funded innova-

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tion platform MaterialDigital [4] and research projects on hydrogen embrittlement conducted as part of the lighthouse projects TransHyDE and H2-Mare [5]. These are also funded by the BMBF.

13.3 Materials and mechanisms: Steel materials Hydrogen interacts with a metallic material such as steel through a variety of mechanisms and on multiple different size and time frames. Fig. 13.2 outlines the most important microscale phenomena for hydrogen embrittlement in a material—these influence the macroscopic behavior of a component. When hydrogen gas comes into contact with a metal surface, weak binding (physisorption) and strong binding (chemisorption) of hydrogen molecules can occur on the surface. The molecules on the surface can then be split into their individual atoms (dissociation). The individual hydrogen atoms can penetrate into the metal interior (permeation) through certain facets or defects of the surface and occupy interstitial sites in the crystal structure, as well as migrate between them through the metal interior across long distances (diffusion).

Gas

Gaseous H2

V

V

Oxide layer Physisorption H2,ph Dissociative Chemisorption H2,ph -> Hch + Hch

Stresses Absorption Soluble H in the lattice Hch -> H+ab + e

3-axial stresses

Interaction with dislocations

Materials behaviour

Surface processes

Diffusion

Fig. 13.2 The prominent microscale phenomena for macroscale hydrogen embrittlement. (Diagram according to Fig. 1 in [6])

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Due to their atomic volume, which is small in comparison to metal atoms, but not negligible, the hydrogen atoms that penetrate inside the metal cause local mechanical strain and feel local mechanical stress caused by various crystal defects in the metal. Thus, the diffusing hydrogen atoms are drawn to atomic defects (e.g., empty spaces or foreign atoms in the crystal lattice), linear defects (e.g., edge or screw dislocation) and planar defects (e.g., grain or heterophase boundaries) and held there in a process known as hydrogen trapping. The hydrogen atoms that have reached the defects can, if they remain there for a sufficient period of time, change the cohesive, elastic or plastic properties of the metal in that area in such a way that microscale damage processes occur, which can result in macroscale material defects. The hydrogen atoms interact with the metal atoms in the crystal structure and in structural defects in a variety of ways. Investigating the key mechanisms for hydrogen embrittlement remains a demanding scientific challenge, despite extensive experimental and theoretical material research having been conducted for decades—see [7–10], for example. The current state of knowledge is discussed in literature such as the overview articles [11–16]. Some prominent mechanisms are outlined in Fig. 13.3:  In the hydrogen-induced phase transformation (HIPT) process, hydrogen causes a phase transformation in the metal. The metal’s structure and properties in the new and the old phase differ greatly.  In the hydrogen-enhanced decohesion (HEDE) process, hydrogen disrupts the cohesion of the metal atoms in a localized area, and microscopic pores or cracks form, which lead to brittle fracture on a macroscopic scale.  In the hydrogen-enhanced localized plasticity (HELP) process, the plasticity in the area around a moving crack tip in the metal is alternately increased by hydrogen atoms moving toward it and decreased by hydrogen atoms moving away from it. This results in fractured areas of the surface with a characteristic ripple pattern.  In the case of hydrogen-enhanced strain-induced vacancy formation (HESIV), vacancies filled with hydrogen are formed in the metal as a result of the dislocation movement during deformation; these then prevent further deformation [17, 18].  Likewise, the hydrogen-filled vacancies generated in large numbers during HESIV formation can coalesce and form pores in a process known as nanovoid coalescence (NVC), and thus reduce cohesion.

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Fig. 13.3 Diagrams of hydrogen embrittlement mechanisms. (Diagram according to Fig. 5 in [19]; see also [20–23])

Comparing the last two methods listed in the diagram illustrates the experimental problem of distinguishing NVC from a combination of HEDE and HELP using proven macroscale testing methods. For a thorough and ultimately clear explanation of hydrogen embrittlement mechanisms, new microscale testing methods are required. Following a short summarization of hydrogen embrittlement mechanisms, the special properties of hydrogen compared with other light foreign elements in steels and other metal materials—whether interstitial elements (C, N) or substitutional elements (B, O; Al, Si, P, S)—will be briefly outlined. Hydrogen atoms are very small and light compared with atoms of the other elements. As a result, they can move much more quickly through the crystal lattices of the metals. Atoms of other elements usually move so slowly in the metal that the reaction of the metal to mechanical stress is almost static. This is because during the course of deformation or

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fracturing processes, the distribution of the elements in the metal hardly changes. Hydrogen atoms, on the other hand, often move so quickly in the metal that the metal reacts very dynamically to stress, as the local distribution of hydrogen in the metal changes almost simultaneously with localized plasticity or decohesion processes. The degree to which the hydrogen distribution is synchronized with the damage processes depends on the metal structure. In addition, the diffusivity of hydrogen in metals with different crystal structures and crystal defects varies greatly. This is why it has been so difficult thus far to consistently assign microscale damage mechanisms to the macroscale damage processes observed in the case of hydrogen embrittlement in steel materials used in technical contexts.

13.4 Experimental material testing and theoretical material modeling In particular, the following experimental methods have been established to examine hydrogen embrittlement on the mechanics of materials and to test materials for their suitability for use in components that come into contact with hydrogen.  Bulk material samples are first charged with hydrogen, either in a high-pressure hydrogen gas chamber or in an electrochemical cell, and then tested using mechanical testing equipment.  Alternatively, they can be tested directly in the high-pressure atmosphere of the hydrogen gas using a testing device installed in a high-pressure autoclave. The major advantage of the second method is that the material test is carried out under well-defined hydrogen conditions. In contrast, in the more common first method, the test must be carried out quickly to prevent the hydrogen concentration in the material sample from changing between when it is charged in the highpressure chamber and the deformation in the testing equipment. Both test methods that use bulk material samples and hydrogen gas under high pressure require complex laboratory equipment to carry out the experiments in a scientifically proper manner and to ensure that they are safe from a technical perspective. As a result, material tests for hydrogen embrittlement using these methods are expensive and can rarely be applied to an extensive series of samples. In a third test method, hollow material samples are deformed in a standard testing device. A channel is drilled into the sample along its longitudinal axis, through which the hydrogen gas comes into contact with the material under defined internal

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Fig. 13.4 Test benches at the Fraunhofer IWM hydrogen laboratory for metal materials that come into contact with hydrogen gas. Left: Standard material testing in a high-pressure hydrogen autoclave; right: testing using hollow material samples under internal hydrogen pressure. (Photographs and sketch: Fraunhofer IWM)

pressure. This method requires significantly less effort in terms of laboratory facilities than the methods described above. The experiments are less expensive and therefore more suitable for large series of samples. Fig. 13.4 shows a photograph of a hydrogen high-pressure autoclave test stand on the left and a photograph of a hollow sample test stand (with a diagram of a hollow sample) at the Fraunhofer IWM hydrogen laboratory on the right. The earlier and the more precisely it can be determined when and where material damage may occur in a component, the better the component can be designed to have a high level of protection against accidents and a long service life. The material properties required to do this can only be obtained to a limited extent through experiments using the macroscale testing methods mentioned above. Micro-mechanical testing methods using microsamples of materials [24–26] could potentially be very useful in the future for testing materials that come into contact with hydrogen gas. Microsamples can be used to precisely identify critical points in a microstructure of the material where hydrogen embrittlement may occur. In this way, detailed data on the characteristics of the formation and spread of damage in the material can be obtained. The micro-mechanical material testing

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methods extend the range of application of material testing from the macroscale of the component to the microscale of the microstructure. They are clearly applicable and advantageous for use with materials that come into contact with hydrogen. For this reason, the Fraunhofer IWM hydrogen laboratory is currently developing a micro-mechanical hydrogen gas pressure chamber test bench for material microsamples. This means that in the near future, it will be possible to carry out tests on series of material microsamples to examine damage processes caused by hydrogen embrittlement in a mechanically thorough and cost-effective manner. Further progress toward experimental multiscale material testing may lie in non-destructive methods of material testing that use novel quantum physical sensors for electromagnetic fields. Very small field changes on the surface of the sample, which are caused by small structural changes due to damage processes caused by hydrogen inside the sample, can in principle be detected and located at an early stage using quantum magnetic sensors with extremely high field sensitivity (e.g., alkali metal gas cell sensors) or with extremely high spatial resolution (e.g., diamond-tip NV-center sensors). As part of the Fraunhofer lighthouse project QMAG—Quantum Magnetometry, researchers are working to develop quantum magnetic sensors that can be used for material testing in a practical context [27]. To complement experimental material testing, theoretical material modeling also makes an increasingly important contribution to the research of hydrogen embrittlement of materials and to the development of criteria for evaluating and designing components with regard to accident prevention and service life. Due to the multiscale interactions of hydrogen atoms with material structures outlined above, a variety of computer simulation methods for the relevant size and time scales (see, for example, the overview articles [28, 29]) are being developed for material modeling and linked together. Fig. 13.5 outlines the four chain links in multiscale material modeling (MMM) for the diffusion of hydrogen in metals, which were developed as part of the EU project MultiHy and used for problems of hydrogen embrittlement [30, 31]. Some prominent computer simulation methods of material mechanics to model hydrogen embrittlement are summarized below:  On the macroscale, continuum models can be used to simulate mechanical material behavior with spatially and temporally variable concentration and diffusion of hydrogen in the material structure. The mathematical field equations of the models can be solved numerically using standard finite element methods. Normally, macroscale material properties are used to establish the parameters for the models. These are usually determined directly using material testing experiments, but sometimes indirectly though microscale structure simulations

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Fig. 13.5 Multiscale modeling of the diffusion of hydrogen in materials (diagram: Fraunhofer IWM, from Project MultiHy [30, 31])

using suitable statistical averaging (coarse graining). The physical linking of the relevant mechanical fields (strains and stresses in the material structure) to the thermodynamic fields (temperature and pressure of the hydrogen gas, concentration and partial pressure of the hydrogen in the material, etc.) is essential for the further development of the continuum methods for the simulation of hydrogen embrittlement. Developing suitable methods to achieve this in the context of material mechanics is an important but challenging task. These methods should take into account as many mechanisms as possible in an empirically reliable manner and be numerically calculated in an efficient way.  Phenomenological continuum models (e.g., Fourier equations for heat transport or Fick’s equations for atomic transport) are combined with atomistic/discrete transport theories (e.g., master equations with kinetic crack growth rate models for Monte Carlo simulations or Newton equations with interatomic potentials for molecular dynamics simulations) when it comes to the concentration and diffusion of hydrogen atoms in material structures on the mesoscale. This enables effective descriptions to be developed for individual interactions of hydrogen atoms with atomic defects, lattice dislocation or boundaries in the microstructure of the material; these small-scale material damage processes lead to hydrogen embrittlement on a large scale.  To determine the parameters of the crack growth rate models or the interatomic potentials, material properties are used that can be calculated from first principles on the microscale using quantum mechanical computer simulation methods (e.g., methods of density functional theory) for atomistic models of the individual crystal and defect structures in the microstructure of the materials (see, for example, [32–36]).

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Multiscale chains, as illustrated in Fig. 13.5, have to date only been consistently applied to particular use cases (Project MultiHy [30]). It remains a great challenge to describe them for general use cases where hydrogen embrittlement occurs in such a way that they can be understood not only by physicists specializing in theory of materials, but also by practical development engineers who don’t have specialist expertise. This will finally enable engineers to consider hydrogen embrittlement when designing components and take steps to prevent it occurring. Theoretical material modeling, component evaluation and software tool development are required here.

13.5 Discussion: Hydrogen readiness The current state of the art in science and technology regarding the macroscale hydrogen embrittlement of materials in components and the associated microscale interaction of hydrogen atoms with microstructures of materials can be broadly summarized as follows: Experimental mechanical material testing provides material properties, which are good for specific materials, but often still insufficient for evaluating and designing components that need to be safe and have a long service life when they come into contact with hydrogen. Macroscale computer simulations provide good, but often still insufficiently realistic, descriptions of the specific behavior of materials when they come into contact with hydrogen. Empirical interpretation of the experimental findings for certain materials requires sound technical knowledge and a great deal of experience. Transferring the findings for one tested material to other materials and making general statements regarding the interpretation is only possible to a limited extent. Interpolative evaluations of materials with similar microstructures with regard to hydrogen embrittlement are possible, whereas extrapolative predictions for different materials are not very reliable. Thus, put simply, a key task must be addressed in the future for the experimental testing methods and theoretical simulation methods of material mechanics: The mechanistic description of material behavior must continue to be specific and interpolative, but should also enable generic and extrapolative predictions regarding other materials. For this purpose, new possibilities for the methodological further development of material testing and material modeling can be created by combining mechanistic models of mechanics, physics and chemistry with stochastic material data models from the field of material informatics (big data, machine learning, artificial intelligence) as well as coupling scales (coarse graining) of mechanistic or statistical material models. This could enable more reliable evaluation and design of safe and long-lasting components within the hydrogen infrastructure.

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In the future, when designing components for long-lasting systems, care must be taken to consider “slow-acting” damage processes that occur in structures due to static or cyclical subcritical mechanical stresses—these processes cause quasistatic hydrogen embrittlement that results in material fatigue and aging in components. When designing components for accident-proof systems, however, it is important to consider “fast-acting” damage processes in structures due to shortterm and local supercritical mechanical stresses that can lead to plastic deformation or the formation of cracks and consequently to the destruction of the components due to dynamic hydrogen embrittlement. In order to ultimately achieve these objectives, materials science must develop computer simulation tools that are equipped with material data and material models and are informed by multiscale models. These can then be used to design components that can be operated by development engineers without any special expert knowledge. To this end, the aim is to compile comprehensive expert knowledge in mechanical material testing and material modeling in the future in the form of digitalized data and models, and thus to make them easily available and automatically applicable for problems relating to hydrogen embrittlement in technical systems within the hydrogen infrastructure. Therefore, hydrogen readiness will ultimately mean that development engineers can reliably evaluate the suitability of materials for safe and long-lasting components in systems within the hydrogen infrastructure.

References 1. Barnoush A., Vehoff H. (2010): Recent developments in the study of hydrogen embrittlement: Hydrogen effect on dislocation nucleation. Acta Materialia 58 (16): 5274–5285 2. Michler T., Wackermann K., Schweizer F. (2021): Review and Assessment of the Effect of Hydrogen Gas Pressure on the Embrittlement of Steels in Gaseous Hydrogen Environment. Metals 11 (4): 637 3. Michler T., Schweizer F., Wackermann K. (2021): Review on the Influence of Temperature upon Hydrogen Effects in Structural Alloys. Metals 11 (3): 423 4. MaterialD1g1tal: Die Plattform für die Digitalisierung der Materialien (MaterialD1g1tal: The platform for material digitalization). https://www.materialdigital.de/, last viewed on December 11, 2021 5. German Federal Ministry of Education and Research: Welcome to the Hydrogen Flagship Projects! https://www.wasserstoff-leitprojekte.de/, last viewed on December 11, 2021 6. Michler T., Naumann J. (2009): Coatings to reduce hydrogen environment embrittlement of 304 austenitic stainless steel. Surface and Coatings Technology 203 (13): 1819–1828 7. Oriani R.A. (1972): A mechanistic theory of hydrogen embrittlement of steels. Berichte der Bunsengesellschaft für physikalische Chemie (Reports of the German Bunsen Society for Physical Chemistry) 76 (8): 848–857

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8. Oriani R.A. (1978): Hydrogen embrittlement of steels. Annual review of materials science 8: 327–357 9. Oriani R.A. (1987): Whitney award lecture 1987: Hydrogen—The versatile embrittler. Corrosion 43 (7): 390–397 10. Robertson I.M., Sofronis P., Nagao A. et al. (2015): Hydrogen embrittlement understood. Metallurgical and Materials Transactions B 46: 1085–1103 11. Barnoush. A., Vehoff H. (2010): Recent developments in the study of hydrogen embrittlement: Hydrogen effect on dislocation nucleation. Acta Materialia 58 (16): 5274–5285 12. Lynch, S. (2012): Hydrogen embrittlement phenomena and mechanisms. Corrosion Reviews 30: 105–123 13. Dadfarnia M., Nagao A., Wang S. et al. (2015): Recent advances on hydrogen embrittlement of structural materials. International Journal of Fracture 196: 223–243 14. Bhadeshia H.K.D.H. (2016): Prevention of hydrogen embrittlement in steels. ISIJ International 56: 24–36 15. Barrera O., Bombac D., Chen Y. et al. (2018): Understanding and mitigating hydrogen embrittlement of steels: a review of experimental, modelling and design progress from atomistic to continuum. Journal of Materials Science 53 (9): 6251–6290 16. Li X., Ma X., Zhang J. et al. (2020): Review of hydrogen embrittlement in metals: Hydrogen diffusion, hydrogen characterization, hydrogen embrittlement mechanism and prevention. Acta Metallurgica Sinica (English Letters) 33 (6): 759–773 17. Li S.Z., Li Y.G., Lo Y.C. et al. (2015): The interaction of dislocations and hydrogenvacancy complexes and its importance for deformation-induced proto nano-voids formation in alpha-Fe. International Journal of Plasticity 74: 175–191 18. Xie D., Li S., Li M., Wang Z., Gumbsch P. et al. (2016): Hydrogenated vacancies lock dislocations in aluminium. Nature Communications 7: 13341 1–7 19. Li X., Ma X., Zhang J. et al. (2020): Review of hydrogen embrittlement in metals: Hydrogen diffusion, hydrogen characterization, hydrogen embrittlement mechanism and prevention. Acta Metallurgica Sinica (English Letters) 33 (6): 759–773 20. Gerberich W.W., Oriani R.A., Lji M.-J. et al. (1991): The necessity of both plasticity and brittleness in the fracture thresholds of iron. Philosophical Magazine A 63: 363–376 21. Birnbaum H.K., Sofronis P. (1994): Hydrogen-enhanced localized plasticity—a mechanism for hydrogen-related fracture. Materials Science and Engineering: A 176: 191–202 22. Neeraj T., Srinivasan R., Li J. (2012): Hydrogen embrittlement of ferritic steels: observations on deformation microstructure, nanoscale dimples and failure by nanovoiding. Acta Materialia 60: 5160–5171 23. Martin M.L., Robertson I. M., Sofronis P. (2011): Interpreting hydrogen-induced fracture surfaces in terms of deformation processes: a new approach. Acta Materialia 59: 3680–3687 24. Gianola D.S., Eberl C. (2009): Micro- and nanoscale tensile testing of materials. JOM 61: 24–35 25. Piotter V., Eberl C., Kraft O. (2016): Miniaturisierung? Ja, bitte! (Miniaturization? Yes please!) Forschung 41: 24–27 26. Thomas A., Durmaz A.R., Straub T., Eberl C. (2020): Automated Quantitative Analyses of Fatigue-Induced Surface Damage by Deep Learning. Materials 13 (15): 3298 27. Fraunhofer-Gesellschaft: QMAG—Quantum Magnetometry. https://www.qmag. fraunhofer.de/en.html, last viewed on December 11, 2021

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28. Díaz A., Alegre J.M., Cuesta I.I. (2016): A review on diffusion modelling in hydrogen related failures of metals. Engineering Failure Analysis 66: 577–595 29. Jemblie L., Olden V., Akselsen O.M. (2017): A coupled diffusion and cohesive zone modelling approach for numerically assessing hydrogen embrittlement of steel structures. International Journal of Hydrogen Energy 42 (16): 11980–11995 30. European Commission: MultiHy—Multiscale Modelling of Hydrogen Embrittlement (2011–2015). https://cordis.europa.eu/project/id/263335/reporting, last viewed on December 11, 2021 31. Winzer N., Mrovec M. (2014): Multiscale Approaches to Hydrogen-Assisted Degradation of Metals. JOM 66: 1366–1367 32. Hickel T., Nazarov R., McEniry E.J. et al. (2014): Ab initio based understanding of the segregation and diffusion mechanisms of hydrogen in steels. JOM 66: 1399–1405 33. Di Stefano D., Mrovec M., Elsässer C. (2015): First-principles investigation of quantum mechanical effects on the diffusion of hydrogen in iron and nickel. Physical Review B 92: 224301 34. Di Stefano D., Nazarov R., Hickel T. et al. (2016): First-principles investigation of hydrogen interaction with TiC precipitates in ’-Fe. Physical Review B 93: 184108 35. Di Stefano D., Mrovec M., Elsässer C. (2015): First-principles investigation of hydrogen trapping and diffusion at grain boundaries in nickel. Acta Materialia 98: 306–312 36. Bombac D., Katzarov I.H., Pashov D.L., Paxton A.T. (2017): Theoretical evaluation of the role of crystal defects on local equilibrium and effective diffusivity of hydrogen in iron. Materials Science and Technology 33 (13): 1505–1514

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14

Carolin Pannek  Armin Lambrecht  Jürgen Wöllenstein  Karsten Buse Fraunhofer Institute for Physical Measurement Techniques IPM Armin Keßler Fraunhofer Institute for Chemical Technology ICT Ralf Tschuncky  Patrick Jäckel  Steven Quirin  Sargon Youssef  Hans-Georg Herrmann Fraunhofer Institute for Nondestructive Testing IZFP Steven Oeckl Fraunhofer Institute for Integrated Circuits IIS Abstract

The most important prerequisite for a successful hydrogen economy is that its technology that does not pose any danger. Sensors are key to ensuring safety here: Existing sensors for non-destructive testing can be used to monitor structural integrity, and established sensor concepts can be employed to detect hydrogen leaks. However, these available technical solutions are often only of limited use or are very complex. The research and development work into sensor technology presented here serves to demonstrate how current limitations can be either reduced or eliminated entirely in the future.

© Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_14

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14.1 Introduction With the publication of the National Hydrogen Strategy in June 2020, the German federal government laid out its plan for establishing green hydrogen (H2 ) as the energy carrier of the future, thus making an essential contribution to the protection of the climate [1]. The successful implementation of this new technology depends on it being widely supported in society; this support in turn relies on the assurance that the hydrogen economy does not pose any danger. This must be ensured in all aspects of the hydrogen economy, including production, transportation, storage and usage. As hydrogen advances ever closer to the end user, with its infrastructures and logistics becoming available all over the country, the question of its safety is by no means trivial. The use of hydrogen as an energy carrier places high demands on safety technology, as H2 can ignite at 4 vol% in the air and becomes explosive at 18 vol%. The consequences of this property of hydrogen became apparent when, on June 12, 2019, there was an accident at a filling station outside Oslo belonging to the hydrogen company Nel. The incident led to the collapse of Norway’s entire H2 supply and was found to have been caused by errors in the assembly of a high-pressure tank [2]. Hence a systemic safety analysis is an indispensable step in planning, constructing and operating hydrogen facilities. It is normally carried out in the form of a hazard and risk analysis (Fig. 14.1; [3]) using established safety technology tools such as HAZOP (hazard and operability study), FMEA (failure mode and effects analysis) and FTA (fault tree analysis) [4]. Possible sources of danger are first identified, and a risk determination is then carried out on the basis of typical scenarios (for example, refueling processes at an H2 filling station). Changes may be made to the process or system depending on the result of the risk assessment, for example by providing additional protective devices.

Sensors As these risk analysis processes show, sensor technology is a vital element of all areas of the hydrogen economy. Sensors can quickly and reliably detect a source of danger, allowing active protection measures to be immediately implemented. This significantly reduces the risk of damage, as the sensors serve to avert danger. To accomplish this, the sensors must be capable of covering as many scenarios as possible. Sensors are needed to inspect all system and machine parts, to ensure that they function safely for their entire service lives. Furthermore, sensors in all systems

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Fig. 14.1 Safety analysis procedure: Sensor technology is an important element of hazard prevention

and devices must prevent both danger to people and damage to property in all states of operation, including breakdown scenarios—regardless of how improbable they may be. This results in the following general requirements for sensors and for the classification of safety sensors in hydrogen technology:  Materials, components and systems used in hydrogen technology must be inspected for safety both before and during installation, as well as during operation. A suitable non-destructive sensor system is required for this.  Guidelines and technical protective devices are necessary for the safe use of hydrogen and the safe operation of all hydrogen plants and systems. Furthermore, the safety of people and objects in the vicinity of hydrogen-carrying systems and devices must also be guaranteed. This requires reliable H 2 safety sensors for a very wide range of applications.  Leak tests must be carried out during the installation process and during maintenance work on hydrogen-carrying systems and machines, as well as during regular inspections. All leaks must be detected, located and repaired. This process requires H 2 leak sensors.

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 If hydrogen is chemically bound to a carrier molecule for a temporary period of time, for example so that it can be transported safely and efficiently, then additional hydrogen carrier sensors are required. For example, this is the case when ammonia acts as a hydrogen carrier.  Process-related and accidental contaminations can occur during hydrogen production, distribution and storage. In addition, associated gases and odorants may be added for certain purposes. Contaminations and admixtures, even in trace amounts, can be crucial factors when it comes to using hydrogen gas safely. For this reason, many hydrogen gas applications require the purity of the gas to be closely monitored. Suitable hydrogen purity sensors are required for this.

14.2 Challenges Successfully constructing a large-scale infrastructure for hydrogen production, storage and distribution with the necessary level of public support will require the highest possible degree of safety and availability—this must be guaranteed from the outset at every location, in all operating conditions and over long periods of time. Not only that, but this must be achieved as efficiently and cost-effectively as possible in order to conserve economic and ecological resources. Hydrogen must be produced, transported and stored in large quantities, with the storage taking place in mobile (pressure) tanks, pipes or cavern storage facilities. This means that hydrogen must be compressed or cooled or, in the case of cryogenic hydrogen storage, both at once. Given that hydrogen is highly diffusive and it can change material properties, safety-related issues must be carefully considered and applied in all infrastructural components. Factors relating to materials were covered in Chap. 13. For the industrial use of hydrogen, it is necessary to set up a hydrogen pipeline network that links large consumers (the chemical industry, refineries, the steel industry, etc.) with production facilities (wind/PV electrolysis) or ports for imported hydrogen. One possibility for quickly implementing an area-wide hydrogen distribution system is to use the existing natural gas infrastructure. This can be done by adding up to a double-digit percentage of H2 to natural gas. Furthermore, individual elements of the supply chain can be converted for use with high concentrations of hydrogen. Long-established systems such as natural gas pipelines and storage systems must be inspected in detail and, if necessary, converted, expanded, equipped with suitable H 2 safety sensors and approved for use with hydrogen. At the same time, safety-related devices and regulations that have been approved for

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a natural gas infrastructure must be extended to encompass the specific properties and hazard potential of hydrogen. This applies to everything from planning, qualification of components, construction measures and the installation, initial operation, regular operation, inspections and maintenance of the distribution infrastructure. Leak tests are an essential safety measure when it comes to installing, converting and repairing gas systems, as well as when conducting maintenance and regular inspections. Storage facilities, fittings, measuring devices, etc. must be examined and approved before installation. The DVGW has a comprehensive system of rules and standards for leak testing and locating possible leaks of natural gases, as well as for suitable test devices for this purpose. Thanks to the use of these guidelines and devices, very few gas-related accidents have been recorded in the German natural gas network [5, 6], which totals 511,000 km in length and has a storage capacity of 130 TWh—the equivalent of around 14 days’ worth of primary energy consumption. 2017 saw about six accidents requiring immediate reporting per 100,000 km of pipeline. The majority of these accidents could be attributed to external factors affecting the pipeline, such as damage caused by excavators [7]. Approved safety protocols for the natural gas network can serve as a safety template for a future hydrogen network. One example is DVGW guideline G 465-4: “Gas leak detection and gas concentration measuring devices for leakage survey on gas supply systems,” which defines properties that also apply to hydrogen, but require further specification [8]. However, there are significant differences and challenges unique to a hydrogen network. For example, odorization plays an important role in ensuring the safety of a natural gas network. The unpleasant smell of gas means a gas leak can immediately be noticed by everyone in the vicinity, including children. Odorization therefore significantly aids the quick recognition of gas leaks and helps avoid accidents. Unfortunately, there is no effective means of odorization for hydrogen. One problematic factor here is that hydrogen can diffuse through the smallest of leaks, and that unlike all other gases, it can also diffuse through a number of materials. This means conventional odorants, which have large molecules, are unsuitable for hydrogen. Small hydrogen leaks therefore cannot be detected by smell. This makes having a sensitive H 2 safety sensor all the more important.

Sensors for locating leaks When it comes to natural gas, non-contact methods have been developed for detecting and locating possible leaks from a distance. Modified thermal imaging cameras [9] and sensitive laser detectors [10] can help locate leaks from a distance of up

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to 30 m. There is even a helicopter system that is used to monitor gas pipelines, allowing gas leaks to be detected from a height of more than 100 m [11]. This method of leakage screening can also be carried out automatically or from a vehicle, which allows effective, targeted inspections to take place on site. The physical principle that these remote detection methods are based on is the infrared absorption of methane. Unfortunately, pure H2 is not infrared active. This means that a comprehensive, branched hydrogen network requires its own sensitive, efficient remote detection technology. When carrying out new installations, pipe sections, sleeves, fittings, etc. are subjected to high gas pressure and tested for pressure drop. Critical system parts are investigated using sensitive leak detectors; for example, a flame ionization detector (FID) is used for natural gas. For hydrogen, palladium field-effect transistor sensors or a compact mass spectrometer that selectively responds to H2 may be used. This technology is used for leak testing with helium and is very sensitive. However, manually checking complex systems in this manner is highly labor-intensive and time-consuming; for this reason, it is only carried out at fixed intervals, e.g. annually, in existing systems. Using imaging technology to detect and locate leaks enables inspection work to be carried out much more effectively. As with gas cameras for methane, this requires an appropriate non-contact H2 leak sensor system.

Safety sensors The continuous monitoring of gas installations during operation requires the use of permanently installed H2 safety sensors, which can reliably detect a concentration of over 1 percent H2 in the ambient air and can verify an increase in H2 concentration within a few seconds, even at values below 0.4 percent. These sensors must offer high levels of reliability, robustness and long-term stability. They must also be maintenance-free and inexpensive, since reliably detecting a leak normally requires a network of multiple sensors. The sensors must be placed in an optimal position so that they can, for example, remain responsive in a building with changing air currents. To avoid false alarms, the sensors must exhibit almost no cross-sensitivity in the presence of changing environmental conditions, dust, humidity or other gases (e.g., vapors from cleaning agents). The ISO 26142:2010 standard sets out some important specifications for hydrogen sensors, regardless of the technology used. The sensors must also monitor their function independently and be able to detect the contamination or degradation of key components. In addition, the sensor elements in an H2 detector require redundancies that are independent of any technology. This means two sensor elements that each

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Table 14.1 Comparison of hydrogen, methane (gases at 0 °C and 1013 mbar) and liquid fuels (at 25 °C) [15–17] Property

Hydrogen

State of aggregation Density (air: 1.3 kg/m3 ) Calorific value per unit mass [MJ/kg] Calorific value per unit volume [kWh] Ignition temperature [°C] Minimum ignition energy [mJ] Diffusion coefficient in air [m2 /s] @20 °C Speed of sound [m/s] (air: 343 m/s) Thermal conductivity [mW/m K] (air: 26.2) Lower explosive limit, LEL [vol%] Upper explosive limit, UEL [vol%]

Gaseous

(a)

Methane

141.8

Liquid Gaseous (LH2) 0.071 kg/l 0.72 kg/m3 @253 °C 55.5

3.54/m3

2.79/l

0.09 kg/m3

11.1/m3

Gasoline Liquid Liquid (LNG) 0.42 kg/l  0.75 kg/l @162 °C  43.5 6.5/l

Diesel Liquid  0.85 kg/l  45.4

 9.0/l

 10.4/l

585

595

200–410

220

0.016

0.2

0.24(a)

–

6.9  105

2.2  105

0.67  105 (b) –

1280

466

186

34.1

4

4.4

1.4

0.6

77

16.5

7.6

7.5

Heptane-air mixture, (b) n-Heptane vapor

physically operate in a different way must be used in one system to guarantee that even if one element fails, the system continues to function. These are requirements for “functional safety,” which are regulated in the standards DIN EN 61508, DIN EN 61511 and ISO 26262 (for road vehicles, see below). As shown in Table 14.1, in the event of a leak, H2 dissipates much faster than methane or gasoline vapors. On the one hand, this is an advantage, since it reduces the risk of creating flammable mixtures. On the other hand, the high diffusion coefficient also means ignitable concentrations can build up more quickly in an enclosed space. In addition, the concentration range of explosive mixtures for H2

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is greater than for CH4 or gasoline vapors, and it requires less oxygen for combustion than other energy carriers. Hydrogen’s very low ignition energy is another major source of danger. Even a small spark, for example caused by electrostatic discharge, can trigger ignition. Given the wide variety of scenarios, it is not possible to decide from values alone (Table 14.1) whether hydrogen or natural gas is the safer energy source. A crucial element to the safety of both systems is how they are handled by professionals [12].

Sensors for mobile applications Aside from the material and industrial use of hydrogen, e.g., in the production of ammonia for fertilizers, in refineries or in the steel industry, the most important application of hydrogen is converting electricity in fuel cells. The vast majority of fuel cell systems are used in the transportation sector, in stark contrast to natural gas, which only plays a minor role in transportation. While there were 14,470 filling stations for gasoline and diesel in Germany in 2020 [13], there were only 832 filling stations for natural gas (compressed natural gas, CNG) [14]. There were already 89 hydrogen filling stations at the end of 2020, with 1000 more planned by 2025. Freight transportation and public transportation, in particular, make up the largest markets for fuel cells, and have high annual growth rates [32]. For freight transportation alone, the overall electrical output of the fuel cells sold worldwide in 2019 was 0.9 GW, representing a market share of 80% [33]. In contrast, despite numerous pilot projects and the commercial availability of fuel cell vehicles, private transportation remains a niche market, as it has not been proven to be costeffective. It is essential for the transportation sector to establish a nationwide filling station infrastructure, which should preferably be paired with a stationary supply network. Hydrogen is significantly different to other energy carriers in this regard (Table 14.1). For one, Table 14.1 shows that the energy content per unit volume of gaseous fuels at atmospheric pressure is about 1000 times lower than that of liquid fuels. Furthermore, the energy content per kg of H2 is about three times higher than that of natural gas, but three times lower per normal volume. This means that hydrogen should be tanked and stored at about three times the pressure of natural gas in order for a vehicle to achieve a similar range with the same tank size. The maximum refueling pressure for CNG vehicles is limited to 200 bar at 15 °C. Since pressure increases during refueling, and the gas heats up as a result, the refueling process is cut off at an upper limit of 250 bar. The tank volume (which is approximately 100 l for CNG passenger cars) limits the range of a ve-

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hicle. A CNG vehicle therefore has roughly half the range of a diesel vehicle. Liquefied natural gas (LNG) and cryogenic, liquid hydrogen (LH2) require smaller tank volumes, but are much more complex to handle in a technical sense. They are not used in passenger cars and are rarely used in trucks. For this reason, LNG and LH2 will not be specifically addressed below. In comparing hydrogen to natural gas, it is clear that very high refueling pressures are required if introducing hydrogen to the transportation sector is to become economically viable. Hydrogen heats up considerably during refueling and must therefore usually be precooled to 40 °C. Fuel cell cars are normally refueled at 700 bar, which hydrogen filling stations in Germany are equipped for. However, only a few of them are also suitable for commercial vehicles. These require larger amounts of hydrogen, with a majority only designed for a refueling pressure of 350 bar. It is still unclear how the increased demand for filling stations that are suitable for fuel cell vehicles can be met, and how the desired short filling times of around 10 minutes can be achieved. Another important aspect to consider is how the filling stations are supplied with hydrogen. For example, it is hard to imagine a remote filling station on a highway having a connection to a stationary hydrogen network in the medium term. The obvious solution in this case would be for the filling station to receive regular deliveries of liquid H2 . However, this would increase the need for safety devices and safety sensors for handling LH2 . Appropriate safety measures are also required when using alternative hydrogen carriers such as ammonia. Although ammonia is not as flammable as hydrogen, it is toxic, so appropriate ammonia sensors must be provided. Significant safety challenges in this context include the rapidly increasing number of filling stations, high refueling pressures, the short refueling times required, human errors and operating errors, wear and tear of components and, last but not least, the harsh environmental conditions at filling stations. For this reason, many safety studies have specifically investigated the subject of hydrogen filling stations [18–20]. In addition to using safety sensors in a stationary H2 distribution structure, their use in filling stations must therefore also be considered in particular. Special H2 safety sensors must be used in these cases. Since there are generally many people at filling stations, most of whom are not involved in individual refueling processes, special caution is required. This was made apparent at the Norwegian filling station accident mentioned above, which injured two bystanders. Another challenge lies in the safety of H2 -powered fuel cell vehicles. Protecting people is paramount here, too. Traffic accidents, difficult weather conditions, wear and tear, operating errors, etc. can all result in dangerous situations, which means

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special safety measures are required for hydrogen-powered vehicles. This includes, first and foremost, reliable H2 safety sensors. In this regard, complying with the ISO 26262 standard and the “safety integrity level” standard (SIL standard), both of which are required for approval, proves to be a major hurdle for many applications.

Purity sensors Fuel cells are particularly sensitive to impurities in hydrogen gas—this applies in particular to PEM (proton exchange membrane) technology, which is by far the most commonly used technology. The quality and purity of the hydrogen must be adequately guaranteed, especially when it comes to refueling fuel cell vehicles. The ISO 14687-2:2012 and EN 17124:2018 standards and their 2019 revisions outline specifications for hydrogen as a fuel for PEM fuel cells. For example, they permit maximum concentrations of only 5 ppm H2 O, 5 ppm O2 , 0.2 ppm CO, 0.1 ppm NH3 and only 4 ppb in total for all sulfur compounds. The analytic procedure for measuring the purity of hydrogen is complex and is only available in a few laboratories in Europe [21]. However, there is no compact, inexpensive purity sensor system available that can be used at filling stations or in vehicles. Contamination of H2 can lead to breakdowns and permanent damage to the fuel cell. This does not in itself lead directly to a hydrogen leak. Since the focus of this chapter is on explosion protection, H2 purity sensors will not be discussed further.

14.3

H2 sensor technologies and applications

The various measuring principles for detecting hydrogen are presented below. The methods are summarized and divided into the areas of established sensors, MEMSbased sensors and optical sensors.

14.3.1 Established sensors There are a variety of sensors on the market for detecting hydrogen and hydrogen leaks. Thermal conductivity detectors (TCD), catalytic gas sensors (pellistors) and metal oxide gas sensors (MOx) make up the largest share of the market. Ultrasonic sensors, electrochemical gas sensors, gas-sensitive field-effect transistors (FET) and spectroscopy systems can also be used. Due to the more complex technology associated with these, and the higher resulting costs, they are more likely to be

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found in niche markets. In the field of R&D, highly specialized laboratory devices such as high-speed mass spectrometers and non-contact optical or acoustic imaging methods are also used.

Thermal conductivity sensors Every material has its own specific, typical thermal conductivity. This is a physical quantity; for gases, it can be derived using the kinetic theory of gases. It is independent from pressure at a given temperature [22]. From the kinetic theory of gases, it can also be deduced that light atoms and molecules can conduct heat better than heavier ones. For that reason, the thermal conductivity of hydrogen differs significantly from other gases: It is higher by a factor of about seven. Only helium can cause a cross-sensitivity, since its thermal conductivity is 16 percent below the H2 value. However, helium only occurs naturally in low concentrations, and is only selectively used for technical purposes, meaning that it poses practically no restrictions. Given that hydrogen differs from other gases in terms of thermal conductivity, determining the thermal conductivity is the ideal basis for a selective hydrogen sensor. The measuring principle of thermal conductivity sensors and thermal conductivity detectors (TCD) consists of heating a heating element (filament) made of platinum, tungsten, nickel or their alloys to a defined temperature. During this process, there is a continuous flow of heat from the heating element to the surrounding environment. This flow depends on the thermal conductivity, and thus on the composition of the surrounding gases. Changes in the composition of the gas being measured cause the temperature of the heating element to change, and the electrical resistance of the filament also changes as a result. Measurement can take place either at a constant temperature or at a constant heating current. This measuring principle can be used to determine even low concentrations of H2 in ambient air. In terms of the physical method, thermal conductivity measurement is a suitable technique for analyzing the exhaust gas composition of a fuel cell; however, cross-sensitivity effects such as humidity and possible disrupting factors such as condensation must be taken into account in the analysis. Nevertheless, TCDs are currently state of the art. The diagram in Fig. 14.2 shows the structure of a thermal conductivity sensor. An additional reference cell can be integrated both to increase the level of accuracy and to lessen the influence of ambient conditions. TCDs can typically be produced inexpensively and in miniature. They are stable in the long term, highly selective and consume only a moderate amount of energy. Thermal conductivity sensors are often used as detectors in gas chromatographs.

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Fig. 14.2 Diagram of a thermal conductivity sensor. The gas inside the cell is heated by a heating element. If the composition of the gas in the measuring cell changes, so too does the dissipation of heat, leading to a change in temperature. The change in temperature is detected by a temperature sensor

Pellistors Pellistors (a portmanteau of “pellet” and “resistor”) are among the earliest solidstate gas sensors. They originally date back to the 1960s, when they were used to detect methane in mines. The original method was to use a heated wire that produced a reaction of the gas at very high temperatures and the wire itself changed temperature due to the heat produced by the reaction. The structure of this first sensor was quickly improved upon to increase its stability (Fig. 14.3). At its core is a coiled platinum wire (a), which is embedded in a ceramic pellet to protect it from oxidation and mechanical stress (b). The outside of the pellet is coated with a thin, catalytically active layer (c). Combustible gases and oxygen react with this catalytic coating (d) from temperatures starting at 500 °C and can be detected as a change in the sensor temperature. Since the heating coil is also used as a temperature sensor, the gas concentration can either be recorded as a temperature change at a constant heating current or as a change in the heating power at a constant sensor temperature, much like a TCD. The classic setup consists of two separate heating coils sintered into ceramic. The “active” pellistor is coated with a catalyst. The uncoated, “inert” pellistor serves as a reference sensor. If both pellistors are operated in a bridge circuit, this serves to compensate for disturbance variables such as air flow, ambient temperature and the thermal conductivity of the air. The advantage of pellistors is that, in principle, their simple but robust design makes them ideal for detecting all kinds of combustible gases. Not only that, but pellistors are established on the market. Their disadvantages are that they have a relatively high heating power of about 1 W and their measurement principle is

14.3 H2 sensor technologies and applications

369 a

b

c

d

Fig. 14.3 Diagram of the structure of a catalytic gas sensor (pellistor). a) Heating coil, b) Pellet made from inert oxide material (ceramic), c) Thin catalytically active layer and d) Reaction of the layer with H2 molecules in the surrounding environment

non-selective. Moreover, they operate at temperatures above 500 °C, making them a potential source of ignition for combustible mixtures. Additionally, there must be a minimum oxygen level of about 10 percent in the environment for the gases to be detected. High water content in the ambient atmosphere will also affect the measurement. Due to the sensors’ three-dimensional, multi-part structures, production costs are comparatively high. Both this and the desire for low-power solutions are inspiring a wave of research into MEMS-based sensor structures and alternative catalytic sensor layers. Pellistor-based sensors are typically relatively inexpensive and offer good longterm stability. In principle, they are not selective for H2 , instead delivering a combined signal for combustible gases and vapors. The high surface temperatures required can not only potentially act as a source of ignition, but are also associated with high energy consumption.

Metal oxide gas sensors Metal oxide (MOx) gas sensors are based on the reversible change of the electrical conductivity of a semiconductor layer. This change is caused by adsorption processes between the heated sensor surface and the surrounding gas atmosphere. The presence of oxygen in the gas matrix is essential for the operation of MOx sensors. Oxygen is reversibly chemisorbed on the surface at operating temperatures of 150 °C and above, leading to a charge transfer with the metal oxide. At temperatures above 400 °C, the molecular oxygen also dissociates. When the temperature and the concentration of oxygen are constant, a state of equilibrium is established at the semiconductor surface. At this point, the oxygen ions on the surface themselves react with oxidizing and reducing gases, thereby introducing or withdrawing

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Fig. 14.4 Cross-section diagram of a metal oxide gas sensor. Platinum electrodes are applied to a non-conductive substrate (ceramic). These are electrically connected to the semiconducting metal oxide so that gas reactions can be detected as resistance changes. A heating element helps keep the sensor at the correct operating temperature

electrons from the system. This charge transfer can be detected as a change in resistance [23]. The basic structure of a MOx sensor is shown in Fig. 14.4. Unfortunately, MOx sensors exhibit a low degree of selectivity, because their measuring principle leads them to react with almost all reducing and oxidizing gases. Their selectivity can be increased by selecting an appropriate metal oxide and operating temperature and using multiple sensors in an array. Coupled with their relatively high operating temperatures, and the power consumption that is required as a result, this means that MOx sensors are ultimately not suited to all areas of application. In spite of their disadvantages, these inexpensive sensors, which are stable in the long-term, are now used as standard in a number of fields, including the automotive industry, environmental technology, ventilation engineering, air conditioning technology and process engineering.

Electrochemical gas sensors Electrochemical gas sensors, also known as electrochemical cells, are chemical sensors with a complex structure. They consist of two spatially separated electrodes that are surrounded by an electrolyte. The measuring electrode can react with the target gas in the ambient air, leading to a redox reaction inside the sensor. The measuring electrode is also protected by a diffusion barrier. The electrons are transferred to the counter electrode via an external circuit (amperometric measuring principle). During this process, the current is directly proportional to the gas concentration. The function of an electrochemical gas sensor is shown in Fig. 14.5. The reaction between the electrolyte and the target gas is selective. Electrochemical sensors are available for a wide variety of different gases and concen-

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Fig. 14.5 Diagram of an electrochemical gas sensor. The gas penetrates the diffusion barrier to reach the measuring electrode. There, a chemical reaction takes place, creating an ion current from the electrolyte toward the counter electrode. The electrons are conducted through an external measuring resistor. During this process, the current is directly proportional to the gas concentration. Either ion-conducting liquids or solids are used as the electrolyte, depending on the target gas

trations. One disadvantage of this particular method of measurement is the low long-term stability of the electrolyte, which is used up over time and, in the case of liquid electrolytes, dries up. For that reason, the service life is often given as only around twelve months.

Solid electrolyte sensors Solid electrolyte sensors function according to the same principle as electrochemical sensors. Because the electrolyte is a solid object, the aforementioned issues of electrolytes drying out and aging no longer apply. However, solid electrolytes require higher temperatures and, as a result, a level of sensor heating on par with an MOx. The primary advantage of this type of sensor is its potential for high sensitivity of up to 0.1 ppm, combined with short response times of less than one second. Because it is a planar sensor, a simple layered structure is possible, which means production can be inexpensive and carried out on a highly miniaturized scale [24]. These properties make this type of sensor perfect for MEMS and for use as a sniffer sensor in leak detectors.

Gas-sensitive field-effect transistors The potential use of field-effect transistors (FET) as gas sensors is based on the discovery of the reaction of gases with the gate surface of FETs. This reaction can be useful if a suitable gate material is chosen. Gas-sensitive metal-oxide-

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Fig. 14.6 Diagram of a GASFET with a Pd-coated gate. The reaction with hydrogen on the surface of the gate causes the dissociation of the hydrogen, which in turn causes diffusion processes in the metal and leads to the formation of a dipole layer on the gate insulator. Depending on the geometry of the GASFET, this can either increase the current flow or cause the FET to “cut off” the current at a certain concentration limit

semiconductor field-effect transistors (GASFETs) can be used to detect hydrogen. The gate electrode consists of a catalytic metal such as palladium (Pd), which is known for its high level of reactivity with hydrogen. Hydrogen from the surrounding environment dissociates upon reaching the gate material, where it becomes atomic hydrogen and diffuses through the gate into the sensor. This leads to the formation of a dipole layer, which in turn causes a change in the activation energy. The shift in the transfer characteristic of the FET serves as a signal for measurement. The diagram in Fig. 14.6 shows the structure of a GASFET. The affinity of palladium and hydrogen means that even low H2 concentrations can be detected. For this reason, Pd-FETs, are often used in devices that detect hydrogen leaks [25]. They are very inexpensive to produce in miniaturized form, remain stable over the long term and consume very little energy. Because of their measuring principle, Pd-FETs are only suitable for measuring small concentrations. High concentrations lead to the degradation of the palladium layer and, ultimately, sensor failure.

Ultrasonic sensors The high speed of sound in hydrogen (1280 m/s at 20 °C) compared to air (343 m/s) [26] can be useful in detecting hydrogen. The resonant frequency of an acoustic resonator is proportional to the speed of sound. Suitable hydrogen sampling instruments are available on the market [27]. Gas escaping at high differential pressure also often produces a characteristic ultrasonic whistling sound; a special microphone can use this to locate leaks [28]. However, this method is only suitable for higher leak rates, and fails when applied to small or diffusive leaks.

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Speed of sound sensors The speed of sound increases proportionally with the H2 concentration in the air; this can be used as another measurement method. Sound signals are sent by a transmitter across a defined distance, before being received by a receiver (microphone). The time this takes reveals the concentration of H2 along the measurement distance. Appropriate transmitters that allow for highly directional radiation, up to and including solitons, can make it possible to monitor long measuring distances, as long as the transmitter and receiver can be placed with mechanical precision. Due to other environmental factors that influence the speed of sound, this method is not sensitive enough for concentration measurements relating to safety. For this reason, it is only used in the scientific sector in a specially adapted form to deal with high concentrations of hydrogen. Mapping methods using ultrasonic radar are also possible. These can be used to record the dynamic development of explosive materials with high temporal resolution. This way, they serve as the basis for making safety-related assessments, for example when determining the boundaries of explosion protection zones.

H2 mass spectrometry Mass spectrometry is based on breaking down molecules into their atomic components using electron ionization in a vacuum. Then, alternating electric fields direct the ionized atoms to detectors according to their characteristic atomic mass. The detectors then count the number of atoms. The structure of the vacuum chamber is specially designed to accommodate the light weight of gaseous hydrogen. In addition to allowing the spectrometer to measure the mass of the H atom only, this gives it some unique properties: The real-time H2 mass spectrometer developed by Fraunhofer ICT allows online concentration detection across seven decades from 100 ppb to 100 vol%, with 1 ms temporal resolution at response time t90 of 15 ms, with 100 percent selectivity [29]. For the measurement, a very small flow of sample gas is sucked in through a heated capillary; the time this takes to execute causes a measurement delay of < 200 ms. However, this method of measurement is free from cross-sensitivity within a very wide range of physical conditions at the place of measurement, including pressure and temperature, as well as in practically any gas and/or vapor atmosphere.

14.3.2

MEMS-based sensors

The semiconductor-based sensor principles of TCDs, pellistors and MOx sensors are considered to be state of the art. However, conventional forms of these tech-

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Fig. 14.7 Magnified images of microstructured MEMS-based H2 sensors. Left: Array consisting of a pellistor with an active layer (cobalt oxide with a metal catalyst) and a reference sensor. The active layer was deposited using ink-jet printing. Without a metal oxide layer, the resistor structure can be operated as a TCD (Fraunhofer IPM and Fraunhofer IMS). Center: MOx sensor as a micro-hotplate. The active surface is freely suspended by four bridges. Right: Configured as an array consisting of four independent MOx sensors (Fraunhofer IPM)

nologies consume high volumes of power due to their high operating temperatures. This can be significantly minimized using silicon technology and manufacturing processes based on microelectromechanical systems (MEMS). In these processes, the active sensor surface is thermally decoupled from the rest of the chip using etching processes, allowing for either micromechanical membrane structures or freely suspended micro-hotplates. As a result, the active areas are reduced to just a few —m2 , in turn reducing the heating output down to a few mW [30]. The basic manufacturing process is identical for all three sensor types. A silicon substrate serves as the base material, with metallic heating structures deposited on its surface. The layers can be produced through thermal evaporation of the pure metal or through sputtering. The active layer is thermally decoupled using a wet etching process conducted on either the front or back side. For TCDs, the manufacturing process ends here. However, in addition to the heating element, MOx sensors require an electrode structure, which is deposited on the front. In the last step of the process, the active gas-sensitive materials are deposited on the pellistors (e.g., cobalt oxide with a catalyst) and MOx sensors (e.g., tin dioxide) [31]. Ideally, this should be done without contact, for instance through printing processes (ink-jet printing), as the membrane or micro-hotplate will have a low level of mechanical stability. Many target gases can be detected using layers that react more sensitively than others; these gases also tend to have ideal operating temperatures. The most sensible approach is therefore to process and operate MEMS-based sen-

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sors as an array on a chip in order to increase selectivity levels. Fig. 14.7 shows magnified images of microstructured H2 sensors. One possible area of application for MEMS-based sensors is in fuel cell vehicles. The cost pressures in the automotive industry can be overcome by using semiconductor technologies to reduce manufacturing costs; the limited size of the sensors can also help in this regard. Due to the high risk of personal injury, safety standards take top priority in the automotive industry. Despite the H2 system being hermetically sealed, it is necessary to continuously measure maximum H2 concentrations using a number of sensors in the exhaust system, on the drive and in the passenger compartment. This is regulated in the ECE-TRANS-180a13e standard. The future of sensors for mobile fuel cell applications lies in combining at least two complementary measurement principles to provide intrinsically safe sensors (with the focus being on functional safety). “Intrinsic safety” is defined in the ISO 26262 standard. For example, this standard stipulates that an intrinsically safe sensor must be able to detect a concentration of 0.4 percent hydrogen within three seconds. When starting and stopping an engine, in particular, there is the risk that the membrane of the fuel cell will rupture, and a large amount of hydrogen will be released. This presents a major challenge, especially during operation, since measurements must remain reliable even when temperatures reach below freezing point, i.e., in the event of icing or when condensation forms in the sensor housing. One possible solution is to integrate a cold trap as a water separator. This way, the water contained in the exhaust gas is removed from the gas flow through condensation. This separator can be made of metal (e.g., copper) and stacked directly in front of the gas sensor. Peltier elements attached to the sides allow cooling to a temperature below 0 °C. Fig. 14.8 shows a laboratory setup for simulating an exhaust system with an integrated sensor setup. This allows gas flows of up to 5 l/min. In addition to the safety sensors for the exhaust gas, monitoring the vehicle’s tank is also crucial. In this case, the hydrogen is compressed at a pressure of up to 700 bar. The sensors must be able to detect leaks at an early stage and use an automatic shutoff system to prevent the further operation of the vehicle. For this reason, inexpensive and reliable hydrogen sensors must be developed to ensure the safe use of hydrogen fuel cells. In principle, there are a number of sensor solutions that could be used to detect and determine the concentration of hydrogen in mobile and stationary applications. However, these have so far not proven successful in practical implementation, where both price and reliability are enormously important factors.

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Fig. 14.8 Left: Laboratory setup of an exhaust line. Any hydrogen contained within can be measured by a TCD. A cold trap in front of it removes moisture from the exhaust gas, ensuring that only dry gas reaches the sensor. Right: A 4  4 mm2 thermal conductivity sensor. (Fraunhofer IPM)

14.3.3 Optical sensors Fiber-optic sensors In addition to the useful electrical effects explained above in relation to GASFETs, a change in volume occurs when palladium comes into contact with hydrogen. Since this change is very small, interfering light waves are used for detection, allowing changes in length in the nanometer range to be measured. Given that open beamlines are impractical in sensors, a number of different fiber optic sensors have been developed that use the change in the volume of palladium to mechanically alter the lengths of optical paths or change the grating constant of an inserted optical grating. In the case of tungsten trioxide (WO3 ), on the other hand, the optical refractive index alters upon contact with H2 . This effect can also be used in a fiber optic configuration by measuring the reflection behavior of a prism coated in WO3 . Fig. 14.9 shows how these fiber optic sensors work. Sensors of this kind are, and will remain, technically complex, and this makes them expensive. Their main advantage is the complete absence of possible sources of ignition and that they offer the possibility of physically separating concentration detection and electrical evaluation in the interferometer control using the fiber optics. The change in the volume of palladium can also be used to detect H2 , because the resulting forces act on platinum, which changes its resistance under pressure (Fig. 14.9). This type of sensor is also difficult to manufacture and, as a result, expensive. However, using resistance change as a measurement method allows for very low energy consumption.

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Fig. 14.9 Fiber-optic H2 sensors that use the change in the volume of palladium or the change in the refractive index of tungsten trioxide when in contact with H2 as a measurement method

Non-contact optical detection In many applications, there are advantages to non-contact gas detection methods. “Non-contact” means that, when detecting a gas, a gas sample is not required for analysis or chemical conversion in a measuring cell. Non-contact measurement methods can detect a gas cloud from a distance (a method known as standoff detection). This can also be done from very long distances, such as from an airplane or helicopter. The disadvantage of non-contact detection is that the distribution of a gas in a gas cloud is unstable in three dimensions, making it impossible to precisely determine the concentration of the gas. The use of non-contact methods for detecting and locating leaks has become established, particularly when it comes to efficiently inspecting large natural gas systems and pipeline networks. One major advantage of this is that many possible leak locations can be tested simultaneously using a single imaging device. In contrast to sensors that must come into contact with gas, and so must be installed in close proximity to potential leaks, a gas cloud can be observed with a non-contact system even if air currents or complex installations prevent the leaking gas from reaching the gas sensor. A distinction is made between passive and active methods of non-contact gas detection.  Passive infrared (IR) methods use temperature differences in the environment. For example, they can measure the gas-specific infrared absorption of thermal radiation from a suitable surface in the vicinity. If methane gas escapes from a pipe next to a warm wall of a house, the heat radiation from the wall will be absorbed by the methane gas cloud in a characteristic spectral range. The gas cloud in front of the leak can be imaged using conventional, highly sensitive

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Fig. 14.10 CH4 gas flows out of a 0.3 mm bore at 2 ml/min. Left: False-color representation of active imaging CH4 leak detection from a distance of 2 m (excerpt from a video with a frame rate of 125 Hz). The IR laser illuminates a 7.5 cm diameter circle on an Al plate. Right: Horizontal and vertical slices sections through the image on the left. The shape and direction of the gas plume are constantly changing due to air currents [35]

thermal imaging cameras equipped with suitable spectral filters. These devices are available on the market [9].  Active gas detection methods also use infrared absorption, but use their own infrared radiation source in order to avoid being affected by varying ambient temperatures. Laser-based measuring devices, in particular, can achieve high levels of sensitivity and selectivity. To do this, the emission wavelength of a laser is quickly tuned to a characteristic absorption line of the target gas. The change in intensity observed in the laser radiation reflected by the object during this process depends on the product of the average gas concentration and the distance covered, or column density. This can be measured very precisely. The column density is given in ppmm. Natural gas leaks can be localized using laser-based point detectors [10] from distances of up to 30 m. If the laser beam is moved over the object or a mobile platform is used, the measured values can be combined into images. A method like this is used to monitor gas pipelines using helicopters from a distance of over 100 m [11]. For shorter distances, simultaneous active imaging is also possible [34]. Combining sensitive laser spectroscopy methods with an infrared camera allows for pixelwise sensitivities of 1 ppmm for CH4 , allowing leaks of 2 ml/min to be detected at a distance of 2 m with a frame rate of 125 Hz (Fig. 14.10; [35]). Pure hydrogen shows no infrared absorption. However, this technique can be used for carrier gases such as NH3 or natural gases with high H2 content.

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Pure hydrogen can be detected using a Raman LIDAR method from distances of up to 50 m (Light Detection and Ranging, LIDAR). However, the laser power must be kept low for reasons of eye safety and explosion protection. Even compact devices are sensitive enough to detect concentrations of H2 in the air below the lower explosion limit of 4 percent [36, 37]. Remotely detecting lower hydrogen concentrations using stimulated Raman scattering also appears to be feasible [38]. Since the low signal intensities require long integration times, fast image changes such as those mentioned above in relation to infrared cameras with Raman spectroscopy are currently not possible. A possible alternative to methods for specifically detecting H2 could be to detect changes in the oxygen concentration of the ambient air. This method is based on the fact that, in the event of a leak, the escaping gas displaces the air at the leak point. As a result, the concentration of oxygen decreases at the leak location. In the free atmosphere, the concentration of oxygen is constant at 21.0 percent. If, for example, a hydrogen leak completely displaces the oxygen within a radius of 2 cm around the leak, the average oxygen concentration will change by 1 percent relative to a measurement from a distance of 2 m, i.e., a concentration of only 20.8 percent would be measured. There are laser-optical oxygen measuring devices available on the market that can achieve this level of accuracy. As part of an internal project, Fraunhofer IPM was able to successfully demonstrate this patented principle using nitrogen as the leakage gas [39]. The method can be used for any type of gas, except of course for oxygen, which acts as the background gas. For this reason, it can in principle also be used for hydrogen leaks. N2 leak rates of 100 ml/min could be detected using this method from a distance of 55 cm [40]. The point detection process used in this method could be expanded to include imaging detection. As shown in [35], imaging methods have a higher probability of detecting leaks, since the influence of flow-related fluctuations is less significant. In contrast to CH4 , an infrared camera is not required to detect oxygen. The concentration of oxygen is measured at a wavelength of 761 nm (at the Fraunhofer line A).

Imaging in explosion-risk areas The Background Oriented Schlieren Method (BOS) was developed by DLR to visualize highly transient flow processes in aeronautics. Fraunhofer ICT has proposed that it be used for hydrogen safety [41]. This passive method makes use of the density of hydrogen, which is 14.6 times less dense than air. Density gradients produce background distortion, similar to what can be observed when there is hot gas above a flame. By examining a statistically structured background, compared against an undisturbed reference image, the local distortion level is calculated using digital image data. This method is sensitive enough to cover the extent of the

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Fig. 14.11 Non-contact BOS visualization of uncombusted hydrogen in the exhaust gas of a fuel cell vehicle during an emergency stop. (Fraunhofer ICT)

concentration range that is relevant to determining safety, from 100 percent by volume to the lower ignition limit. This enables dynamic combustible gas volumes to be estimated with a temporal resolution that is only limited by the camera used in the process. Fig. 14.11 shows an example use case.

14.4 Sensors for non-destructive testing The following sections will describe sensors for non-destructive testing (NDT) and how they are used to monitor the structural integrity of hydrogen infrastructure in terms of corrosion and hydrogen embrittlement.

Long-range ultrasound Hydrogen infrastructure, such as steel pipelines, can corrode if the cathodic corrosion protection (CCP with galvanic sacrificial anodes) fails, or if the insulation

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is insufficient or faulty. Because visual inspections cannot be used in many cases, and corroded areas are often not directly accessible through other methods, it is difficult to record and assess this damage. Not only that, but surface corrosion normally leads to a two-dimensional, albeit shallow, reduction in the thickness of the walls, resulting in a complex geometry that goes beyond the limits of commercial measuring and testing methods. Such methods therefore cannot be relied upon to evaluate the damaged area. Using long-range ultrasonic waves (guided wave testing; long range ultrasonic testing, LRUT) in these difficult cases can help provide reliable evaluations. In extended, three-dimensional components, sound propagation occurs primarily through pure longitudinal and transverse waves known as volume waves, which carry out a particle deflection in the direction of dispersion, or perpendicular to it. On the other hand, in components that have limited space (rods, tubes, plates, etc.), sound propagation takes place in the form of guided ultrasonic waves (long-range ultrasound) [42–44]. Provided good conditions, inaccessible test areas can be examined over distances of up to 50 m without the need to remove insulation or undertake the major task of digging up the component [45, 46]. If transducers based on electromagnetic ultrasound (EMUS transducers) are also used, then no direct contact between the probe and the test object is required; this means that a coupling agent is not necessary [44]. The use of these dispersive, guided ultrasonic wave modes offers the possibility of detecting very small reductions in wall thickness along the sound path of an ultrasonic transmission measurement and/or reflection measurement [47, 48]. For this reason, they are suitable for detecting even the most minor corrosion damage. The physical measurement method is based on the change in both the phase and group velocity of the dispersive, ultrasonic wave mode across the wall thickness. As a result, it is possible to retrieve quantitative information on the damage by evaluating the phase shift, the sound propagation time of the received signal and the mode conversions caused by the damage. Fig. 14.12 shows an excerpt of a processed and evaluated data set from a pipeline scan, which reveals three types of corrosion damage. The color coding visualizes the location and spatial extent of the damage. Beside this is a damage indicator for the loss in wall thickness. Depending on how the test parameters are selected, specific signal intensities can be achieved in relation to specific degrees of damage. A test of this kind can reliably identify and localize defective areas given a reduction in wall thickness of five percent or more.

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Fig. 14.12 Left: Evaluated and visualized long-range ultrasonic data for an H2 supply line with three areas of natural pitting corrosion. Right: Evaluated and interpreted measurement data for damage interpretation (wall thickness reduction). (Fraunhofer IZFP)

Electromagnetic methods for monitoring the structural integrity of ferromagnetic components in the hydrogen infrastructure Electromagnetic methods can not only determine material properties in ferromagnetic materials but can also be used to detect signs of aging and fatigue [49–52]. Here, characteristic correlations between the mechanical and magnetic properties of the materials are used to qualitatively and quantitatively monitor material properties such as the relationship between mechanical hardness and the coercive field strength H C (magnetic hardness) [53]. Combining multiple electromagnetic methods in a multi-parameter, hybrid approach offers additional stability, interference resistance and accuracy in the process of electromagnetic material characterization and opens up the possibility of applying AI-based and machine learning methods [54, 55]. This kind of multi-parameter approach is already being used with 3 MA technology (micromagnetic multi-parameter, microstructure and stress analysis) in various industrial and research areas, and is constantly being further developed [55– 57]. Depending on the application requirements, and how these influence the details of the sensors, the 3 MA approach involves a combination of harmonic analysis of the time signal from the tangential magnetic field strength or from the magnetizing current, with magnetic Barkhausen noise analysis, incremental permeability and impedance analysis of eddy currents [55]. Embrittlement and stress corrosion cracking effects can occur on account of the interaction of hydrogen with ferromagnetic materials (pipes, etc.). Applying 3 MA testing technology can potentially determine hydrogen-related changes in ferro-

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magnetic materials at an early stage using a non-destructive process. This potential has already been demonstrated through research and development projects in the field of nuclear technology, both for hydrogen-related material damage and other embrittlement mechanisms (e.g., neutron embrittlement) [50, 58, 59].

Magnetic flux leakage process for detecting corrosion-related reduction in wall thickness in ferromagnetic materials The probe-based magnetic flux leakage method is based on a physical effect also used in magnetic particle inspection to detect crack-like surface defects in ferromagnetic materials [60]. When an external magnetic field is applied to breaks in the surface, magnetic dipoles are formed due to the permeability differences, which leads to a near-surface magnetic stray field (see the field line model in Fig. 14.13, left). These can be detected using highly sensitive magnetic field sensors (see progression of the line in Fig. 14.13 on the right). In contrast to magnetic particle testing, the magnetic flux leakage method eliminates the need for magnetic powder to visualize the defects. The use of highly sensitive magnetic field sensor arrays, in combination with machine learning algorithms, allows the automatic evaluation of differences in the recorded measurement signals. This makes it possible to detect corrosion-related damage such as wall erosion, pitting corrosion or cracks in ferromagnetic infrastructures such as pipelines using non-contact, non-destructive processes. Because the damage patterns are similar, in principle, the magnetic flux leakage method is also suitable for detecting hydrogen-induced corrosion damage.

Fig. 14.13 Course of the magnetic field at a crack in a magnetized component. Left: Diagram. Right: Measured normal component of the magnetic field. (Fraunhofer IZF)

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Magnetic flux leakage method for corrosion testing on H2 pipelines The PipeFlux system is the result of a study that examined the extent to which corrosion-related test failures can be detected and separated from both the side facing the sensor and the side facing away from the sensor in pipeline steel. Using combined measurement technologies allowed for the addition of a modified sensor arrangement. Fig. 14.14 shows two surface images of a tubular steel panel with two test failures. The two images on the left show the result of the magnetic flux leakage method; the two on the right were recorded using magnetic field distortion. While the magnetic flux leakage method picks up stray fields from the entire volume, making it difficult to map damage on the side facing the sensor (left) and the side facing away from the sensor (middle left), further determining the field distortion will only show near-surface structures on the side facing the sensor (middle right), and will not show any on the side facing away from the sensor (right). This multimodal approach makes it possible to map failures on the side facing the sensor and the side facing away from the sensor separately. The left-hand image in Fig. 14.15 shows the implementation of the PipeFlux portable measuring system, which is based on the magnetic flux leakage method, in order to characterize corrosion damage in pipelines. The system is connected

Fig. 14.14 Leakage flux measurement of the side facing the sensor (left) and the side facing away from the sensor (middle left); field distortion measurement of the side facing the sensor (middle right) and the side facing away from the sensor (right). (Fraunhofer IZFP)

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Fig. 14.15 PipeFlux, a portable measuring system based on flux leakage that characterizes corrosion damage in ferromagnetic pipelines. (Fraunhofer IZFP)

to a pipeline using permanent magnets and moved around the pipe (see Fig. 14.15 on the right). The permanent magnets induce a level of flux density in the pipe segment that is necessary for generating the stray field. The magnetic fields are each recorded using an 80-channel sensor array for measuring flux leakage and field distortion; using a position encoder that is moved in circles, the fields are then displayed in the form of a surface image. This flexible approach can be adapted for use with almost any ferromagnetic structure.

X-ray examination of the internal structures of fuel cell stacks and H2 infrastructure Methods that use X-ray imaging for the non-destructive testing of internal structures can also be applied to fuel cell stacks and components in hydrogen infrastructures. “X-ray” refers to electromagnetic radiation in an energy range between one and several hundred keV. In the case of 2D radioscopy, radiation emanating from an approximately point-shaped X-ray source penetrates the object that is being examined and can be weakened, depending on the internal structure of the object. The weakened radiation is recorded using a flat-panel detector, and the principle of shadow casting is used to generate a projection image of the object. If the examination requires determining the 3D features of a structure, a 2D projection image will not suffice. Here, 3D computed tomography (3D CT) comes into play. This involves generating multiple projection images of the examined object from various directions, in order to then use mathematical methods to calculate a 3D model that features all internal structures of the object. Robot-assisted computed tomography

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was developed so that large objects that are difficult to access can be examined using 3D computed tomography on site and with a high resolution. This process involves attaching both an X-ray source and the detector to a robot, which enables radiography of the object from almost any desired direction. Robot-assisted computed tomography currently allows for defects such as porosities, gas entrapment or foreign bodies in objects to be detected with a resolution (voxel edge length) of 50 m.

Characterizing ceramic solid electrolytes for fuel cells using nuclear magnetic resonance spectroscopy Different electrolytes, reaction gases and process temperatures are used in a fuel cell for different applications. In a motor vehicle, for example, a polymer electrolyte membrane (PEM), hydrogen and air are used at temperatures of around 80 °C. However, in space technology, caustic potash (alkaline fuel cell), hydrogen and oxygen are used at a temperature of 80 °C. During cogeneration of heat and power, phosphoric acid, natural gas and air react at a process temperature of between 160 and 220 °C. Solid fuel cells are being developed for future use in cogenerating heat and power and operating motor vehicles, to name just a few examples. These solid oxide fuel cells operate at temperatures above 600 °C using ceramic solid oxide electrolytes. With the help of solid-state nuclear magnetic resonance spectroscopy (NMR spectroscopy), dynamic phenomena such as the exchange and diffusion processes of charge carriers, structural phase transformations and chemical processes can be observed as a function of temperature.

14.5 Summary and outlook To ensure that the hydrogen economy is successful and is accepted by the public, it must be ensured first and foremost that no dangers are posed by the technology. In the future, both the infrastructure of the hydrogen economy and its usage must become as commonplace as electricity, water and gas supplies are today. When establishing the infrastructure necessary to produce, store, distribute and convert hydrogen into an energy source, it must be ensured that there are no risks to safety or hazards that may cause accidents. The same applies once the infrastructure enters operation. In order to be economically viable, the systems must also have a long service life, given efficient and reliable maintenance.

References

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Here, sensors play a key role in ensuring safety. Sensors allow both immediate dangers and future dangers to be identified and prevented in good time. This is why it is necessary to include a sensor concept that is suitable for all possible scenarios when planning H2 infrastructure systems and applications. One major challenge here is condition monitoring for hydrogen-loaded components in stationary and mobile systems during operation; sensor systems must be used for detection and control in this context. Existing sensors for non-destructive testing are capable of monitoring structural integrity. In addition, all systems and mobile applications, e.g., vehicles with fuel cells, must be monitored for leaks. Leak tests can be carried out using established sensor concepts during reactive, regular or predictive maintenance. Permanent monitoring is possible using permanently installed H2 safety sensors. However, the available technical solutions are often only of limited use, or their use requires a great deal of time and money. It is therefore important to lay the foundations for marketable, operable solutions and standards in a timely manner through research and development, thereby securing the hydrogen economy. The research and development work on sensor technology that we have presented here shows how current restrictions can be minimized and, in the future, eliminated entirely.

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8. DVGW: DVGW G 465-4:2019-05. Technical equipment for the leakage survey of gas pipework and gas stations. https://www.beuth.de/en/technical-rule/dvgw-g-465-4/ 308686557, last viewed on December 13, 2021 9. FLIR: FLIR GF320. Infrared Camera for Methane and VOC Detection https://www.flir. eu/products/gf320/ 10. crowcon: LaserMethane mini, https://www.crowcon.com/products/portables/lmm-gen2/#description 11. Open Grid Europe: CHARM®—Laser-Based System for Remote Gas Detection. https:// oge.net/en/for-customers/services/technical-services/integrity-and-safety/charm 12. Dadashzadeh M., Kashkarov S., Makarov D., Molkov V. (2018): Risk assessment methodology for onboard hydrogen storage. International Journal of Hydrogen Energy 43, 6462–6475 13. MWV e. V.: Tankstellenbestand (Number of gas stations). https://archiv.en2x.de/ tankstellenbestand/, last viewed on December 12, 2021 14. Zukunft Erdgas e. V.: Tankstellennetz (Gas station network). https://www.erdgas.info/ erdgas-mobil/alternative-kraftstoffe/vergleich-cng-und-lpg/, last viewed on December 13, 2021 15. Wikipedia: Hydrogen. https://en.wikipedia.org/wiki/Hydrogen 16. Nabert K., Schön G., Redeker T. (2016): Sicherheitstechnische Kenngrößen brennbarer Gase und Dämpfe (Safety parameters for flammable gases and vapors). Kenngrößen des Explosionsschutzes, zusammengestellt aus Schrifttum und eigenen Messungen (Parameters for explosion protection, compiled from literature and own measurements). Third edition. Deutscher Eichverlag, Braunschweig 17. National Metrology Institute of Germany (PTB): CHEMSAFE—Database for safety characteristics in explosion protection. https://www.chemsafe.ptb.de/ 18. Gye H.-R., Seo S.-K., Bach Q.-V., Ha D., Lee C.-J. (2019): Quantitative risk assessment of an urban hydrogen refueling station. International Journal of Hydrogen Energy 44: 1288–1298 19. Hirayama M., Shinozaki H., Kasai N., Otaki T. (2018): Comparative risk study of hydrogen and gasoline dispensers for vehicles. International Journal of Hydrogen Energy 43: 12584–12594 20. Kikukawa S., Yamaga F., Mitsuhashi H. (2008): Risk assessment of Hydrogen fueling stations for 70 MPa FCVs. International Journal of Hydrogen Energy 33: 7129–7136 21. HYDRAITE—Hydrogen Delivery Risk Assessment and Impurity Tolerance Evaluation (2019): D4.1 Report on European analytical capabilities for hydrogen purity according to ISO 14687 and quality assurance. https://hydraite.eu/public-reports/, last viewed on December 13, 2021 22. Atkins P.W., de Paula J., Bär M. (2013): Physikalische Chemie (Physical chemistry), 5th edition. Wiley-VCH, Weinheim 23. Madou M.J., Morrison S.R. (1989): Chemical Sensing with Solid State Devices. Academic Press 24. Fraunhofer ICT: LHyCon—Low Hydrogen Concentration Measurement Sensor. https:// www.ict.fraunhofer.de/de/projekte/LHyCon.html, last viewed on December 12, 2021 25. Inficon: Sensistor® Sentrac Hydrogen Leak Detector. https://www.inficon.com/en/ products/hydrogen-leak-detector-sensistor-sentrac 26. Wikipedia: Speed of sound. https://en.wikipedia.org/wiki/Speed_of_sound

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46. Niese F., Salzburger H.-J., Zenner J. (2007): Scannende Prüfung auf Außenkorrosion an Rohrleitungen mittels umlaufenden geführten Wellen (Scan testing for external corrosion on pipelines using circumferential guided waves). In: ZfP in Forschung, Entwicklung und Anwendung (NDT in research, development and application). DGZfPJahrestagung (Annual conference of the German society for non-destructive testing), 2007. CD-ROM 47. Jäckel P., Niese F. (2013): Neue Ansätze in der quantitativen Korrosionsdetektion unter gezielter Ausnutzung des dispersiven Verhaltens geführter Ultraschallwellenmoden. (New approaches in quantitative corrosion detection by the selective use of the dispersive behavior of guided ultrasonic wave modes.) In: ZfP in Forschung, Entwicklung und Anwendung (NDT in research, development and application). DGZfP-Jahrestagung (Annual conference of the German society for non-destructive testing), 2013. CD-ROM, Paper Mi.3.B.3. 48. Jäckel P., Niese F., Boller C. (2014): Anwendungen und Chancen bei der quantitativen Korrosionsdetektion mittels Nutzung des charakteristischen Phasenverhaltens geführter Ultraschallwellenmoden in Transmissionsanordnung (Applications and opportunities in quantitative corrosion detection using the characteristic phase behavior of guided ultrasonic wave modes in a transmission arrangement). In: ZfP in Forschung, Entwicklung und Anwendung (NDT in research, development and application). DGZfP-Jahrestagung (Annual conference of the German society for non-destructive testing), 2014. CD-ROM, Paper Mi.1.A.2 49. Dobmann G., Kern R. (2000): Micro-Magnetic, Multiple-Parameter, Microstructure and Stress Analysis—3 MA—For Non-Destructive Material Properties Determination and Ageing Prediction. AMES-NDT-Workshop 2000 50. Szielasko K., Tschuncky R., Rabung M. et al. (2014): Early detection of critical material degradation by means of electromagnetic multi-parametric NDE. AIP Conference Proceedings. AIP Publishing LLC: 711–718 51. Hübschen G., Herrmann H.-G., Altpeter I., Tschuncky R. (ed.) (2016): Materials characterization using nondestructive evaluation methods. Woodhead Publishing 52. Rabung M., Kopp M., Kuhn B. et al. (2016): Nondestructive Characterization of Ageing Phenomena in Heat Resistant Steels by Means of Micromagnetic Techniques. 19th World Conference on Nondestructive Testing, Berlin 53. Hering E., Martin R., Stohrer M. (2002): Physik für Ingenieure (Physics for engineers), 8th edition. Springer, Berlin Heidelberg 54. Tschuncky R., Szielasko K., Altpeter I. (2016): Hybrid methods for materials characterization. In: Materials Characterization Using Nondestructive Evaluation (NDE) Methods. ISBN 978-0-08-100040-3: 263–291 55. Szielasko K., Wolter B., Tschuncky R., Youssef S. (2020): Micromagnetic materials characterization using machine learning, tm Technisches Messen 87, 428–437 56. Wolter B., Szielasko K., Tschuncky R., Conrad C. (2017): Micromagnetic testing at Fraunhofer IZFP: Highlights and experiences of more than 3 decades of research. 12th International Conference on Barkhausen Noise and Micromagnetic Testing (ICBM12) Vaajakoski: Stresstech Oy 57. Altpeter I., Becker R., Dobmann G. et al. (2002): Robust solutions of inverse problems in electromagnetic non-destructive evaluation. Inverse Problems 18: 1907–1921

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Digitalization and simulation of hydrogen technologies

15

Sylvia Schattauer  Alexander Spieß Fraunhofer Institute for Wind Energy Systems IWES Alexander Martin  Robert Burlacu Fraunhofer Institute for Integrated Circuits IIS Gregor Herz Fraunhofer Institute for Ceramic Technologies and Systems IKTS Christian Leithäuser Fraunhofer Institute for Industrial Mathematics ITWM Ulrike Beyer Fraunhofer Institute for Machine Tools and Forming Technology IWU Joachim Seidelmann Fraunhofer Institute for Manufacturing Engineering and Automation IPA Fabian Frank Fraunhofer Institute for Chemical Technology ICT Abstract

As the digital transformation continues to advance, it is creating further possibilities for conducting analyses in hydrogen technology research. In one form or another, it is being used in almost all subcategories of the field. This chapter will provide insight into various application areas where digital methods and model-based analyses are being used. These includes energy system modeling, © Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_15

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mapping transportation infrastructures, process engineering modeling in the chemical industry, the targeted further development of electrolysis, upscaling production and the simulation-based design of safe hydrogen infrastructures.

15.1 Introduction and overview The digital transformation is spreading through and transforming both our everyday and professional lives. As the digital transformation continues to advance, it is creating further possibilities for conducting analyses in hydrogen technology research. In one form or another, it is being used in almost all subcategories of the field. This chapter is intended to provide an insight into various areas of application where digital methods and model-based analyses are used. Only a small selection can be examined here. It is difficult to make simple, clear classifications due to the large number of application areas, modeling methods and distinguishing features. In the field of electrolyzer cells and stack development alone, there is a wide range of methods spanning from the modeling of material, electrical and thermal processes in the electrolytic cell to the mapping of material-related degradation mechanisms on the catalyst surface [1]. Simulations can not only be used for detailed mapping of physical and chemical processes in electrolysis cells, but also for combining technical plant components to form complete plant systems, as well as integrating the plants into the energy system. Last but not least, digital methods offer new ways of designing scalable production systems. The following subchapters will therefore examine the following topics:  Contemporary discussions on green hydrogen technologies are driven in part by its potential to bring about a transformation toward a climate-neutral energy economy and industry. But, to what extent is this really in demand? What costs are associated with green hydrogen, and what investments must be made? Finding answers to these questions falls under the scope of energy system modeling. Sect. 15.2 gives a brief insight into the areas of application, approaches and distinguishing features of green hydrogen technologies.  An inherent and sometimes integral part of energy system modeling is the process of mapping transportation infrastructure. In addition to ships and trailers, pipelines are a possible solution for transporting hydrogen. Determining an optimal hydrogen transportation network makes for a difficult modeling task.

15.2 Future hydrogen demand and integration into energy markets



 



395

Sect. 15.3 provides insights into the current state of research and the different possible approaches. The chemical industry is one of the most promising areas of application for green hydrogen. But how can electrolyzers be optimally combined with chemical syntheses? Sect. 15.4 demonstrates the potential benefits of modeling for process engineering. Increasing cell and stack efficiency are both important targets in developing this technology. Sect. 15.5 describes the extent to which detailed physical models allow for electrolysis to be further developed in a goal-oriented way. The National Hydrogen Strategy for the market ramp-up of green hydrogen technologies aims to strategically upscale production. What role can digital transformation play here? And what are the appropriate approaches to take in the field of digital factories? Sect. 15.6 gives a brief insight into this. Last but not least, the process of developing new technologies and launching them on the market always involves developing appropriate safety technology and identifying any necessary safety considerations. Hydrogen is particularly sensitive due to its material properties. Simulation-based analyses are an integral part of predicting the safety-critical behavior of hydrogen applications and systems. Sect. 15.7 gives a brief insight into the simulation-based design of safe hydrogen infrastructures.

15.2 Future hydrogen demand and the integration of hydrogen into energy markets Green hydrogen technology is considered a beacon of hope for constructing a climate-neutral energy sector and industry. But, to what extent is green hydrogen really in demand? What costs are associated with green hydrogen, and what investments must be made? How can these technologies be integrated into the markets, and what revenue can they generate? The relevant literature contains a large number of studies and scientific publications that deal with these and similar questions [2]. A common feature of the studies is their use of similar methods and modeling approaches that can be categorized as belonging to the field of energy system modeling. They are based on future scenarios that serve to define necessary conditions, such as the maximum permitted amount of greenhouse gas emissions trading and technology development road maps. Mathematical optimization methods are normally used for calculation. These can, for example, be used to determine the future composition of a power

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plant fleet or analyze the most cost-effective way to integrate individual plants into the market. A study that covers an extensive scope (national, EU, global) and multiple sectors can be referred to as a system study. Well-known studies on the national level in recent years have included “dena Study—Integrated Energy Transition” [3] and “Wege für die Energiewende” (Paths for the energy transition) [4]. At the EU level, examples include the “Hydrogen Roadmap Europe” [5] and “Industrial Innovation: Pathways to deep decarbonization of Industry” [6]. The results usually include the spatially resolved figures found for energy and raw material demand, as well as the technologies used for the scenarios considered. Fig. 15.1 shows an example of results of this kind: the calculated demand for hydrogen and its derivatives according to a study commissioned by the Umweltbundesamt (UBA, German Environment Agency) from 2019 [7]. The results are separated out according to the sectors that the demand stems from and the energy carriers. The study is based on a scenario in which the EU achieves climate neutrality by 2050, without the use of carbon capture and storage technologies (CCS) and with limited biomass potential. The energy system model Enertile® was used for the EU-wide analysis. The model depicts the components of the energy system as a linear optimization problem, which determines the minimum costs from demand sectors and generation technologies, taking grid infrastructures into account. Enertile® analyzes the potential for generating electricity from renewable energies with a temporal resolution of one hour and a spatial resolution of ten square kilometers. More detailed descriptions of the model and the methodology for analyzing hydrogen demand can be found in [8] and [9], among others. One current focus of scientific discussions on energy system modeling is the modeling of hydrogen transportation networks. Sect. 15.3 goes into more detail on this. In contrast to system studies, analyses for identifying optimal marketing strategies from a business point of view are conducted with a focus on individual systems and system networks. The 2018 study “Strommarktseitige Optimierung des Betriebs einer PEM-Elektrolyseanlage” (Optimizing the operation of a PEM electrolysis plant with regard to the electricity market) provides insights into this with reference to the Energiepark Mainz [10]. The aim is to find an economically optimal form of system control, taking into account the costs of procuring electricity, possible income from participating in the secondary control power market, and marketing options for the hydrogen produced. The submodels are depicted as mixed-integer linear problems. The simulation is carried out with a higher temporal resolution than system studies, so that it can map participation in the electricity and operating reserve market. A more detailed modeling of the electrolysis is also required. The principle of rolling-wave planning is used to produce a realistic simu-

15.2 Future hydrogen demand and integration into energy markets

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Fig. 15.1 Requirements for hydrogen and its derivatives to achieve a greenhouse-gas-neutral EU

lation. Short-term forecasts of price developments on the electricity and operating reserve markets are made for this purpose. These are then incorporated into the process of determining the operating plan for the electrolysis system. The examples listed here show the wide range of applications of energy system modeling for addressing various issues relating to a green hydrogen economy. The models used in this process usually differ greatly. Their respective distinguishing features, listed in Fig. 15.2, include different mathematical approaches, the distinction between top-down and bottom-up models and technical details (geographic balance scope, spatial resolution and temporal resolution of the sectors

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Fig. 15.2 Properties and possible classification criteria for energy system models. (from [11])

covered, etc.) [11]. When interpreting the results, both the distinguishing features of the methodology and the limiting conditions of the scenarios must be taken into account. The challenges that arise when comparing different studies are shown in “Metastudie Wasserstoff—Auswertung von Energiesystemstudien” (Hydrogen meta-study—Evaluation of energy system studies) [2].

15.3

Modeling and simulating hydrogen pipelines

The current global hydrogen market is determined by the needs of the chemical and petrochemical industries. As the transition to a climate-neutral economic and energy system progresses, further sales markets and application areas for hydrogen will emerge. As a result, not only will methods of production change, but the transportation volume will also increase. This will create new demands on the transportation system. The long-distance transportation of hydrogen via pipeline is increasingly being seen as a promising technology for transportation and distri-

15.3 Modeling and simulating hydrogen pipelines

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bution. A large number of projects are focusing on the technical suitability of new pipelines and existing natural gas systems. These projects focus on research questions that can only be answered through detailed modeling of the overall system, taking the entire supply network into account. One challenge here is to model the interaction of physically mapped properties and discrete choices in a sufficiently realistic way. To achieve this, the respective models are usually depicted as a mixture of non-linear and discrete integer problems. The physics of the gas is given as a system of non-linear partial differential equations and can be simplified to an algebraic form as required. Controls or noncontinuous decisions (such as turning a compressor on and off) are represented by integer variables. The models are therefore divided into stationary and transient models. At this point, it is necessary to mention the Transregio 154 special research area “Mathematical Modelling, Simulation and Optimisation Using the Example of Gas Networks” (spokesperson: Prof. Alexander Martin, IIS institute director), which has been running since 2014.

15.3.1 Stationary models Stationary models are easier to operate than transient models. With stationary models, it is possible to address problems that are formulated across longer periods of time, where physical dynamics are of lesser importance. Stationary solutions are being used to address central questions such as whether a given volume of gas (nomination) can be transported through a network. An insight into the various stationary modeling approaches can be found in [12]. In most cases involving discrete choices, the physics of the gas is depicted using the Weymouth equation, which exists in algebraic form. An alternative is offered in [13] and [14], which formulate gas flow using a system of ordinary differential equations (ODE) and develop a learning procedure based on it. Mixing hydrogen and natural gas on larger networks with components that can be switched on and off involves highly complex mathematics. For example, [15] presents a method that can determine optimal mixing ratios. However, this method is heuristic in nature and is not guaranteed to provide the optimal solution.

15.3.2

Transient models

Certain problems require the gas flow to be modeled in a dynamic, transient way, meaning that they cannot be adequately represented using stationary models. These

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include, for example, problems involving dynamic load profiles. Here, a transient model is necessary to adequately map the dynamics of the gas and thus determine how the network may realistically react. The following examples provide an insight into current research developments. In [16], a transient model of a power-to-gas system was optimized using a method that was developed to expand stationary models based on the Weymouth equation into transient models. Another possibility is mixed-discrete dynamic optimization, which has been the subject of intense research. In this case, the problem is typically depicted as a system of differential algebraic equations. An overview of this can be found in [17]. Aside from optimization methods, there are a number of different software solutions that can simulate gas flow through a pipeline or, on a larger scale, through an entire network using a transient model (and therefore also a steady-state model).

15.3.3 Challenges and outlook Most software solutions relating to gas transportation through pipelines simply involve a network simulation. The algorithm only accounts for discrete decisions (for example, switching a compressor on and off) to a limited degree, and may even assume them to be fixed inputs. For this reason, there is a limit to how much optimization is possible. Fraunhofer IIS is currently developing a solution to remove this limitation and offer resources to support decision-making for a wide range of issues in the context of gas network optimization. This tool will provide recommendations for discrete and continuous decisions, such as the most economical expansion paths for hydrogen pipelines and even controls for compressors. These decisions can be then validated and iteratively adjusted on the basis of existing simulation software, e.g., MYNTS-Gas. This enables more comprehensive, realistic handling of issues specific to gas pipelines.

15.4 Integration into process engineering methods Producing green hydrogen and synthesis gas through electrolysis is a particularly important part of process engineering methods for reducing greenhouse gas emissions. These processes can be used to bind carbon if CO2 separated from the air or exhaust gases is used as the carbon source. These are referred to as CCU (carbon capture and utilization) processes. If the process generates liquid products, it is referred to as a power-to-liquid approach. Taking CCU processes as an example,

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this chapter will outline the importance of process simulation in developing new methods that involve electrolysis, as well as the procedure for carrying this out. Dieterich et al. provide an overview of various power-to-liquid approaches [18]. Since these are, in principal, new production chains, it is logical to carry out a process engineering simulation before a decision is made regarding investment, so that the process can be evaluated in terms of process engineering and economics. A variety of software packages can be used for this purpose. The use of flowchart-based applications, in particular, has become widespread, with aspenOne® being the most commonly used. New tailored models still need to be created in addition to the currently available models, especially for electrolysis. The software provides options suitable for this purpose. Some tools and procedures developed at Fraunhofer IKTS as part of the lighthouse project “Electricity as a resource” are presented below for the purpose of illustration. These are used to simulate approaches for avoiding or harnessing the use of CO2 . In order to assess the process, target values are first defined for the calculation. Since there is a limited amount of electrical power available from renewable energy, these values include both the energetic efficiency en D

Pch;product Pel;input

C D

PC;product PC;input

and the carbon efficiency

when a carbon source is used (CO2 , in this case). In this example process, an electrolysis-based synthesis gas production process is combined with a Fischer-Tropsch synthesis process. Fig. 15.3 shows a simplified process flow diagram. In the first step of the process—the synthesis gas production—CO2 and water are used to produce a carbon monoxide (CO) and hydrogen (H2 ) mixture that is suitable for the synthesis process. The gas mixture is compressed, tempered and fed into the Fischer-Tropsch reactor. There, the gas mixture is converted to hydrocarbons of different chain lengths using an iron or cobalt catalyst. Waxy, liquid fractions of the product are separated from the product stream. The residual gas is made up of the unreacted synthesis gas and short-chain hydrocarbons. It is fed back into the synthesis gas production process, where it is recycled as a material or used to generate heat. There is also the possibility of using waste heat from the exothermic synthesis reaction in the process of generating the synthesis gas. This process is referred to as waste heat recovery (WHR).

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Fig. 15.3 Simplified flowchart of a Fischer-Tropsch-based power-to-liquid process

Three different process routes can be derived from the simplified flowchart above (Fig. 15.3). The main difference between them is the electrolysis process used:  Following the process described by König et al. [19], low-temperature polymer membrane water electrolysis (PEMEL) process operated under the pressure conditions required for a synthesis reaction is combined with a reverse watergas shift (RWGS) reaction that converts CO2 to CO and the residual gas.  In a process described by Cinti et al. [20], an atmospheric solid oxide electrolysis process (SOEL) is combined with an atmospheric RWGS reaction in order to convert CO2 and the residual gas.  In the single-step method described by Herz et al. [21], a solid oxide coelectrolysis process (Co-SOEL) with internal reforming is used to produce syngas. Aside from these different methods for producing the synthesis gas, another important feature is how the residual gas is used and what forms of process control are involved. Fig. 15.4 shows that all the different processes involve separating and burning a part of the residual gas in order to create thermal energy to reform the rest of the residual gas. In processes (a) and (b), the gas is reformed during the RWGS reaction; this reaction is supplied with thermal energy through combustion. In process (c), the residual gas is converted on the catalytically active electrode material, with thermal energy supplied by blasting the air-facing side of the stack with hot exhaust gas. The model is created by mapping the processes in a flowchart-based software solution. There are no ready-made flowchart blocks for the process stages in elec-

15.4 Integration into process engineering methods

a

b

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H2O

exhaust gas

air

exhaust gas

air

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rWGS syngas waste water

Fig. 15.4 Simplified flow diagrams of synthesis gas production based on (a) PEM electrolysis, (b) solid oxide electrolysis and (c) solid oxide co-electrolysis

trolysis or in Fischer-Tropsch synthesis, which is why a simplified diagram is used to show them instead. The sub-processes of solid oxide electrolysis, namely internal reforming, electrochemical conversion and methanation, are separated and represented by their own respective blocks. The electrochemical calculations are carried out in the background using a calculator block [21]. Empirical reaction kinetics can be used to model synthesis processes. However, there are no usable kinetics available for the example of Fischer-Tropsch synthesis. For this reason, a simplified representation has been established, based on specifications relating to conversion rate and product range [22]. As a consequence, the results are dependent on the database used. However, this is not to say that relative comparisons of methods are not possible. Different approaches can be compared in terms of their energy efficiency (Fig. 15.5), whereby the shaded areas represent an increase in efficiency due to the recovery of heat that is released through reagent water evaporation during exothermic synthesis. In the case of PEMEL processes, the reactant water must be supplied in liquid form, meaning that heat integration is not possible. Setting aside concerns about heat recovery, a PEMEL-based process is more energy-efficient than a H2 O-SOELbased process. Since both the electrolysis and the RWGS reaction are operated under the pressure conditions required for a synthesis reaction, only the CO2 reactant stream must be compressed, minimizing the energy required for compression. In the case of H2 O-SOEL, the electrolysis and RWGS reaction are operated at atmospheric pressure. As a result, compressing the synthesis gas requires a high amount of energy. On the other hand, there is high potential for heat integration, resulting in higher overall energy efficiency. When it comes to co-electrolysis, the rate of energy efficiency can be increased even further.

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η

0.5 0.4 0.3 0.2

ηC WHI ηen

0.1 0.0 PEMEL

H2O-SOEL

Co-SOEL

Fig. 15.5 Rates of energy efficiency and carbon efficiency found during analysis of electrolysis-based power-to-liquid processes

Since a portion of the residual gas is used to sustain endothermic reformation processes, there is a direct correlation between the efficiency of the reformation process and the level of carbon efficiency: If the reformation process is designed to be efficient, less energy is required. Less CO2 is released due to the lower material flow of combusted hydrocarbons. H2 O-SOEL has an advantage over the PEMEL here, as the hydrogen can be fed into the RWGS reaction at the stack temperature, and thus no energy is required to heat it up. For this reason, solid oxide electrolysis has a higher carbon efficiency. The further gain in carbon efficiency from co-electrolysis, much like the energy efficiency of the process, is based on the reduction in high-temperature process stages and, as a result, a minimization of heat losses. Hopefully, this brief example has illustrated the central role of process simulation in planning and designing electrolysis-based processes and shown how a reliable model can be an important tool for process design.

15.5 Optimized stack design

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15.5 Optimized stack design This brief overview outlines the range of possibilities offered by model-based approaches for supporting the design of electrolysis systems and for process intensification.

15.5.1

Model-based simulation approaches

Model-based simulation approaches are playing an increasingly significant role in the development of electrolyzer technology. New methods for digital analysis and optimization have the potential to increase cell and stack efficiency. This is made possible by innovatively combining modeling approaches from the fields of fluid dynamics, multiphysics and porous media with surrogate models and optimization methods. The various components of an electrolyzer all require their own separate approaches. We would like to briefly examine these below. Fraunhofer ITWM uses its own established software tools to help find solutions to individual issues, while also developing new, tailor-made solutions. Criteria relating to fluid dynamics are a decisive factor in designing the bipolar plate. These involve simulating a multiphysics problem that includes aspects of flow, thermodynamics and substance concentrations. Substance concentration is a significant target criterion: In PEM electrolysis, for example, the oxygen produced must be removed quickly enough to avoid a reduction in cell efficiency. Our tool CASHOCS [23], originally developed for general shape optimization tasks, is used to design bipolar plates. Designing flow dynamic stacks raises similar issues. It is important here to establish a uniform flow to all cells, without major losses in pressure. Within an electrolytic cell, there are porous microstructures. The precise nature of these microstructures has a major impact on the efficiency of the cell, although the exact relationship between them is highly complex. Simulation tools that have already been tried and tested in fuel cells [24] and battery cell research [25] are being used in the search for new materials and structures. The flow within the porous microstructures is simulated by special models to establish a connection to the target criteria. Virtual material design can be carried out on this basis to support the experimental investigations. In particular, this virtual approach provides a detailed look at the complex processes within the microstructures. It would not be possible to achieve this using only experiments. Commercial flow diagram simulators are typically used to create an overall view of the electrolysis system (Sect. 15.4). The fluid dynamics component mod-

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els discussed above provide a significantly higher level of detail than the simpler balance models used in flowsheet simulators. However, they involve a much higher level of effort to compute. One solution to this is to employ a multi-scale approach using surrogate models. This involves evaluating the complex model on the basis of parameter sets selected through a sophisticated process. This results in a surrogate model that contains the basic dynamics of the complex model. However, the surrogate model can be evaluated much more quickly. Next, the specially trained surrogate model can be integrated into a commercial flowchart simulator. Once there is an available flowchart model for an electrolysis plant, a system optimization process can be carried out. The optimizer has direct access to the flowchart model and can determine the optimal design parameters. This allows the system design and dimensioning of individual components to be optimized first. Once the system has been implemented, the optimum operating parameters can then be determined.

15.5.2

Bipolar plate design

Examples of methods for designing bipolar plates are presented in more detail below. PEM electrolysis is used as an example. In this process, water is supplied on the anode side via the bipolar plate, before being split inside the cell. The oxygen that results from the process must be removed on the anode side to prevent a drop in cell efficiency. For this reason, a bipolar plate must be evenly perfused and must not have any dead zones where the oxygen cannot escape at a quick enough rate. Our shape optimization tools help to design these bipolar plates to have an optimized flow. The optimized geometries are characterized by an even flow and more favorable concentration distribution. In general, drops in pressure across the cell can also be reduced through specialized design. Fig. 15.6 depicts one such design. The left-hand side of Fig. 15.6 shows a reference design with the inlet in the upper-left corner and the outlet in the lower-right corner. The different colors indicate the local flow velocity. In the lower-left and upper-right corners of the reference bipolar plate, there are dead zones with insufficient flow. These dead zones can be a limiting factor for cell efficiency. The right-hand side of the graphic shows an optimized bipolar plate. New methods [26] from the mathematical field of shape optimization are used here. Fraunhofer ITWM’s algorithm manipulates the reference geometry in a sophisticated way until the target criterion of an even flow is fulfilled as best as possible. The optimized bipolar plate is then free of dead zones, and the flow through all areas is significantly improved. The new design can then be easily implemented through additive manufacturing processes.

15.6 Scaling and flexibilization through digital transformation

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Fig. 15.6 Two bipolar plates before and after shape optimization. The blue areas are dead zones with insufficient flow

15.6 Scaling and flexibilization through digital transformation Specific research on the topic of electrolyzer and fuel cell technology is a new field of activity. A high number of new solutions are anticipated, which will enable high-rate, cost-optimized production and allow for the further development of electrolyzers and fuel cells. At the same time, the market is highly agile. Although significant growth rates are predicted, there are still no sufficiently detailed technical solutions for electrolyzer production. It is therefore necessary to build an agile, service-oriented digital system that is not locked into any particular technology and can be scaled for different quantities. To achieve this, a platform was designed as part of the National Action Plan for Fuel Cell Production and in the joint project FRHY: Reference Factory for Electrolyzer Mass Production to serve as a focal point connecting the two. The digital reference architecture is an essential component of this, as it combines virtual images of the various production steps involved in stack manufacturing and effectively establishes links between them. Aside from this creation of synergies, it also ensures a high level of responsiveness when mapping and implementing new technological solutions. Virtual mapping serves as the basis for developing the digital reference architecture. This mapping process must incorporate certain specifications to allow for a collective, overarching analysis. It must also offer a high degree of flexibility so that the interacting locations and partners in the value creation network can implement the stack manufacturing process in a way that is both dynamic and interoperable.

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Fig. 15.7 Asset administration shell and submodels [27, p. 5]

The process of virtually mapping a manufacturing process or product results in a digital twin in production. The idea here is that every product that will be manufactured will have a digital twin that can be continuously monitored and adjusted from the initial design stage to the production line. To begin with, it is necessary to equip all machines on a production line with sensors that can send detailed information on the current production status to a backend in real time. There, the data is merged and linked. It is possible to create simulation models that use this input data to map the actual process in a simplified manner, while at the same time using physical models to predict the properties of the production process and of the resulting product or semi-finished product. This makes it possible to evaluate the quality of the manufacturing process and predict the quality of the end product. Conversely, it is also possible to carry out parameter variations on the digital twin, allowing for the real-life process to be evaluated without interrupting production or consuming valuable materials. These new possibilities for optimization not only offer flexible quality-assurance measures, but also ensure that the material used is tracked from the semi-finished product stage to the finished product. On top of that, they significantly contribute toward scaling production lines. Digitally mapping the process steps and resources in the form of supplies and infrastructure not only allows data-driven technologies to be used more effectively, but also aids interoperability in general. Common standards must be implemented and expanding upon for this purpose. The asset administration shell developed as part of Industry 4.0 (Fig. 15.7; [27]), which is currently in the process of being standardized and further developed, involves the implementation of a digital twin.

15.6 Scaling and flexibilization through digital transformation

409

For example, each asset can be assigned its own asset administration shell, which, together with the asset, forms an Industry 4.0 component in one unit. Asset administration shells contain submodels that represent functional, domain-specific information, enabling a consistent language for description and exchange based on standardized dictionaries such as the ECLASS standard or the IEC 61360 Common Data Dictionary (CDD). Asset administration shells can be passively stored in information systems or actively implemented as parts of intelligent systems. The latter directly provide their submodels and the information contained within them and are able to communicate with other Industry 4.0 components via the API interface. A standard-compliant asset administration shell infrastructure is currently in its development and pilot phase. Developing application-specific and cross-application submodels is the ideal approach for efficiently implementing networked production and its associated digital twins. This allows plannable digital production modules to be provided, forming the basis for a cost-effective production process. The digital reference architecture is the virtual counterpart to the real-life production of electrolyzer and fuel cell stacks. It forms the framework for the virtual images of the decentralized production modules, which each have different functionalities within the reference architecture. When viewed as a single element, the digital twins provide the information configured via the standard (e.g., technology, costs) for the respective production module. The digital reference architecture thus allows individual production modules, namely machines, systems and test equipment, to be evaluated and planned. When different individual modules are linked together, entire production lines are created, which makes it possible to conduct studies on a much larger scale. This allows individual technologies to be compared in terms of quality and scalability. Production variants can also be simulated, thus enabling the comparison and evaluation of possible production strategies for parallelization, automation and integrative, continuous production processes. As a result, it is not only possible to obtain a validated projection of investment costs, but also such a projection for return on investment relative to the planned production volume. The reference architecture also allows production lines to be connected to form a complete value chain. This enables an assessment of both the vertical integration and need for suppliers. In addition, it allows for aspects of factory planning to be evaluated, in turn enabling the development of a holistic energy model that covers all energy sources as a prerequisite for resource-efficient production.

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15.7 Simulation-based design of hydrogen infrastructures On account of the specific material properties of hydrogen, both developing safe technologies and assessing the safety risk of hydrogen applications on a projectspecific basis are prominent subjects in research and industry. In particular, the application of hydrogen technologies in urban environments requires taking completely new scenarios into account, simulation models therefore play an important role here as a predictive tool. The functional safety of systems as complex as future hydrogen infrastructures is very important. Functional safety deals with minimizing the probability of dangerous errors and can be achieved using system simulations. The scope of functional safety ranges from analyzing random errors through digital fault tree analysis (FTA) to detecting systematic errors through the automated testing of digital twins. Functional safety methods cannot completely eliminate error and accident scenarios. For this reason, conducting risk assessments in the event of damage is an important part of safety considerations. As a flammable gas, hydrogen can form explosive atmospheres if released into the ambient air. The principle of a particular process may require the release of hydrogen (for example, the boil-off stage of cryogenic storage); otherwise, a release can occur due to damage to pipes, fittings and storage containers. With the help of three-dimensional, transient dispersion simulations, a wide variety of release scenarios can be evaluated, and adequate protective measures can be developed to prevent the formation of potentially explosive atmospheres. One example is the Fraunhofer ICT model for hydrogen dispersion in enclosed spaces, which was developed on the basis of the Fire Dynamics Simulator (FDS). The model allows the concentration of hydrogen to be determined with spatial and temporal resolution for a wide variety of release scenarios. The model requires leakage parameters to be provided as input data, such as the duration of leakage, the release rate and the temperature of the medium, as well as external conditions such as the geometry of the space and technical ventilation measures. Detailed results from this model’s simulations can be used to develop structural and technical protective measures and to estimate their effectiveness. The model also allows for the implementation of error controls. This ensures that, for example, it is possible to simulate systems that combine hydrogen sensors and technical ventilation measures. This makes it possible to specify the required dimensioning of ventilation and to establish appropriate alarm thresholds for gas warning systems. The model is suitable for designing the safety features of new systems and existing objects. Fig. 15.8 shows the application of the model in an underground parking garage with technical ventilation systems, which have previously been used pri-

15.7

Simulation-based design of hydrogen infrastructures

411

Fig. 15.8 Simulation of a hydrogen leak from an FCEV in an underground parking garage. Blue: Volumetric representation of the hydrogen concentration. Red: Flow field, mainly influenced by technical ventilation systems

marily for smoke extraction during outbreaks of fire. The simulation can be used to examine the extent to which this smoke and heat extraction system is suitable for preventing dangerous explosive atmospheres when used in conjunction with the appropriate hydrogen sensors. The model was specially designed for application in atmospheric conditions where small pressure differences and low Mach numbers (< 0.3 Ma) are expected. While this limits the area of application to the corresponding release scenarios, these presumptions work to significantly reduce the simulation time. This enables detailed observations in large construction projects, such as special structures, industrial buildings and entire housing developments. If ignition of the hydrogen cannot be ruled out, it is also possible to analyze the mechanical and thermal effects on the environment through a simulation. Simulating fire and explosion events requires a combination of reaction kinetic and fluid dynamic models, which considerably increases the level of complexity compared to simple dispersion simulations. This is why simplifying assumptions are often included in such models, which keep the effort involved in the calculation at an acceptable level [28]. The loss of precision resulting from these simplifications must be taken into account in safety considerations by ensuring an increased safety factor. Models intended to be used to assess safety must be thoroughly verified and validated. That is why a guideline for evaluating simulation models in the field

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of hydrogen safety was developed as part of the SUSANA project. The project provides a database for verification, as well as a collection of relevant literature with examples of validation [29].

References 1. Oliver P., Bourasseau C., Bouamama P.B. (2017): Low-temperature electrolysis system modelling: A review. Renewable and Sustainable Energy Reviews 78: 280–300 2. Wietschel M., Zheng L., Arens M. et al. (2021): Metastudie Wasserstoff—Auswertung von Energiesystemstudien (Hydrogen metastudy—Evaluation of energy system studies.). https://www.ise.fraunhofer.de/de/veroeffentlichungen/studien/metastudiewasserstoff.html, last viewed on December 14, 2021 3. German Energy Agency (2018): dena Study, Integrated Energy Transition: Impulses to shape the energy system up to 2050. https://www.dena.de/ newsroom/publikationsdetailansicht/pub/dena-leitstudie-integrierte-energiewendeergebnisbericht/ 4. Robinius M. et al. (2020): Wege für die Energiewende: Kosteneffiziente und klimagerechte Transformationsstrategien für das deutsche Energiesystem bis zum Jahr 2050 (Pathways for the energy transition: Cost-efficient and climate-friendly transformation strategies for the German energy system by 2050). Schriften des Forschungszentrums Jülich (Forschungzentrum Jülich publications), Energy & Environment series, volume 499. ISBN 978-3-95806-483-6 5. Fuel Cells and Hydrogen Joint Undertaking: Hydrogen Roadmap Europe. A sustainable pathway for the European Energy Transition. https://www.fch.europa.eu/sites/ default/files/Hydrogen%20Roadmap%20Europe_Report.pdf, last viewed on December 14, 2021 6. Fleiter T., Herbst A., Rehfeldt M., Arens M. (2019): Industrial Innovation. Pathways to deep decarbonisation of Industry. Part 2: Scenario analysis and pathways to deep decarbonisation. ICF Consulting Services Ltd. and Fraunhofer ISI 7. Duscha V., Wachsmuth J., Eckstein J., Pfluger B. (2019): GHG-neutral EU2050—A scenario of an EU with net-zero greenhouse gas emissions and its implications. German Environment Agency (ed.), Climate Change 40. https://www.umweltbundesamt.de/ publikationen/ghg-neutral-eu2050, last viewed on December 14, 2021 8. Lux B., Poslowsky S., Pfluger B. (2019): The economics of possible CO2 utilization pathways in a highly decarbonized European energy system. IEEE/PES/EEM September 18–20, 2019, Ljubljana. https://doi.org/10.1109/EEM.2019.8916453 9. Bernath C., Deac G., Sensfuß F. (2019): Modellbasierte Analyse der Auswirkung von Sektorkopplung auf die Marktwerte erneuerbarer Energien (Model-based analysis of the impact of sector coupling on the market values of renewable energies). 11. Internationale Energiewirtschaftstagung “Freiheit, Gleichheit, Demokratie: Segen oder Chaos für Energiemärkte?” (International energy industry conference “Freedom, equality, democracy: a blessing or chaos for energy markets?”) February 13–15, 2019, Vienna, Austria

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26. Blauth S., Leithäuser C., Pinnau R. (2020): Shape sensitivity analysis for a microchannel cooling system. Journal of Mathematical Analysis and Application 492 (2): 124476 27. Bedenbender H., Billmann M., Epple U. et al. (2016): Beispiele zur Verwaltungsschale der Industrie 4.0-Komponente—Basisteil (Examples of the asset administration shell of Industry 4.0 components—Fundamentals). Zentralverband Elektrotechnik- und Elektronikindustrie e. V. (Central association of electrical engineering and the electronics industry), Frankfurt am Main. 28. Mulenga L. (2018): Modeling Of Detonations Using Scenarios With Hydrogen As A Fuel. Dissertation, University of North Dakota. https://commons.und.edu/theses/2294 29. Baraldi D., Melideo D., Kotchourko A. et al. (2017): Development of a model evaluation protocol for CFD analysis of hydrogen safety issues the SUSANA project. https://doi. org/10.1016/j.ijhydene.2016.05.212

Hydrogen technologies in the energy system: the international perspective

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Christopher Hebling  Kira Schlüter  Ombeni Ranzmeyer Fraunhofer Institute for Solar Energy Systems ISE Norman Gerhardt  Maximilian Pfennig Fraunhofer Institute for Energy Economics and Energy System Technology IEE Martin Wietschel Fraunhofer Institute for Systems and Innovation Research ISI Natalia Pieton  Kristin Kschammer  Mario Ragwitz Fraunhofer Research Institution for Energy Infrastructures and Geothermal Systems IEG Abstract

Across the world, it’s widely accepted that in order to conserve resources and protect the climate, we must phase out the use of fossil fuels entirely by the middle of the century. Furthermore, a large portion of our production processes must be converted in pursuit of a circular economy. The key elements in this process will be hydrogen produced through carbon-neutral processes, the longer-chain molecules that are synthetically produced in this process, and material energy carriers and chemical raw materials in a large number of mobility and industry-related products. Since the effects of using up resources and producing CO2 are fundamentally a matter of international concern, the transformation process can only take place if there is international collaboration based on a common set of defined rules. This applies to the research on and development of the relevant technologies, as well as their application and promotion. The chapter will provide an overview of the agreements, initiatives, goals and successes associated with this international collaboration. © Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_16

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16.1 The importance of green hydrogen In order to conserve resources and protect the climate, we must phase out the use of fossil fuels entirely by the middle of the century. Furthermore, a large portion of our production processes must be converted to circular economy models. This will necessitate a radical transformation of our energy and industry systems in the coming decades. In this context, climate-neutral hydrogen and longer-chain molecules, energy carrier materials and chemical raw materials that are synthesized based on that hydrogen will become vital constituents in a large number of products in the mobility and industry sectors. A combination of climate-neutral energy supply and electro- and thermochemical processes will give rise to a global industry worth billions of euros. The foundation of this industry will be the production of hydrogen via water electrolysis powered by renewable electricity. This green hydrogen can be put further use in various different ways—it can be reconverted into electricity in fuel cells or gas turbines for mobile and stationary applications, used as a reducing agent in industrial processes, or converted into different molecules in combination with (non-fossil) carbon and nitrogen. At present, the synthesis processes described here are undergoing a global transition toward large-scale, industrial use. In the last few years especially, the importance of hydrogen technologies in the transformation of the global energy system has been recognized on a massive scale and many domestic economies across the globe are rapidly developing in the direction of a hydrogen economy. There is a basic distinction to be made between regions here: some areas have considerable potential for renewable energy generation and aim to use hydrogen-based energy carriers to participate in global renewable energy trade (this includes net exporters such as Australia, Chile, the MENA region, South Africa, Norway and the Iberian Peninsula), while other economies are dependent on sustainable energy carrier imports to establish climate-neutral energy systems in their own countries (this includes net importers such as Japan, Korea, China and Central Europe). However, in many cases, the latter group have also identified major economic opportunities for exporting technological equipment and know-how. In its Hydrogen Insights Report 2021, the Hydrogen Council summarized the current situation in terms of the following statistics:  Over 80 nations, representing the vast majority of global gross domestic product, have made a commitment to achieve climate neutrality by 2050 or 2060.  To date, 35 countries have adopted national hydrogen strategies, road maps or hydrogen R&D programs.

16.2

An international hydrogen economy

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 In their strategy papers, these governments have announced plans for funding or set out budgets for hydrogen programs amounting to around 100 billion US dollars in total by 2030 (C 7 C 2 billion in Germany).  Some 228 large-scale projects (of which 85 percent are based in Europe, Asia and Australia) are in development, comprising installation of a total electrolysis capacity of 17 GW as well as subsequent expansion of infrastructure or use of hydrogen in industry and mobility applications.  The public and private sectors have announced plans for investments in the areas of hydrogen production, transportation and distribution, as well as the use of hydrogen in a variety of final applications totaling 350 billion US dollars by 2030.  Based on announcements in the transportation sector, it is expected that by 2030, 5 million fuel cell vehicles will be on the roads and 10,000 hydrogen refueling stations will be established.  To date, 24 countries have announced their intention to phase out combustion engine propulsion technology completely in the 2030s.

16.2 An international hydrogen economy 16.2.1

The Green Deal

As 2019 drew to a close, the European Commission revealed its new scheme for achieving its goal of becoming emission-free. This European Green Deal consists of a comprehensive set of measures and regulations that has since taken center stage in European climate policy and is now pointing the way ahead for EU member states as they strive to achieve climate neutrality. One core element of the Green Deal is the intensification of CO2 reduction targets. The original target was a 40 percent reduction rate in comparison to 1990—the Green Deal increased this to 55 percent. To make this target a reality, the European Commission introduced the Fit for 55 Package in summer 2021, a set of proposals designed to “deliver the transformational change needed across [the European] economy, society and industry” [1]. To this end, the Commission is formulating a policy mix consisting of eight proposals aimed at expanding existing legislation and five new initiatives for various policy areas and economic sectors. These not only cover pricing, but also objectives, rules and support measures. Even before the Fit for 55 package was published, the Renewable Energy Directive (RED II) played a key role in promoting renewable energy. Now, as part of

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the package, the directive is set to undergo further revisions, which will ultimately align with other adjustments that will be implemented in the directives on the European emissions trading system (EU-ETS), energy taxation (ETD) and energy efficiency (EED), fuel quality (FQD), energy performance in buildings (EPBD), ecodesign, and alternative fuels infrastructure (DAFI) [2]. When the Fit for 55 package was in production, the European hydrogen umbrella organization Hydrogen Europe published a position paper containing extensive recommendations and highlighting the basic advantages of using hydrogen [3]. As it happens, the adjustments to the directives do include clear policies and recommendations for action in relation to hydrogen. For example, the Directive on the deployment of alternative fuels infrastructure (DAFI) contains provisions stipulating the minimum quantity of hydrogen refueling stations that must be publicly accessible for heavy-duty and light-duty vehicles and describing how a userfriendly hydrogen refueling infrastructure may be established [4]. Minimum standards would have to be set in terms of payment options, price transparency and contractual choices in this context. As a practical expression of these targets, the directive specifies that a maximum distance of 150 km between individual hydrogen refueling stations must be achieved by the end of 2030. Meanwhile, publicly accessible refueling stations for liquid hydrogen are set to be available every 450 km and it is expected that, in general, every urban center will have a refueling station for hydrogen by the end of 2030. Hydrogen is also an important factor in initiatives such as ReFuelEU Aviation [5] and FuelEU Maritime [6], which promote the use of sustainable fuels (both directly and in blended forms) in shipping and aviation. Although the original version of the Energy Tax Directive [7] did not provide adequate support for the implementation of alternative fuels, such as renewable hydrogen or synthetic fuels, it is now undergoing adjustments that will see advanced biomass fuels as well as green hydrogen taxed at the lowest rate. The subject of hydrogen is being addressed through a variety of measures across the board, including amendments to the other directives and initiatives mentioned above. As such, it is evident that hydrogen has progressed from the low-priority or downstream role it played in the past to become a key energy system component. The EU member states are required to incorporate the directives into their national legislation. The European Union aims to take a leading role in the global fight against climate change. However, the official announcement regarding the Fit for 55 initiative emphatically states that the EU’s efforts alone will not be enough to achieve an effective reduction in greenhouse gas emissions [1]. Consequently, it argues for extensive international collaboration activities that go beyond the 27 member states.

16.3

Hydrogen strategies and road maps

16.2.2

419

The Paris Agreement

In 2015, all 195 parties to the United Nations Framework Convention on Climate Change adopted the Paris Agreement, thereby committing themselves to taking collective action against global warming. The Agreement established a number of targets, such as limiting the rise in mean global temperature when compared to preindustrial levels to well below 2 °C, fostering climate resilience and low-emission development, and providing the requisite funding for climate conservation. The parties to the Agreement have formulated individual, long-term strategies in order to help achieve these goals. The resulting national climate strategies outline comprehensive programs of action and reforms aimed at implementing the climate goals.

16.3 Hydrogen strategies and road maps Nearly all EU member states have outlined specific hydrogen-related targets in their national energy and climate plans (NECPs) [8]. Some 20 nations are currently working on or have already developed hydrogen strategies [9]. Meanwhile, other countries are conducting status-quo analyses and opportunity and risk assessments. For example, Finland has conducted a conventional SWOT analysis to evaluate the strengths, weaknesses, opportunities and threats resulting from the production and use of low-carbon hydrogen [10].

16.3.1 Strategy developments in chronological order Japan became the first country to develop a hydrogen strategy when it published a national strategy paper in December 2017 [11]. France followed suit in June 2018 by announcing its own strategy, followed by Russia in 2019 [12, 13]. In 2020, the Netherlands, Germany, Norway, the United States, Spain, Portugal, Chile, Canada, and the European Union all published strategies of their own [14–22]. Meanwhile, Finland released its risk and opportunity assessment, and Italy produced a strategy paper containing some preliminary guidelines. Since then, more than 35 national hydrogen strategies, R&D programs and other road map documents outlining countries’ aims as regards the implementation of hydrogen technologies in their national economies have been published. Although all these documents do refer to climate protection as a goal, they also mention a wide range of other mo-

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tivating factors such as the following: implementing industry policy measures in order to strengthen national value chains; reducing local emissions in urban centers (whereby protecting the health of local residents forms a non-negligible motivating factor); leveraging renewable energy sources in order to create an energy export industry; achieving energy self-sufficiency; and establishing a more flexible energy system. Most countries have established national bodies that will serve as intermediaries and advisors for the fields of politics, industry and research, in order to implement the relevant national hydrogen strategy. Examples of these bodies include the Hydrogen Working Group in Australia, the National Hydrogen Council in Germany, the Consejo Nacional des Hidrógeno Verde in Chile, the Strategic Steering Committee in Canada and the European Clean Hydrogen Alliance. Their function is generally to provide advice and make decisions on policies and possible financing measures, which often go beyond the regulations outlined in the relevant strategy.

16.3.2 Strategy papers by non-government institutions Governments are not the only entities producing strategy papers—many industrial and scientific companies have also formulated region-specific road maps and strategies. For example, the Commonwealth Scientific and Industrial Research Organisation (CSIRO) in Australia presided over the production of a road map for Australia back in 2018 [23]. Likewise, in 2019, Fraunhofer ISE and ISI coordinated a project to produce a hydrogen road map for Germany [24], while in 2019 and 2020 respectively, the Desertec Industrial Initiative (Dii) published a manifesto for North Africa, and an opportunity and risk assessment on hydrogen exports from the MENA region [25, 26].

16.4 The driving forces behind the hydrogen economy The various strategy papers differ dramatically in their content and focus areas. Some of the papers include comprehensive status-quo analyses, while others set out specific goals for their particular country. In spite of this, across almost all of the papers, it is possible to detect common driving forces that motivate efforts to establish a global hydrogen economy, namely environmental, economic and energy-related concerns.

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16.4.1 Environmental concerns Reducing CO2 emissions seems to be the primary focus area for almost all the countries involved; however, Australia, the Netherlands, the United States and Canada also refer to improving air quality as another important environmental goal.

16.4.2

Economic concerns—exports, industry, prosperity

Many countries and regions are striving to establish an export industry for a variety of reasons. For example, the MENA (Middle East, North Africa) region, Australia, Norway, Canada, Spain, Portugal, Chile and the United States are all motivated by their outstanding resources in terms of solar and wind power potential, while the Netherlands is driven by the potentially vital role that the port of Rotterdam could play in supplying Europe with energy. Furthermore, nations that have historically had strong, export-focused industry sectors (including Germany, France, Russia, the United States, Chile, Canada and Norway) have identified the enormous industry potential offered by hydrogen technologies. All these countries have high hopes that hydrogen technologies may offer them opportunities to improve their national prosperity. For example, Chile believes it could result in the creation of 100,000 new jobs, while Australia estimates that there could be an annual increase in its national gross domestic product amounting to around 11 billion US dollars.

16.4.3 Energy-related concerns In the context of energy, security of supply is an important goal for all countries. For example, Spain has highlighted the fact that hydrogen could make it possible to guarantee a secure energy supply even in isolated areas such as on its islands. There are few countries striving for independence from imports or energy selfsufficiency. On the contrary, a number of countries, including Germany and the entire European Union, have discussed the necessity of hydrogen imports and the corresponding international supply chains and global partnerships. These environmental, economic and energy-related concerns can be viewed as complementary objectives. The strategies outlined various routes to implementing these goals, including detailed strategies for developing financing models and regulatory frameworks for developing standards and the associated certification processes. A number of strategies also laid down intermediate targets, some of

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which were specific to certain sectors. The strategies concentrate primarily on the industry sector, refineries, the steel and chemical industries, and the transportation sector. Nations that focus heavily on industry, such as Chile, Australia and South Africa, which all have strong mining sectors, and the United States, which has an important iron and steel production industry, see these sectors as important application areas for hydrogen. Other nations are directing their efforts in the field of hydrogen technologies toward the transportation sector (road and rail transportation, shipping and aviation). Many countries are focusing on using hydrogen in areas where electrification presents difficulties; however, Asian countries are concentrating on using it in passenger cars [9]. The hydrogen infrastructure for fuel-cell-powered vehicles encompasses around 150 refueling stations across Europe; nearly 100 of these are located in Germany, 10 are located in the United Kingdom, and others are scattered across various countries, such as Switzerland. Overall, around 50 more refueling stations are in the planning or construction stages at present [27].

16.5 International trade and partnerships 16.5.1

Europe—Middle East and North Africa (MENA)

The EU’s hydrogen strategy expresses a clear need for hydrogen imports. Given the rise of promising resource opportunities in the Middle East and North Africa, the MENA region is aware that it has an opportunity to go beyond simply contributing to meeting European demand, and actually establish an international partnership. In this context, the Dii initiative’s green hydrogen strategy for the MENA region has identified Germany and France in particular as potential partners, as these countries have allocated funding amounting to 16 billion euros for international partnerships in their strategies. A link has already been established between Morocco and Spain thanks to the Maghreb-Europe Gas Pipeline, which represents a possible means of supplying green hydrogen. In addition, the Tanger-Med port has direct sea links to 186 ports in 74 countries, which would facilitate intercontinental hydrogen trade. The ports of Jorf Lasfar and Agadir could also potentially serve the hydrogen and ammonia trade. The country’s green hydrogen strategy has indicated that the transportation network connecting its highly productive southern region to its export-focused northern region must be expanded [28].

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Importing green hydrogen and synthesis products

16.5.2

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Germany—West Africa

In the H2 Atlas Africa project, the German Federal Ministry of Education and Research is collaborating with Sub-Saharan countries to research the potential for producing hydrogen and exporting it to Germany. This involved environmental, technical and socio-economic investigations of the individual countries, whereby particular attention was paid to the question of water stress in the context of green hydrogen production. Based on the results of these investigations, the countries could potentially produce 165,000 TWh of green hydrogen per year, with production costs of between 2 and 4 EUR/kg [29]. The geographic data on West Africa’s hydrogen supply has been turned into an atlas, which can be used to make investment decisions regarding the location of pilot plants based on hot spots. The pilot plants will be designed in the next project phase. Countries in the south of Africa will also be investigated in later project phases. To lay the foundations for this intercontinental collaborative initiative, RWTH Aachen University, Forschungszentrum Jülich and the West African Science Service Centre on Climate Change and Adapted Land Use (WASCAL) have created a master’s program for green hydrogen technologies, with the aim of training the scientific specialists that will be needed for the project and unlocking the hydrogen production potential of West Africa [30]. The program was launched in 2021 and 180 students are currently enrolled in it.

16.5.3 Australia—Japan/Germany Australia is also turning its attention to maritime hydrogen transportation and is exporting liquid hydrogen to Japan as part of a four-year pilot project (Hydrogen Energy Supply Chain—HESC). The goal, according to the Australian hydrogen strategy, is for the supply chain running from Victoria to Japan to commence commercial operations by 2030 [31]. Australian and German project participants are currently working on methods of exporting hydrogen from Australia to Germany as part of the HySupply project [32].

16.6 Importing green hydrogen and synthesis products: external conditions and design issues In recent years, a number of studies have been conducted on possible supplier countries’ potential for producing green hydrogen, often with a focus on (North) Africa. The primary component of these studies is generally a technical and eco-

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nomic evaluation focusing on the production and transportation of hydrogen and its synthesis products. However, when it comes to the issue of importing hydrogen and its synthesis products, it is necessary to go beyond the technical and economic issues that have been considered thus far and examine the topic from all possible perspectives. These additional perspectives are addressed below1 .

16.6.1 The market for imports Based on the information currently available, the market for hydrogen imports will reach between 100 billion and 700 billion euros per year in the long term. This range varies depending on the application areas that hydrogen and the related energy carriers can break into. This will present major market opportunities for the German industry sector, but it will also create new import dependencies and risks.

16.6.2

Renewable energy potential and imports

It is very unlikely that Germany and the EU’s renewable energy potential will be enough to meet demand cost-effectively when it is evaluated in terms of availability, economic viability and public support. Imports of green hydrogen and its synthesis products are viewed as a necessary step to facilitate the achievement of the policy goals that have been established. Extensive technical and economic analyses have already been conducted as regards the potential importing of green hydrogen and synthesis products from regions that have the necessary geographic and climate conditions, and they have established that such imports would be feasible. However, it must be noted that establishing the required production and transportation capacity would require a great deal of time and the investment of large sums of capital. The risks associated with imports can be reduced by establishing long-term partnerships with hydrogen-producing countries that have an adequate degree of stability as regards their democratic and political systems and economies.

1 These issues are addressed in detail in Wietschel, M. et al. (2020): Opportunities and challenges when importing green hydrogen and synthesis products; Policy brief by the Fraunhofer Institute for Systems and Innovation Research ISI.

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16.6.3 Sustainability Constructing facilities for renewable electricity generation, electrolyzers for hydrogen production, and synthesis plants requires resources such as sites for building on, water, energy, and CO2 . This is also associated with certain environmental consequences. Many countries that could potentially produce hydrogen still use fossil sources in their energy generation. As such, it is important to develop and apply criteria for sustainability at an international level as much as possible, while also taking care to ensure that these countries can also achieve their own energy and climate policy goals. This means that, in order to avoid conflicts between targets and resources at a national level, the countries’ hydrogen strategies must be closely integrated into their national energy strategies. It is also necessary to coordinate intensively with industrial and political bodies.

16.6.4 Market mechanisms and pricing Investors will only provide sufficient sums of capital at affordable rates if there is stable, long-term, secure demand for hydrogen and if country-specific risks are addressed by means of bilateral and multilateral agreements. Furthermore, because their investment risks are generally higher, private investors will set higher interest rates for their capital, which can make imports more expensive. Incentive systems are needed in order to create market conditions for hydrogen production and transportation that will attract exporting countries; however, these systems have yet to be established or are only just being set up. Possible incentives include tools for encouraging investments, initiatives aimed at creating secure hydrogen demand levels (e.g. quotas) and instruments that will help offset the higher costs (e.g., feed-in tariffs or contracts for differences). These must account for the abovementioned investor requirements. The overlapping issues of investors, expected interest rates and incentive systems give rise to the question as to how much hydrogen and synthesis imports will ultimately cost on an international market. It is very likely that existing analyses have significantly underestimated future market pricing because they are usually based on average manufacturing costs only, and do not include other important pricing components. To produce a realistic estimate, it is first necessary to compare the future global potential demand for hydrogen and synthesis products with supply.

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16.6.5 Governance In order to allow for the environmental impact of a hydrogen economy and its low efficiency rates from production to use, it must be integrated into governance structures for energy system transformation based on a hierarchical ranking system. This includes four levels:  Minimizing demand by focusing on energy efficiency first and foremost (“energy efficiency first” principle)  Treating the decarbonization of the electricity sector as a matter of primary importance  Giving priority to the use of alternative renewable energy sources that provide similar services but have a lower environmental impact, such as the direct electrical use of sustainable biomass, biofuels, biogas, while taking into account their limited availability  Using hydrogen and its synthesis products when the potential of the first three levels has been exhausted (to a reasonable extent) In the energy system transformation, this four-step system, which is essentially an extension of the “energy efficiency first” principle, must be implemented in both the governance structures of the countries where demand for hydrogen and synthesis products exists and in the structures of the countries that produce them.

16.6.6 International collaboration The countries of the global South that could potentially produce hydrogen are faced with a number of complex social challenges, including the consequences of climate change; however, it is possible to address these challenges by integrating import strategies into international collaboration activities in a well-organized way. Achieving this will require concrete trust-building measures, so that countries that produce and export hydrogen are not left behind internationally in terms of technological and scientific knowledge in the long term.

16.6.7 Local expertise It is necessary to identify local sources of knowledge and areas of expertise that can address the overlap between social and geographical and infrastructural issues. For example, support could be provided for local research institutions to help them

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Global production potential for green hydrogen and synthetic fuels

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consolidate their role as intermediaries between politics and society. However, such support must be provided in coordination with existing energy partnerships, NGOs, and international stakeholders. Through building capacity and integrating the necessary infrastructure neatly into the relevant regional, social and economic context, it is possible to create favorable conditions for the required multilateral reliability, local energy supply and market attractiveness. In addition to promoting the global energy transition, other key motivating factors behind the establishment of an interconnected global hydrogen economy include job creation and the expansion of local value creation in the hydrogen-producing countries. This means that targeted strategies must be implemented in order to develop competitive industry and service sectors along the entire value chain.

16.6.8 Technological sovereignty No comprehensive assessments of technological sovereignty in the field of hydrogen have been conducted as yet. However, some initial evaluations have indicated that from a German and European perspective, the reliability of countries that export green hydrogen is more likely to pose a threat to technological sovereignty than any issues regarding access to existing technologies. To draw reliable conclusions on this topic, more up-to-date analyses that cover a wider range of technologies must be conducted. At the same time, it is becoming apparent that if we are to import green hydrogen, we must expand the concept of technological sovereignty to include developing countries’ perspectives. This is because many of the countries that could export green hydrogen are dependent on other nations for technological knowledge and manufacturing. The conclusion that must be drawn here is that we do not have an adequate understanding of the complexities involved in importing green hydrogen, which has resulted in a tendency to underestimate the challenges this presents and the problems that will need to be solved in the future to a certain extent. Much more research is urgently needed here.

16.7 Global production potential for green hydrogen and synthetic fuels As with many other European countries, Germany will have to rely on imports to cover a large proportion of its demand for green hydrogen and synthetic fuels. A global power-to-X atlas compiled by Fraunhofer IEE contains some answers to

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the question of where these energy carriers could come from.2 This atlas, which is focused on non-European locations, applied strict environmental sustainability criteria when evaluating possible sites. It provides information on hydrogen production potential, but does not take into account the countries’ own expected demand for power-to-X (PtX). For information on potential hydrogen production at European offshore facilities that are not connected to the electricity grid and the advantages that hydrogen production would offer within Germany (subject to bottlenecks in the electricity transmission grid), see Chap. 4.

16.7.1

Factors affecting analyses of potential

Evaluations of technical and economic PtX potential are based on comprehensive analyses of such factors as the availability of land, weather conditions, peripheral, storage and transportation costs, and variations in system design. The socioeconomic conditions of the individual regions must also be taken into account—these conditions are analyzed on the basis of 70 indicators, suggested by sources such as the World Bank and touching on issues such as the level of political stability in the region and how secure investments in a particular location might be. The PtX Atlas only includes regions where it is possible to produce the energy carriers in a sustainable way. In concrete terms, this means that any sites where PtX production could impinge on nature conservation have been excluded. The same applies to inland regions where conducting electrolysis could lead to water stress. Locations that could be used for food production have also been excluded, particularly when it comes to ground-mounted solar plants. Fig. 16.1 shows where the regions identified as potential PtX producers are located. All the calculations are based on the assumption that direct air capture (DAC) can be used to obtain the carbon dioxide needed to produce synthetic fuels. It is also assumed that these sites will operate in island mode, i.e., that the electrolyzers will not feed into the public electrical grid.

2

The PtX atlas was produced as part of the DeVKopSys project on decarbonizing transportation through connections with the energy system, which was funded by the German Federal Ministry for the Environment, Nature Conservation, Nuclear Safety and Consumer Protection. For more information, including project results, see the project website (https://devkopsys.de/) or access the atlas directly at: https://maps.iee.fraunhofer.de/ptxatlas/.

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Fig. 16.1 Global overview of potential sites for PtX production, taken from the Fraunhofer IEE’s PtX atlas. (Fraunhofer IEE, map background: ©Esri HERE, Garmin)

16.7.2

Key findings

Fig. 16.2 shows the percentage distribution of global PtX production potential by continent and total area in the priority regions. As electrolysis requires fresh water, bodies of water located inland often make for very attractive PtX production locations—provided they offer suitable conditions for generating wind energy and/or solar energy and do not have any indicators of water stress. The USA, Argentina and Australia offer the greatest potential in terms of inland bodies of water. In total, inland water locations account for 70 percent of worldwide PtX production potential. Fig. 16.3 shows the ten countries with the largest potential area for production worldwide.

16.7.3

Global PtX potential

Based on these conditions, the atlas shows that in the long term, it would be possible to produce a total of around 109,000 terawatt hours of liquid green hydrogen or 87,000 terawatt hours of climate-neutral synthetic fuels (power-to-liquid, PtL) outside of Europe each year.

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Fig. 16.2 Percentage distribution and total area for priority preferred regions for PtX production. (Fraunhofer IEE)

Fig. 16.3 Overview of the ten countries with the largest potential areas for PtX production. (Fraunhofer IEE)

Regions that are suitable for both wind and solar energy, i.e. that have relatively high wind speeds and sunshine levels, account for a large share of this potential. Australia and the USA also offer significant potential in terms of solar-only locations, that is, locations that have low wind speeds but high sunshine levels. Wind-only sites in the USA, Canada and Russia constitute another significant source of potential.

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Global production potential for green hydrogen and synthetic fuels

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Fig. 16.4 Global PtX production potential across different types of PtX fuel. Source: Fraunhofer IEE

However, in reality, it will only be possible to exploit a portion of this total potential. The primary limiting factor for all these locations is the maximum possible speed at which renewable energies can be expanded between the present and 2050. PtX processes are often in competition with the decarbonization of local electricity generation for wind and solar energy resources. This is because countries’ carbon emissions can be reduced much more quickly by closing coal power plants as soon as possible than by producing PtX energy carriers. Furthermore, some of these locations do not offer sufficient investment security or lack the required infrastructure. However, if these factors are taken into account via socio-economic indicators, the potential production volumes that could realistically be achieved still come to 69,000 TWh of hydrogen or 57,000 TWh of PtL per year. For comparison, in 2019, total global production amounted to 45,380 terawatt-hours for natural gas and 53,610 terawatt-hours for petroleum. In efficiency projection scenarios that assume biomass will be used as an energy source (“Barometer der Energiewende” (Energy transition barometer) by Fraunhofer IEE [33] or “Klimaneutrales Deutschland” (Climate-neutral Germany) by Agora Energiewende [34]), the annual demand for PtX imports reaches approx. 500 TWh (including international transportation, and the share of global shipping and material use that the German industry accounts for). If biomass is not used, the demand may be higher, although it tends to be lower in sufficiency projection scenarios. Assuming that priority is given to increasing energy efficiency in all energy system sectors, and that direct electricity use is treated as the preferred

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option in end-use applications, the production potential that has been calculated would be sufficient to meet the remaining global demand for green hydrogen and climate-neutral fuels.

16.7.4

Location costs

Fig. 16.5 shows the distribution of liquid hydrogen production costs in relation to production volumes; in particular, it shows the costs and cumulative production volumes for low-temperature PEM electrolysis at coastal locations across the world. In general, the following principle applies: Locations with very good wind energy conditions tend to have the lowest costs—even when solar power is taken into account. However, such locations are limited in number. Consequently, PtX market prices are mainly determined by hybrid sites that offer suitable conditions for solar energy but are not optimal for wind energy. Sites that offer good conditions for solar energy only also have a significant impact on market prices, but their production costs are higher (Fig. 16.6). This means that depending on demand, these sites may have a lower economic potential. The countries that combine the lowest hydrogen production costs with significant production capacity are Chile, Argentina and Canada (Fig. 16.7). However, if the costs of transportation to Europe are also taken into account, this changes the outlook for many locations, at least in terms of hydrogen. This is because shipping is an energy-intensive and therefore expensive transportation op-

Fig. 16.5 Production costs and quantities of gaseous hydrogen at coastal sites using a PEM electrolyser across the world in 2050. (Fraunhofer IEE)

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Fig. 16.6 Production costs and quantities of gaseous hydrogen at coastal, solar-only sites using a PEM electrolyser in 2050. (Fraunhofer IEE)

Fig. 16.7 Average production costs and import costs (including transportation to Germany) for Fischer Tropsch fuels (FT) and liquid hydrogen (LH2). (Fraunhofer IEE)

tion, which cancels out the advantages that some regions offer in terms of production costs. For example, Australia is a good location for cost-effective production of green hydrogen—but due to the long distances involved, it is one of the most expensive locations worldwide in terms of total costs for European importers. Conversely, when transportation is taken into account, Morocco, which is relatively close to Europe, becomes one of the cheapest regions, in spite of its high production costs. Countries like Brazil or Mexico offer advantages in terms of hydrogen production costs, but these are tempered by transportation costs, thus giving rise to almost identical import costs for hydrogen and PtL.

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The atlas also shows that it is often more cost-effective to produce PtL energy carriers in the same location as the green hydrogen, as the PtL carriers are relatively easy to transport. The CO2 needed for these processes can be obtained on-site via direct air capture, particularly in South American countries and Australia.

16.7.5 Results for individual energy carriers In order to transport hydrogen to Germany by ship, it has to be liquefied, which is very cost-intensive due to the high levels of energy required. In addition, some gas is inevitably lost through vaporization en route, so it is necessary to ensure that the hydrogen is also used to power the ship itself. The average production costs for liquid hydrogen range from 64 to 153 euros per megawatt hour, depending on the country. If the costs of transportation are factored in, for example, from Argentina to Germany, the result is import costs of 112 euros per megawatt hour. The cheapest option for importing liquid hydrogen to Germany is Mauritania, which comes in at 82 euros per megawatt hour. Closer locations, for example in North Africa (Fig. 16.8), present different opportunities, as importing hydrogen from there to Europe via pipelines would be relatively inexpensive. The political situation is quite stable in both Morocco and Tunisia; however, these countries can only produce 971 terawatt hours of hydrogen per year. Egypt, Libya and Algeria offer far greater potential—8728 terawatt hours—but their socioeconomic conditions are much worse.

Fig. 16.8 Potential areas for PtX production in North Africa, taken from Fraunhofer IEE’s PtX atlas. (Fraunhofer IEE, map background: ©Esri HERE, Garmin)

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Conclusion

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Synthetic natural gas (SNG) must be liquefied if it is to be transported by ship, just like hydrogen. However, the potential for pipeline importing is limited in this case. Average production costs for liquefied SNG range from 87 to 195 euros per megawatt hour—similar to that of Fischer Tropsch (FT) fuels and methanol. Production costs for PtL energy carriers such as Fischer-Tropsch fuels and methanol fall between 86 and 190 euros per megawatt hour. Regions with very good wind conditions tend to make the most suitable locations for these processes. However, areas with very high levels of sunshine, such as Chile, can also be an attractive option, even in cases where the wind energy potential is quite low. The cheapest of these sites can achieve costs of 112 euros per megawatt hour for liquid SNG or PtL. Although the hydrocarbons that have been studied here differ only slightly in terms of import costs, FT fuels have proven to be the cheapest option due to their good chemical properties (they have high energy densities and are liquid under normal conditions). The costs of importing such fuels from Chile would come to at least 88 euros per megawatt hour.

16.8

Conclusion

In recent years, our knowledge and understanding of the importance of hydrogen technologies in the global energy system transformation have increased massively. On the basis of the Paris Agreement and the goals it laid down (including restricting the average rise in mean global temperature, promoting climate resilience and low-emission development, and providing the necessary funding for climate protection), countries are developing strategies, action programs, and energy and climate plans, and established corresponding national bodies. Other goals that are driving the transition to a global hydrogen economy include developing infrastructure and trading systems in the exporting countries with a view to improving national prosperity, creating new jobs, guaranteeing security of supply and establishing strong international partnerships. This global development means that in the future, climate-neutral hydrogen and its synthesis products will be used more and more as energy carrier materials and chemical raw materials in the mobility and industry sectors. Imports of hydrogen and its synthesis products will play a significant role in helping each country cover its own national demand in the long term. In the future, when evaluating supplier countries with the right geographical and climate conditions, it will be necessary to go beyond the technical and economic issues that have formed the main focal areas thus far and take into account

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additional factors and conditions affecting those regions. As such, it is important that the development and application of sustainability criteria, market mechanisms and incentive systems takes place at an international level where possible, and to integrate these factors into the governance structures of both the importing and exporting countries. Building up expertise and value creation and creating the necessary infrastructure at a local level, while taking into account the regional, social and economic conditions in the production countries, are the motivating factors behind the development of a global, interconnected hydrogen economy. Global climate targets can only be achieved by taking advantage of existing potential for sustainable PtX imports. However, this potential is clearly limited by factors such as costs, feasibility and sustainability, which means that in robust projection scenarios, priority must always be given to increasing energy efficiency in all energy sectors and using electricity directly in end applications—hydrogen and PtL must play a secondary, complementary role in such scenarios. Australia and the USA in particular have the potential to become major exporters here, as they offer excellent conditions for producing large quantities of PtX energy carriers, in terms of available area and climate. Moreover, their political stability makes them reliable candidates for investments. Australia would primarily supply PtL to Europe; however, the long distances involved mean that transporting green hydrogen from Australia to Europe will not be an economically viable option in the foreseeable future. It remains to be seen what share of American production volumes will be available for exporting, as there will also be domestic demand and demand from other importing regions for its climate-neutral fuels. In principle, it would also be possible to obtain large volumes of PtX from countries closer to Europe, such as the MENA region and Egypt and Libya in particular. This would include green hydrogen, because the distances involved are comparatively short, meaning that the energy carriers could be transported via pipeline. However, the socioeconomic conditions in these countries are worse, which increases investment risks and consequently also financing costs. Consequently, it is less likely that large-scale PtX projects will be implemented there. In addition to making use of import options, Europe must also expand its own hydrogen production capacity. Electrolyzers that run on electricity generated via offshore wind energy can act as an efficient source for the gaseous hydrogen needed by industry consumers (such as the steel industry), new gas turbines and fuel-cell CHP units in the energy sector. There is a higher level of competitiveness here. By contrast, PtL products will be imported to Europe for the most part.

References

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20. National Green Hydrogen Strategy—Chile, a clean energy provider for a carbon-neutral planet (2020) 21. Hydrogen Strategy for Canada (2020) 22. A hydrogen strategy for a climate-neutral Europe (2020) 23. CSIRO (2018): National Hydrogen Roadmap—Pathway to an economically sustainable hydrogen industry in Australia 24. Hebling, C., Ragwitz, M., Fleiter, T. et al. (2019): A hydrogen roadmap for Germany. https://www.ise.fraunhofer.de/content/dam/ise/de/documents/publications/studies/ 2019-10_Fraunhofer_Wasserstoff-Roadmap_fuer_Deutschland.pdf, last viewed on December 15, 2021. 25. Van Wijk, A., Wouters, F., Rachidi, S., Ikken, B. (2019): A North Africa—Europe Hydrogen Manifesto. Dii Desert Energy. https://dii-desertenergy.org/wp-content/uploads/ 2019/12/Dii-hydrogen-study-November-2019.pdf, last viewed on December 11, 2021 26. Matthes, C., Aruffo V., Retby-Pradeau L. (2020): Risks and Opportunities of Green Hydrogen Production and Export From the Mena Region to Europe. Dii Desert Energy, November 2020 27. H2 Mobility Tankstellennetz (H2 mobility refueling station network). https://h2.live/ tankstellen, last viewed on March 11, 2021 28. Matthes, C. (2020): Risks and Opportunities of Green Hydrogen Production and Export From the Mena Region to Europe 29. Forschungszentrum Jülich: https://africa.h2atlas.de/, last viewed on December 15, 2021 30. BMBF (2021) Karliczek: Westafrika kann zum klimafreundlichen “Powerhouse” der Welt werden (Karliczek: West Africa can become the world’s climate-friendly “powerhouse”). Press release, 110/2021 31. Commonwealth of Australia (2019): Australia’s National Hydrogen Strategy 32. BDI: Project HySupply. https://bdi.eu/themenfelder/energie-und-klima/wasserstoff/ hysupply/ 33. Fraunhofer IEE: Barometer der Energiewende (Energy transition barometer). https:// www.barometer-energiewende.de/, last viewed on December 15, 2021 34. Agora Energiewende (ed.): Klimaneutrales Deutschland. In drei Schritten zu null Treibhausgasen bis 2050 über ein Zwischenziel von 65% im Jahr 2030 als Teil des EU-Green-Deals (Climate-neutral Germany: Three steps to zero greenhouse gases by 2050, with an interim target of 65 percent in 2030 under the EU Green Deal). https://static.agora-energiewende.de/fileadmin/Projekte/2020/2020_ 10_KNDE/A-EW_195_KNDE_WEB.pdf, last viewed on December 15, 2021

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Uwe Spohn  Klemens Ilse  Jörg Kleeberg  Peter Michel Fraunhofer Institute for Microstructure of Materials and Systems IMWS Sylvia Schattauer  Alexander Spieß Fraunhofer Institute for Wind Energy Systems IWES Ulrike Beyer Fraunhofer Institute for Machine Tools and Forming Technology IWU Detlef Kratz BASF SE Stefan Spindler  Stefan Gossens Schaeffler Technologies AG & Co. KG Armin Schnettler Siemens Energy AG Abstract

In light of the targets for climate neutrality and resource conservation outlined in various international agreements, hydrogen is set to become a vital component in industrial production and general energy supply in the future. The growing hydrogen demand is opening up emerging markets at both a national and international level, meaning that technological solutions that address practical needs could develop into internationally successful products and processes. This chapter will discuss strategies and possible means of not only helping existing technologies evolve but also discovering and pursuing entirely new avenues. These new avenues range from recycling and innovative hydrogen pro© Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2_17

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duction processes, to the development of diverse technologies that will facilitate the establishment of a functional, economically viable hydrogen-based energy supply and basic industry.

17.1 Introduction In the German Climate Protection Act (Klimaschutzgesetz, KSG) concluded in 2021, the German Federal Parliament (Bundestag) set the country the goal of becoming climate neutral by 2045 [1]. Establishing a sustainable, cross-sectorial hydrogen economy is an essential part of national [2], European [3, 4] and global [5] efforts to reach climate protection targets. Climate-neutral hydrogen will have a role to play in almost every field of application, from basic industry1, where it will serve as a basic substance, feedstock and fuel respectively, for heating, energy supply and mobility on land, in the air and at sea. The suitability of a technology for producing, transporting and utilizing hydrogen is heavily dependent on location-specific factors and the intended use. From a climate protection perspective, the most important criterion for evaluation is the amount of harmful emissions released during production and use of an energy-efficient technology. In this context, the main focus is on ensuring that using the technology is climate neutral; however, ultimately, economic factors must also be taken into account at an early stage. Even today, hydrogen is already an indispensable substance for manufacturing products in many industry sectors (refineries, chemicals), with worldwide use reaching approximately at least 70 million tons. In other sectors, such as steel production, green hydrogen is viewed as the only technological option for achieving climate-neutrality. According to the action plan for hydrogen in Germany published in July 2021, Germany’s basic industry alone already requires 1.1 million tons of hydrogen per year [6]. The study adds that Germany’s hydrogen demand is set to grow to many times the current level of consumption. In the industry sector2 , the demand is expected to reach around 9 million tons in 2050. Meanwhile, hydrogen demand is projected to soar to 6.1 million tons in the traffic and transportation sector by 2050, based on scenarios where a high proportion of eFuel is used. Due to the many dependencies involved, estimating hydrogen demand in energy and heating supply is much more difficult. The energy supply limitations 1 2

This includes the chemical, steel, metal and biotechnology industries, among others. This does not include refineries.

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listed in the action plan include a demand amounting to around 288 TWh (approx. 17 million tons hydrogen) for 2040. The growing hydrogen demand is opening up emerging markets at both a national and international level. Technological solutions that address practical needs could potentially develop into export products. Many German companies are hard at work in this area, driving technological development along the entire value chain. A wide range of these technologies and fields of application have already been explored in the previous chapters of this book, covering the use of hydrogen in the energy system, industry, construction, and mobility and transportation. The necessary infrastructure was also examined, along with topics such as the basic technological principles involved in producing hydrogen via electrolysis, the use of hydrogen via fuel cell systems, relevant production processes and numerous other overarching issues (safety, standardization and digital transformation). The previous chapters have demonstrated that hydrogen could serve as the backbone of the energy transition. The goal for the coming decade is to develop and establish scalable technologies for producing, storing, distributing and utilizing hydrogen in the sectors of industry, mobility, energy and heating. Due to this systemic relevance, hydrogen technologies constitute one of the Fraunhofer-Gesellschaft’s seven strategic research fields. This is also plainly illustrated by the Fraunhofer Hydrogen Network, which numbers 32 of our 75 institutes among its members. This chapter offers a further insight into selected fields of application and technologies that are expected to be highly relevant to further research and development activities aimed at establishing a sustainable hydrogen economy.  The future demand for green hydrogen in the industry and energy sectors exceeds the current level of hydrogen production, which is largely dependent on fossil-based energy carriers. The question of where sustainable hydrogen could be produced is essential here. The potential for land-based locations is limited. However, offshore hydrogen production has the potential to deliver enormous quantities of the gas, which could help cover the future demand for green hydrogen. As such, Sect. 17.2 gives an overview of the concepts involved and the current status of research into offshore hydrogen production.  Achieving climate neutrality in the basic chemical industry requires not only that the energy needed to supply power, process heat and process chilling be switched to renewable sources, but also that chemical conversion processes be transformed into closed-loop cycles. Sect. 17.3 outlines possible means of supplying these basic materials via green hydrogen and alternative carbon sources, resulting in the incorporation of new closed-loop cycles into the industry processes.

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 To facilitate market ramp-up for hydrogen technologies, particularly as regards cost-effective green hydrogen production, intensive cost reduction measures in the area of electrolyzer production will be needed in the near future. In addition to improvements and upscaling of existing production technology, this will necessitate radical, systemic research and development to demonstrate the possible courses of action as regards evolving electrolyzer manufacturing technology (Sect. 17.4).

17.2 Offshore hydrogen production—options for covering future hydrogen demand According to current data, the EU demand for hydrogen and hydrogen-based synthesis products is set to reach a range of 550 to 1800 TWh by 2050. In Germany alone, demand is expected to climb to between 400 and just under 800 TWh, as was shown by a recent meta-analysis study that explored German and EU-wide climate protection scenarios where greenhouse gas emissions should be reduced by at least 95 percent [7]. In light of the limited potential offered by biomass and the restricted use of carbon capture and storage (CCS) strategies, the most promising technological option for meeting demand is the production of green hydrogen via electrolysis. Cheap electricity produced from renewable energy sources is one of the requirements for achieving competitive hydrogen production costs (levelized cost of hydrogen, LCOH). When it comes to quantity and cost, offshore wind energy has the potential to fulfill the conditions necessary for hydrogen production, which is quite energyintensive when compared to direct electricity usage. At the end of 2020, the installed capacity for offshore wind power in the EU amounted to 25 GW [8]. The global technical potential for offshore wind energy facilities located close to coastlines (less than 90 km away), in the lower atmosphere and at medium water depth (less than 200 m) is estimated at 180,000 TWh per year [9]. According to a 2009 report by the European Environment Agency, the EU’s technical potential amounts to 3500 TWh, although this only takes into account the potential for a water depth of up to 50 m [10]. Offshore wind farms that are far from the coast also offer a great deal of potential. However, due to their distance from land, they are not suited for connection with power grids and depending on the water depth, it may not be possible to build them on a solid foundation [11]. In principle, offshore wind farms benefit from higher and more stable wind speeds than onshore conditions, which would help facilitate the continuous operation of electrolyzers and lead to lower

17.2

Offshore hydrogen production—options for covering future hydrogen demand443

hydrogen production costs. The models for offshore hydrogen production can be divided into self-sufficient models without any connection between the offshore wind farm and the power grid, and hybrid models that do have a connection to a power grid.

17.2.1

Hybrid offshore hydrogen production

Hybrid offshore hydrogen production offers advantages such as a higher degree of operational flexibility and a higher portion of usable electrical energy. An analysis of a simulation of a hybrid offshore wind farm with an energy capacity of 1000 MW in the Pays de la Loire region in France showed that such a facility could significantly reduce wind energy curtailment. When no H2 is produced, curtailment amounts to around 35 percent of the wind energy that could potentially be generated [12]. Furthermore, hybrid models offer the flexibility to decide whether the electricity produced is fed into the power grid or used for hydrogen production, provided that there are no bottlenecks in the upstream power grid and that there is sufficient transportation and storage capacity available for the hydrogen. Using suitable control processes based on predictive models, the system can make automatic decisions during operation as to which operating mode would be more economically advantageous, taking into account various technical criteria such as the difference between energy costs and the revenue generated via that energy. In addition to participating in the conventional power market (power exchange or over-the-counter trading), grid connections enable a negative control power supply. The addition of a fuel cell unit means that a hybrid offshore hydrogen production system can also function as a power storage facility, thus enabling the supply of positive control power. The disadvantages of this approach are that the investment costs are much higher. Previous studies have shown that hybrid models are only be profitable for a limited range of locations with specific market and environmental conditions [13]. This is due to the fact that the hybrid model is primarily suited to locations in close proximity to the coast, since a high proportion of costs go to power grid connections (submarine cables, converters, etc.). At the same time, they are also in competition with offshore wind farms that only produce energy. If the facility is focused on power storage rather than hydrogen production, other storage technologies must be taken into account as well [14]. The hybrid model is most likely to be suitable for regions with high wind energy potential and high curtailment levels that have impeded the development of the locations thus far. Land-based electrolysis may also be an alternative to direct offshore hydrogen production. However, analyzing the economic viability of a facility of this

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kind shows that even in this scenario, self-sufficient offshore hydrogen production should be the preferred option, particularly where electrolysis capacity and distance from the coast are increased [15].

17.2.2

Self-sufficient offshore hydrogen production plants

As they do not require a power grid connection, the investment costs for selfsufficient offshore hydrogen production plants are lower. Furthermore, the plants offer more flexibility in terms of location. The hydrogen can be transported away from the plant by ship or pipeline. The advantages of pipelines are their high, continuous throughput capacity and their ability to transport the hydrogen as a gas. The latter helps avoid energy loss, which occurs when liquefying hydrogen, for example. The question of which mode of transportation is more suitable is also heavily dependent on the distance from the coast and the quantities of hydrogen transported. For locations that are close to the coast3 and have high production output, pipelines have a clear advantage over shipping in terms of costs. For locations that are particularly far from the coast, transportation via ship is likely the best option, as the costs of a pipeline are generally proportional to the length of the line [11]. One challenge for self-sufficient offshore hydrogen production plants is dimensioning and controlling the wind turbines and electrolysis, as well as the individual turbine components. The goal here is to achieve the maximum usage rate for the electrical energy while also taking into account the technical restrictions of the electrolysis plant. In order to avoid operating conditions that may damage the system, the degradation properties of the electrolysis cell must be taken into account. In the self-sufficient model, the energy for the entire system, including the peripheral components, is supplied by the wind turbines. This includes not only electrolysis but also water supply, sea water treatment, compressors, cooling, automatic system control and the use of electricity to provide lighting and heating for sensitive parts of the system. If the wind drops, a basic energy supply must still be ensured, for example, by reconverting the hydrogen that has been produced into electricity using a fuel cell. Battery storage also offers a potential area for optimization. In terms of the placement of the electrolysis units, both “in-turbine” and hub models are under discussion. The in-turbine model involves placing electrolyzers directly in the wind turbine tower or on a dedicated platform around the turbine. 3

The pipeline studied by Dambeck et al. [15] was 150 km long.

17.2

Offshore hydrogen production—options for covering future hydrogen demand445

The individual turbines of offshore wind farms have far greater capacity than onshore facilities (capacity levels currently range from 6 to 14 MW). In locations with multiple in-turbine systems, the hydrogen is fed into a central collection point via small pipes and compressed. Then it can be taken away via a larger pipeline. In hub models on the other hand, the electrolysis units are mounted on a central platform. In this case, the turbines are connected to the hub via power lines rather than gas pipelines [16]. Both models generally allow for buffer and temporary storage. Depending on the size of the overall system and the logistical factors concerning the hydrogen, different storage solutions may be more suitable.

17.2.3

Impact of electrolysis technologies

The electrolysis technology used has a non-negligible impact on optimal facility set-up. An important factor here is the electrolyzers’ ability to handle the dynamic conditions stemming from the turbines’ fluctuating electrical loads. To date, technical and economic studies [11–13, 15] are focused primarily on alkaline and PEM electrolysis (AEL and PEMEL). Due to the lower specific investment costs incurred in alkaline electrolysis, the results of these technical, economic analyses often indicate that it offers a slight advantage over PEMEL in terms of cost. However, the difference between the specific investment costs is expected to be more or less eliminated in the medium term. Furthermore, the dynamic properties were only taken into account to a limited extent, as each simulation only lasted an hour. PEMEL offers certain advantages over alkaline electrolysis, particularly in terms of dynamic load properties, space requirements and operational stability when current density fluctuates [17, 18]. In principle, deionized water can be provided via reverse osmosis [19, 20], electrodialysis [21], isothermal distillation and other distillation processes [19]. Reverse osmosis involves hyperfiltration via asymmetrical polyamide-polysulfone membranes, which uses relatively small amounts of energy and produces deionized water and a concentrated saline solution. If there was an effective way of combining electrodialysis with hydrogen electrolysis, carbon dioxide could also be extracted from the sea water [22] and opens up a way to synthesize methanol on the offshore platform. In general, the technical challenges involving in just supplying water for offshore hydrogen production are far greater, and this higher level of effort is reflected in the water supply costs [23]. Solid oxide electrolysis (SOEL) is often brought up in discussions around PtX processes. One advantage that SOEL offers is that heat can be recovered in the upstream and downstream processes. If the waste heat can be used productively,

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SOEL has a better overall level of efficiency than PEMEL or AEL, so it is suitable for combination with PtX synthesis processes [24]. However, up to now the technology is more limited in terms of its capacity to handle dynamic conditions.

17.2.4

Lighthouse projects for offshore hydrogen production

Offshore hydrogen production is still in its early days, and as such, achieving the target of cost-effective hydrogen production will require further research and development activities, addressing the entire ecosystem, from designing and combining the components and developing individual technologies right through to investigating the possible impact on the marine environment. At the system level, researchers are focusing on overall efficiency and cost-effectiveness. As such, the system configuration and the various technologies must be optimized in order to avoid issues such as unnecessary losses due to additional conversion steps. When it comes to hydrogen components, researchers are placing particular focus on the impact and stresses that the marine environment will place on the materials. The corrosion stress that the high saline levels will place on the materials also requires research. In order to scale processes up from research labs to an industrial level, scientists must investigate the mechanical stresses affecting both in-turbine and hub models and take these into account during technological development. Electrolysis technologies must be optimized to suit the wind turbines’ characteristic energy generation properties in such a way that they can be shut down if minimal signs of degradation occur. Researchers must study operating conditions that can damage the systems so that it is possible to avoid such conditions by designing a suitable control process. When it comes to material supply, researchers are directing particular attention to sea water treatment. H2 Mare, a lighthouse project in the German scientific ecosystem, is addressing many of these research questions. The H2 Mare participants are collaborating in four different joint projects aimed at researching offshore hydrogen production, including downstream synthesis steps, and creating the first demonstrator for a system of that kind [25].  In the joint project OffgridWind, researchers are attempting to implement an in-turbine model, with the goal of maximizing the electrical efficiency of the hydrogen production. They are also developing solutions for storing and transporting the hydrogen to land.  The aim of the joint project H2 Wind is to develop a PEM electrolysis process that is suited to offshore conditions. This includes the electrolysis cell

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and system design; whereby particular attention is paid to the membrane unit. In addition to a number of other components, finding an optimized sea water treatment method that is aligned with the development of the PEM process constitutes an important element of the project.  Researchers in the PtX-Wind project are primarily working on direct production of additional power-to-X products at sea. They are exploring the possibility of producing liquid methane, Fischer-Tropsch hydrocarbons, methanol and ammonia at offshore facilities that are directly combined with offshore wind farms that do not have power grid connections. In terms of electrolysis technologies, the researchers are focusing on solid oxide electrolysis and direct sea water electrolysis.  The fourth joint project, TransferWind is addressing higher level issues, such as environmental and safety-related factors and infrastructure requirements. All the joint projects include simulation-based analyses, which help support technology development, e.g., for electrolysis cells, facilitate the optimization of individual systems and sub-systems, and enable the researchers to conduct technical and economic evaluations at different system levels. The consortium consists of over forty project partners and is spread across four joint projects. Siemens Energy AG is coordinating the technology platform aspect of the consortium, as well as leading the joint project H2 Wind. Six Fraunhofer institutes are playing key roles in the OffgridWind and H2 Wind projects and are supporting Siemens Energy in the scientific aspects of the platform coordination.

17.3

Working toward climate neutrality in the basic chemical industry

Achieving climate neutrality in the basic chemical industry requires not only that the energy to supply power and process heating and cooling be switched to renewable sources, but also that chemical conversion processes be transformed into closed-loop cycles. This can be accomplished by using methanol synthesis, Fischer-Tropsch synthesis, thermochemical plastic recycling (pyrolysis, conversion to oil or gas) in combination with refining and cracking processes and processes for manufacturing monomers and polymer materials (Fig. 17.1). Large quantities of hydrogen are a vital constituent of these processes. However, to date, this hydrogen has primarily been produced via steam reforming of methane and other hydrocarbons. The replacement of this fossil-based hydrogen with green hydrogen is one of the core issues to be addressed on the road to climate neutrality,

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and it must be implemented gradually in line with the climate targets stipulated by the EU and the German federal government, taking into account factors relating to competitiveness. At a technical level, implementation will necessitate switching hydrogen production to electrolysis powered by green electricity and integrating synthesis gases that have undergone process-related optimization measures, i.e., CO/H2 , CO2 /H2 , CO2 /CO/H2 and N2 /H2 , into supply and management. However, it must be noted that complete defossilization of the chemical industry, i.e., switching from petroleum and natural gas to green hydrogen and carbon dioxide, would require many times the volume of hydrogen that is currently used (1.1 Mt), which would cause a corresponding increase in electrical energy consumption. This can only be achieved by a sufficient expansion in the generation of electricity from renewable sources for hydrogen production and by importing energy carriers produced via renewable methods, including green hydrogen, among others. On the other hand, the chemical industry and the refinery industry already have a well-developed infrastructure for process engineering, transportation (pipeline and distribution networks) and storage of hydrogen. As such, they are set to play a pioneering role in implementing green hydrogen at an industrial scale. In addition to increased use of climate-neutral hydrogen, identifying and using the most climate-friendly and economical source of carbon is also a crucial factor here. Using CO2 would be an obvious, sustainable solution here. In addition to obtaining CO2 from process gases that already contain it (known as point sources), as occurs in cement manufacturing, for example, the possibility of extracting CO2 from the atmosphere or hydrosphere is also currently being examined with an increased level of interest. However, the CO2 ’s high level of dilution poses a major challenge here. Methods for capturing CO2 from air and water include cryogenic air separation [26], adsorption technologies, molecular filters and electrochemical processes. The focus here lies on using carbon dioxide and nitrogen in combination with green hydrogen in order to manufacture platform chemicals such as methanol, ammonia (see Chap. 5), ethylene and propylene, BTX aromatic compounds and naphtha (Fig. 17.1), respectively. This becomes evident from such factors as the prominence and diversity of carbonylation processes, which use easily accessible CO by using the inverse water-gas shift reaction from carbon dioxide. The CO can be converted with methanol to produce ethanoic acid, for example, or with olefins to produce aldehydes [27]. What’s more, the catalytic activation of CO and CO2 is also the most important step both in methanol and Fischer-Tropsch synthesis. This means green hydrogen, carbon dioxide and carbon that is brought into the closedloop cycle via climate-neutrally formed molecules (CO, ethylene and propylene) will play key roles in establishing a climate-neutral chemical industry.

17.3

Working toward climate neutrality in the basic chemical industry

449

Fig. 17.1 Establishing closed-loop cycles in the chemical industry and building connections between refineries and plastics recycling (red), methanol synthesis (green), Fischer-Tropsch synthesis (blue) and cracking as key processes for supplying olefins, methanol, and aliphatic and aromatic hydrocarbons (based on [28])

As examples of this, the following sections will consider the three central processes, namely methanol synthesis, Fischer-Tropsch synthesis and plastic recycling, as well as the role of hydrogen and the possible factors that could contribute to achieving a climate-neutral basic chemical industry.

17.3.1

Working toward climate neutrality in methanol synthesis and its downstream chemical processes

Methanol is one of the most important intermediate products of the chemical industry. It is environmentally friendly and easy to store. For all these reasons, it is

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Fig. 17.2 Carbon capture and recycling (CCR) via methanol synthesis and thermochemical plastic recycling (based on [30, 31] and the works cited therein)

becoming rapidly more important. Fig. 17.2 uses methanol synthesis as an example to illustrate how, on the basis of green hydrogen, a closed-loop cycle can be established for the carbon used in other branches of the chemical industry. The process is based on using carbon dioxide in combination with green hydrogen that has been produced using power from renewable energy sources. In this process, as well as the other processes discussed below, it is vitally important to optimally use sufficiently powerful catalysts to achieve high selectivity and space-time yield, as well as to reduce the activation energy required (process temperature reduction) [29–31]. Catalytic pressure synthesis processes based on hydrogen, carbon monoxide (Eq. 17.1) and carbon dioxide (Eq. 17.2) are extremely advanced and can be linked via the water-gas shift reaction (Eq. 17.3). As a result, the production of methanol and the associated downstream chemical processes will become one of the most crucial avenues for replacing fossil-based carbon sources in the chemical industry and recycling carbon dioxide [30–33]. CO C 2 H2 $ CH3 OH CO2 C 3 H2 $ CH3 OH C H2 O CO2 C H2 $ CO C H2 O

R H298K D 90:8 kJ=mol

(17.1)

R H298K D 49:5 kJ=mol

(17.2)

R H298K D 41:2 kJ=mol

(17.3)

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For an optimal process, the reaction heat generated by reactions Eqs. 17.1 and 17.2 must be removed and pressure must be maintained at a sufficiently high level. Using the heat generated in the reactions to pre-heat the synthesis gas and to remove the methanol by distillation is vital for energy efficiency. Synthesizing methanol (MeOH) and dimethyl ether (DME) using carbon dioxide as a raw material and power from renewable energy sources saves 1.43 kg CO2 /kg MeOH and 2.17 kg CO2 /kg DME in carbon dioxide emissions according to calculations conducted in the chemical industry [34]. If applied to Germany’s yearly production in 2019, this would have meant a potential reduction in CO2 emissions of 2 million tons [35]. On this basis, a possible transition to methanol-toolefin processes in the production of propylene and ethylene would mean that more than 30 million tons of CO2 emissions could be saved annually. These processes [36] provide a comparatively selective method of obtaining ethylene (Eq. 17.4), propylene and other olefins (Eq. 17.5), such as butylene and isobutene—a method that is set to become increasingly important in the future. Higher ethylene and propylene yields (of up to 99 percent per unit of methanol and DME) will be achieved via zeolite catalysts based on silicoaluminophosphates (SAPO). 2 methanol ! CH2 D CH2 C 2 H2 O

(17.4)

n methanol ! CH3 .CH2 /n3  CH D CH2 C n  H2 O

(17.5)

Dry reforming is another possible means of incorporating the carbon in CO2 directly into products like ethylene and propylene. In this method, hydrogen and CO are produced using methane and CO2 rather than methane and water vapor (Fig. 17.3). Combining the dry reforming reaction with the production of dimethyl ether (DME) in the presence of a bifunctional catalyst and converting DME into olefins by feeding CO2 back into the reaction makes it possible to incorporate around 25 percent of the carbon from external CO2 into the olefins. Finally, the methane is converted into olefins with binding carbon dioxide additionally. Ethylene and propylene, which can be produced via carbon-negative methane or cracking processes, are numbered among the top five most important chemical industry products, with a yearly global production volume of 158 and 108 Mt respectively [37, 38]. They also form the basis for manufacturing polyethylene and polypropylene, the two most important polymer materials. In this value chain, the use of green hydrogen and carbon dioxide would make a particularly significant contribution to climate neutrality. If ethylene undergoes homogeneous catalysis with CO, methanol and formaldehyde, the Lucite Alpha process [39] becomes available as a highly productive method of manufacturing methyl methacrylate, and thus also PMMA (polymethyl

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Fig. 17.3 Synthesizing olefins from methane and carbon dioxide. CRDR means CO2 recycling via dry reforming, whereby 25 percent of the carbon comes from external CO2 and 75 percent comes from methane (BASF)

methacrylate). The oxygen that is produced along with hydrogen in water electrolysis or in air separation can be used for ethylene epoxidation with a silver catalyst, which represents a climate-friendly means of manufacturing polyethylene oxides. Propylene oxides can be manufactured by converting propylene and hypochlorous acid into 1-Chloro-2-propanol/2-Chloro-1-propanol and then conducting alkaline dehydrochlorination. It can also be manufactured via catalytic oxidation using organic hydroperoxides, hydrogen peroxide or oxygen. The latter option is currently given priority due to its high selectivity of over 99 percent [40]. The catalytic conversion of methanol to aromatic compounds (methanol-toaromatics process [41, 42]) provides a similarly low-carbon means of producing benzene, toluene, ethylbenzene and xylene. Thanks to continuous advancements in catalyst efficiency, this method is associated with very high levels of selectivity and space-time yield. By developing the underlying process model in a similar way, researchers have succeeded in developing methanol-to-gasoline and methanol-tokerosene processes, through targeted catalyst design and suitable adjustment and optimization of process parameters such as temperature, pressure and retention time [43, 44]. This will make it possible to produce and use green fuels in aviation, shipping and heavy-goods transportation in the future—a development of high strategic importance. Provided that a permanently climate-neutral supply of CO, CO2 and green hydrogen is available, the concept of catalytically dehydrating condensation of methanol to hydrocarbons could play an important role in the development of climate-neutral chemical and refinery industries. As it is becoming ever more important and urgent to harness carbon dioxide, and as scientists are continuously developing more selective catalysts, “green” methanol is increasingly taking center stage as a key chemical for the energy and raw materials transition.

17.3

Working toward climate neutrality in the basic chemical industry

17.3.2

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The road to climate-neutral Fischer-Tropsch synthesis

Fischer-Tropsch synthesis is another process considered strategically important for harnessing green hydrogen. In this process, the synthesis gas CO/H2 undergoes heterogeneous catalysis, using iron or cobalt catalysts for example, to form aliphatic hydrocarbons (alkanes and alkenes) and higher aliphatic alcohols. The product mixture composition depends on the partial pressure ratio pCO/pH2 , the overall pressure, the catalyst and the temperature [45]. Tandem catalysis [46–48] can be used to manufacture climate-neutral fuels (gasoline, diesel, kerosene) via synthesis of non-waxy hydrocarbons, provided that optimal temperatures are set for each reaction and that a hydrocracking process follows on downstream. Specially designed iron catalysts [49] make it possible to run a CO hydrogenation reaction (Eq. 17.6) in combination with an inverse water-gas shift reaction (Eq. 17.7). This is the equivalent of converting carbon dioxide and green hydrogen into hydrocarbons (Eq. 17.8) (x D 0 to 1 for alkenes and alkanes, respectively). n CO C .2n C x/ H2 ! Cn H2nC2x C n H2 O

(17.6)

n ŒCO2 C H2 $ CO C H2 O

(17.7)

n CO2 C .3n C x/ H2 $ Cn H2nC2x C 2n H2 O

(17.8)

However, the drastic shift in product composition toward methane and other lower hydrocarbons is an obstacle to using CO2 directly. This highlights the importance of green hydrogen in reaction Eq. 17.7. Fischer-Tropsch synthesis is particularly well-suited for fuel manufacturing due to the relatively moderate reaction conditions it requires (T D 250 to 300 °C and p < 5 MPa). As such, this process is also numbered among the primary strategic routes for making the basic industry climate neutral, especially as the amount of hydrocarbons that must be manufactured for fuels, among other things, exceeds the amount of intermediate products such as ethylene, propylene or methanol manufactured for the chemical industry itself many times over. The Fischer-Tropsch process uses green hydrogen and carbon dioxide or monoxide to produce naphtha. When subsequently processed through cracking, this naphtha offers a carbon-neutral means of manufacturing ethylene and other olefins (Fig. 17.1). As such, the chemical and refinery industries can continue to use existing and expensive facilities such as steam crackers and hydrocrackers. This is another avenue for driving the chemical industry’s transition to climateneutral value chains. In the context of climate-neutral methanol synthesis and

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thermochemical plastic recycling via gasification and pyrolysis, it is becoming apparent that there is a need to develop and establish an intelligently controlled management system for the material flows involving key components such as hydrogen, CO, CO2 , naphtha, ethylene and propylene.

17.3.3 How recycling plastic material can help Plastic is one of the most important materials in the world. Many everyday products and modern technologies would not be possible without it. The plastics manufactured in Germany are produced almost exclusively from the fossil-based resources natural gas and mineral oil. Given that Europe and Germany produce 57.9 and 18 megatons of plastic per year, respectively [50, 51], recycling the material, particularly via chemical methods, could potentially provide substantial assistance in achieving the German federal government’s climate protection targets. Germany generates around 6 to 6.5 megatons of plastic waste every year, which comes to approximately one third of the amount it produces [52]. Based on the assumption that processing plastics into recyclate saves 1.5 kg CO2 equivalent per kilogram of plastic waste, as calculated in [53], achieving the planned recycling rate of 60 percent by 2030 would save 5.6 megatons of CO2 emissions. However, achieving this saving in CO2 emissions will require the efficient use of substantial quantities of climate-neutral energy, as recycling processes generally have a high energy requirement. The system limits of the individual industries in the value chains must be expanded accordingly, in order to take both direct and indirect emissions into account in overall carbon footprint calculations. In this context, green hydrogen could make a crucial contribution to creating a closed-loop cycle for carbon in the industry sector (Figs. 17.1 and 17.2). In today’s established waste management system, however, plastic waste primarily undergoes thermal recycling. The carbon contained in the waste is released into the atmosphere as CO2 for the most part. Transitioning to a circular economy would necessitate cutting out most of these emissions and reducing resource consumption. To achieve this, the processes for treating plastic waste streams must be radically restructured. Consequently, the participants in the Fraunhofer lighthouse project Waste4Future are executing the pioneering strategy illustrated in Fig. 17.4, whereby waste is converted into a raw material to provide green molecules for chemistry. They are focusing in particular on material and chemical recycling, with a view to recovering the material where possible. Otherwise, their primary aim is to enable the use of the carbon as a material by extracting reusable monomers, certain cracking

17.3

Working toward climate neutrality in the basic chemical industry

455

Fig. 17.4 Process map from the Fraunhofer lighthouse project WASTE4Future (see also Figs. 17.1 and 17.2)

products and synthesis gas. They aim to develop a holistic recycling strategy that is controlled via material flows and focuses on optimizing recycling rates while reducing energy consumption using an entropy-based evaluation model. Recycling chains that have previously been process-driven are now being converted into material-driven recycling chains. In this context, entropy is intended to serve as a measurement of disorder and order in the recycling systems and a key indicator for evaluating the success of the recycling process. As waste streams tend to not to be sorted and contain very different waste types—which is likely to continue in the future—a new sorting model has been developed, which can determine what materials and in particular, what plastic fractions are contained in the waste, and in what quantities. This information is used as a basis for deciding what mode of recycling would be most suitable for the specific waste fraction from a technological, environmental and economic perspective. The optimization goes beyond the individual processes and is aimed at separating the overall waste stream based on entropy values and assigning the most energyefficient recycling method in a targeted way. The waste stream is broken down into the specified sub-streams, which are then fed into different processing routes based on a hierarchical ranking of the possible recycling technologies. At the end of the recycling chain, the waste fractions that cannot be recovered through material re-

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cycling (e.g., mechanical recycling, solvent-based purification and fractionation) are available for chemical recycling, e.g., via solvolysis [54], pyrolysis/conversion to oil and gasification. By avoiding thermal recovery via combustion, the recycling process retains the maximum possible amount of carbon compounds, which maximizes value creation and reduces the resulting greenhouse gas footprint. Innovative recycling technologies will be developed for complex waste, in order to obtain high-quality recyclates and raw materials for the chemical industry. Since using combustion to generate heat and power causes unacceptably high levels of carbon dioxide pollution and also involves the destruction of valuable raw materials, coupled with the fact that it is often very difficult to separate materials cleanly in recycling, chemical recycling processes such as gasification, which can be conducted on an autothermal basis using air or oxygen, heated externally or conducted in plasma form [55, 56], pyrolysis with and without the aid of hydrogen [54, 57, 58], and physical and chemical solvolysis are gaining considerable importance. In addition, scientists are developing gasification processes that work with heated and superheated steam yielding synthesis gases with higher hydrogen content. A reforming step conducted using superheated steam can also be used to convert the bitumen and carbon residues that are formed as intermediate products into carbon monoxide and hydrogen. To reach the optimal composition [H2 ]/[CO]/[CO2 ] of the resulting gas mixture, green hydrogen can be added in, which yields a synthesis gas that is fit for use in Fischer-Tropsch and methanol synthesis processes (Figs. 17.2 and 17.4). Hydrogen can also be used in order to harness the CO2 that is produced during gasification. This CO2 primarily results from autothermal gasification, as the necessary process heat can be obtained by oxidizing some of the plastic. The separated CO2 can be processed further, for example, by mixing it with hydrogen to form a CO2 /3H2 synthesis gas that is suitable for methanol synthesis. Hydrogen can also be used to process pyrolysis oils (Figs. 17.1 and 17.4). Pyrolysis of plastic-based waste results in a mixture of organic compounds, the composition of which is determined by process conditions such as temperature, pressure, gas composition, plastic waste composition, retention time in the reactor and catalytic effects. The organic compounds are recovered via product flows for pyrolysis coke, pyrolysis oil and process gas. At present, pyrolysis oil is the most important material flow. Coke and process gas flows are often used to supply the necessary process heat. To improve the pyrolysis oil’s properties as a product, the oil must undergo subsequent processing. Hydrogenation processes are used for this purpose, in order to increase the H/C ratio and remove oxygen [59]. In the future, an optimized

17.4

Evolutionary manufacturing technologies for electrolyzers

457

material flow management system will be established with the aim of providing a flexible supply of the synthesis gas in question. In this system, green and recycled hydrogen and carbon dioxide from process gases, e.g., from thermochemical recycling of plastic waste, will be used in combination. Meanwhile, carbon monoxide will take on a more valuable role in this system, becoming a synthesis component (for methanol and Fischer-Tropsch syntheses and their downstream chemical processes, e.g., methanol-to-olefin processes). Fig. 17.1 illustrates the interactions between the material flows and shows possible means of incorporating green hydrogen and carbon dioxide into them, so as to drive the defossilization of the chemical industry. The use of established chemical and refinery industry processes such as thermal and catalytic cracking and hydrocracking (which are currently the most prominent techniques for manufacturing ethylene and propylene), as well as the purification and use of plastic waste in combination with hydrogen also demonstrate the importance of pyrolysis and the associated process of converting plastic waste into oil.

17.4 Evolutionary manufacturing technologies for electrolyzers 17.4.1

Current situation

At present, globally installed water electrolysis capacity has reached around 1 gigawatt. Due to the current low level of market demand, electrolyzers are generally produced on a project-specific basis and in small batches. As such, value creation in this area has yet to be optimized for high output volumes, while supply chains are few and tend to be fragmented. The companies involved are hesitant to make investments due to uncertainties regarding the regulatory framework, timing, speed and extent of the market ramp-up given the current low level of demand. Consequently, there are few production technologies available today that are standardized to suit high-throughput manufacturing or optimized for high levels of process automation in production and testing technology. At the same time, green hydrogen produced via electrolysis that is powered by renewable energy has come to be viewed as the primary energy carrier for future energy systems. Green hydrogen is expected to be vital to achieving climate protection targets and providing a sustainable energy supply for all sectors. As it stands, hydrogen currently covers around 2.5 percent of global energy requirements (110,000 TWh). Depending on the development scenario that is taken as

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a basis, this share is set to grow to up to 18 percent by 2050. However, at present, gray hydrogen is used almost exclusively. In order to replace this with a more climate-friendly alternative, plans are in place to gradually increase the shares of blue, turquoise and especially green hydrogen. Ongoing research projects are primarily focusing on analyzing and scaling existing production technologies. These projects are important and necessary; however, they are not enough to accomplish the immense cost reduction requirements for hydrogen production and green hydrogen as a product. There is a need for fundamental, systemic research and development activities that highlight the possible courses of action as regards the evolution of electrolyzer technology, in order to make green hydrogen competitive and ultimately guarantee that competitiveness in the long term. This can only be achieved through a synergistic approach that includes all major stakeholders.

17.4.2

Main challenges

The potential increase in demand for green hydrogen will create a need to build up global installed electrolysis capacity considerably and to expand renewable energy generation. Depending on the scenario that is projected, global installed electrolysis capacity may reach between 75 to 234 GW by 2030. This corresponds to projected growth of between 26 and 100 GW in 2030 alone. This market rampup will only be feasible if hydrogen technologies can compete with alternative energy carriers at a financial, technical and legislative level. Currently, green hydrogen costs around 5 to 6 US dollars/kg, while gray and blue hydrogen is available for 1 to 2 US dollars/kg. Improving the competitiveness of green hydrogen will necessitate significant cost savings. The main areas for potential cost reduction relate to capital expenditure and operating expenses for electrolyzers. For example, the costs for a PEM electrolyzer can run up to values between 700 to 1200 US dollars/kW depending on the size of the system, while an alkaline electrolyzer will come to the range of 650 to 950 US dollars/kW. However, the market will only accept costs of between 350 to 450 US dollars/kW. This means that a cost reduction of 50 percent is needed for alkaline electrolysis and 70 percent for PEM electrolysis. In turn, this gives rise to a wide range of challenges for manufacturing of electrolyzers. The focus in this context is on developing production and testing solutions that can maintain high throughputs and are based on current product design. To this end, existing systems must be scaled up and new mass production solutions must be developed to facilitate large batches and reduced cost levels. The

17.5

Possible development paths for a systemic road map

459

aim here is to optimize functionality, component design and production technology in accordance with the output volume. Other primary development goals include extending stack service life (up to 80,000 h for PEMEL, up to 120,000 h for AEL, up to > 20,000 h for HTEL) by reducing cell degradation. Researchers are also concentrating on the vital areas of optimizing operating parameter configuration, e.g., increasing current density and higher operating pressure, and efficient, flexible operating modes at optimal operating points. Furthermore, use of critical materials (e.g., rare earth metals and platinum group metals) must be reduced and recycling processes with corresponding material flows must be developed.

17.5 Possible development paths for a systemic road map outlining radical upscaling measures for electrolyzer production A systemic road map must be implemented along two coordinated courses of action, routes A and B (Fig. 17.5). The first step to be taken—route A—is to develop a production scaling strategy based on existing products. Route B, which explores the evolution of the technology by means of analytical optimization of electrolyzer design and the related manufacturing technologies, must be expanded in parallel. The scope for route B must be developed now to ensure long-term continuation of route A, as well as to reach the target of achieving cost parity between green hydrogen and fossil-based alternatives.

Fig. 17.5 Visualizing the necessary courses of action: routes A and B

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17.5.1

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Hydrogen technologies: outlook and future possibilities

Route A—upscaling existing products

This route must focus on developing an upscaling strategy for the production of established electrolyzer technology. To do this, the results of initiatives that have been announced or already launched, such as H2 Giga must be implemented. The goal here is to consolidate ongoing projects together with research questions that have yet to be addressed, and to identify the corresponding areas where action must be taken. In the process, existing production processes must be analyzed in terms of cost drivers, their suitability for various batch types, functionality, quality, geometry and overall costs. Alternative production processes must also be developed as regards technological and financial parameters and new target ranges, taking into account international competitors. Furthermore, it is necessary to ensure that upscaling can be adapted to the timing of the market ramp-up and national and international road maps (both on an EU-wide and a global level). Standards must also be developed for the electrolyzer systems and their manufacturing and testing. Finally, the development of value creation networks (OEMs, suppliers, plant manufacturers) requires significant acceleration. In particular, this will necessitate the establishment of a highly skilled supplier industry that does not yet exist, so that the supply scale required for implementation can actually be achieved. It is only once this is accomplished that the associated industrialization processes can take place and the system costs can be brought down to the required level.

17.5.2

Route B—evolving design and manufacturing technologies

The core element of the evolution process must be the formulation of an analytical method capable of comprehensively mapping the multidirectional relationships between the functional, economic and spatial requirements, as well as the technological feasibility. This method will then form the basis for designing future electrolyzers. Possible production technologies must be subjected to screening, including an analysis of the advantages and disadvantages they offer. This evaluation must then be used as a basis for identifying strategically relevant research and development fields. When screening the technologies, researchers must quantify them in terms of the entire range from “cost intensive and highly accurate” to “optimized costs and adequate performance.” This should result in various solutions representing all the areas where conflict can arise between high levels of functional integration and components that are easy to manufacture. The results will

17.5

Possible development paths for a systemic road map

461

then be supplemented by analyses of the availability of the materials and recycling strategies and by ongoing consideration of additional environmental and economic factors. Since intense international competition is expected, there will be a great deal of pressure to innovate in the context of current and future electrolysis technologies. Research and industry must collaborate closely in this process from the outset, in order to ensure that implementation takes place as rapidly as required.

17.5.3

Systemic road map

Developing a systemic road map as part of a joint industry and applied research project is a vital step on the road to upscaling electrolyzer production, which is ultimately necessary to enable market ramp-up for green hydrogen. This road map must cover the following courses of action: 1. Formulating requirements specifications that consolidate ongoing activities and research, development and industrialization fields that have yet to be addressed in order to enable scaling of the manufacturing processes for existing products (route A) 2. Aligning technical feasibility (e.g., batch size, quality) with the market requirements that are expected to arise during market ramp-up; synchronizing production technologies with market requirements in terms of technical and economic parameters (route A); assessing the extent to which market ramp-up can be achieved by 2030 using existing electrolyzers 3. Initiating the evolution process (route B) with the goal of offering a range of highly scalable components and systems with costs and quality levels that correspond to international competition in the area of green hydrogen and other energy carriers 4. Developing a value chain with functional supply structures to facilitate incremental implementation of the new solutions within existing manufacturing processes Ongoing funding activities are currently focusing on route A primarily, with the aim of upscaling existing technologies. This activity, which has a direct impact, must be followed by evolution-focused funding activities that coordinate all areas involved, so as to harness the existing potential of electrolyzer technologies in such a way that they are capable of competing at a global level in terms of performance

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and cost structures. However, this cannot be achieved through the currently ongoing initiatives alone. As such, it is advisable to follow the course of action laid out in route B, namely developing a set of initiatives comprised of not only research and development activities but also other elements that are required to achieve the necessary large-scale production capacity.

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Glossar

3D Three-dimensional AEL Alkaline electrolysis AEM Anion exchange membrane AEMEL AEM electrolysis Blue hydrogen Hydrogen produced via carbon capture and storage (CSS); Carbon neutral, provided no CO2 passes into the atmosphere during production BPP Bipolar plate CapEx Capital expenditure CCM Catalyst-coated membrane CCS/CCU Carbon capture and storage/utilization CRC Collaborative research center CSC Cathode-supported cell Digital twin Virtual representation of a production unit or chain E-fuels (also synfuels) Synthetic fuel; long-chain hydrocarbons that do not differ from conventional fuels at a technical level; produced based on hydrogen Energy density, volumetric Measure of the amount of energy a substance contains per unit of spatial volume ESC Electrolyte-supported cell F Faraday constant (F D 96:485 C/mol) Fuel cell A device that produces electricity by means of an electrochemical reaction rather than combustion Gas manifold Gas distribution system; a group of gas cylinders connected in series; the gas is carried to a system or building via a pipeline Specifically: The title of the natural gas pipeline between the UK and the Netherlands GDL Gas diffusion layer GHG emissions Greenhouse gas emissions Gravimetric energy density or specific energy: Measure of the amount of energy in a substance per unit of mass (J/kg) © Springer Nature Switzerland AG 2022 R. Neugebauer (Ed.), Hydrogen Technologies, https://doi.org/10.1007/978-3-031-22100-2

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Glossar

Gray hydrogen Produced from fossil-based energy sources such as a natural gas or during industry processes; not carbon neutral Green hydrogen Hydrogen produced via electrolysis, using electricity from renewable energy sources (power-to-gas); carbon neutral HER Hydrogen evolution reaction HHV Higher heating value HT- high-temperature HTEL High-temperature electrolysis Hydrogen production costs Expenses incurred in producing hydrogen Interconnector Cross-border power grid coupling point; Power grids and gas pipelines that cross national borders LHV Lower heating value Linepack Volume of gas stored in the pipeline LT- Low-temperature MEA Membrane electrode assembly OER Oxygen evolution reaction OpEx Operational expenditure PCCEL Proton-conducting ceramic electrolysis PEC Photoelectrochemical cell; also photocatalytic PEM Proton exchange membrane PEMEL PEM electrolysis Petawatt-hours 1 quadrillion watt-hours or 1 trillion kilowatt-hours, 1012 kWh PFSA Perfluorosulfonic acids (ionomer type for membranes) PGM Precious metal group pH Negative decadic logarithm of proton activity (logŒ”  C.HC /) Power-to-gas (PtG, P2G) The use of power to produce gases Power-to-X technologies (PtX technologies) Power is used to produce gases (power-to-gas), heat (power-to-heat) or liquid energy carriers (power-to-liquid) PTL Porous transport layer Renewable energy Energy generated from renewable sources rWGS Reverse water-gas shift reaction ScSZ Scandia-stabilized zirconia Smart grid An electrical grid controlled via digital technology; improving load balancing through IT and control system engineering innovations SOEL Solid oxide electrolysis SOFC Solid oxide fuel cell Synfuels (also e-fuels) Synthetic fuel; long-chain hydrocarbons that do not differ from conventional fuels at a technical level; produced based on hydrogen

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469

TRL Technology readiness level; a scale for evaluating the development stage that a new technology has reached, ranging from 1 (Basic Technology Research) to 9 (System Test, Launch & Operations) Turquoise hydrogen Hydrogen produced through thermal process whereby methane is broken down to produce solid carbon and hydrogen (methane pyrolysis). Only carbon neutral if the high-temperature reactor is operated using renewable energy and the carbon sequestration is permanent YSZ Yttrium-stabilized zirconium dioxide