Global hydrogen trade to meet the 1.5°C climate goal: Part II – Technology review of hydrogen carriers

By International Renewable Energy Agency IRENA

The report covers transformation from gaseous hydrogen to a suitable form to allow its transport and storage, its use in the process of transportation itself and its reconversion from the carrier back to pure hydrogen.

• Language: English
• Publisher: IRENA
• Release date: Apr 1, 2022
• ISBN: 9789292605001

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© IRENA 2022

Unless otherwise stated, material in this publication may be freely used, shared, copied, reproduced, printed and/or stored, provided that appropriate acknowledgement is given of IRENA as the source and copyright holder. Material in this publication that is attributed to third parties may be subject to separate terms of use and restrictions, and appropriate permissions from these third parties may need to be secured before any use of such material.

ISBN: 978-92-9260-431-8

eBook ISBN: 978-92-9260-500-1

Citation: IRENA (2022), Global hydrogen trade to meet the 1.5°C climate goal: Part II – Technology review of hydrogen carriers, International Renewable Energy Agency, Abu Dhabi.

Acknowledgements

The report was prepared by the IRENA Innovation and Technology Centre (IITC) led by Dolf Gielen. This report was authored by Herib Blanco, as part of the activities of the Power Sector Transformation team led by Emanuele Taibi under the guidance of Roland Roesch.

This report benefited from input and review of the following experts: Kevin Rouwenhorst (Ammonia Energy Association), Ed Frank (Argonne National Laboratory), Umberto Cardella (Cryomotive), Aparajit Pandey and Andreas Wagner (Energy Transitions Commission), Markus Albuscheit, Andreas Lehmann, Ralf Ott (Hydrogenious), Ilkka Hannula (International Energy Agency), Emanuele Bianco, Barbara Jinks, Paul Komor, and Emanuele Taibi (IRENA), Martin Lambert (Oxford Institute for Energy Studies), Cédric Philibert, Rafael d’Amore Domenech (Polytechnic University of Madrid).

The following experts provided support in validating some of the techno-economic data used in this report: Francesco Dolci and Eveline Weidner (Joint Research Center of the European Commission), David Franzmann, Heidi Heinrichs, and Jochen Linssen (Jülich Research Center), Thomas Hajonides van der Meulen (Netherlands Organization for Applied Scientific Research), Rafael Ortiz Cebolla, and Octavian Partenie (Vattenfall).

The report was edited by Justin French-Brooks.

Report available online: www.irena.org/publications

For questions or to provide feedback: [e-mail]

IRENA is grateful for the support of the Ministry of Economy, Trade and Industry (METI) of Japan in producing this publication.

Disclaimer

This publication and the material herein are provided as is. All reasonable precautions have been taken by IRENA to verify the reliability of the material in this publication. However, neither IRENA nor any of its officials, agents, data or other third-party content providers provides a warranty of any kind, either expressed or implied, and they accept no responsibility or liability for any consequence of use of the publication or material herein.

The information contained herein does not necessarily represent the views of all Members of IRENA. The mention of specific companies or certain projects or products does not imply that they are endorsed or recommended by IRENA in preference to others of a similar nature that are not mentioned. The designations employed and the presentation of material herein do not imply the expression of any opinion on the part of IRENA concerning the legal status of any region, country, territory, city or area or of its authorities, or concerning the delimitation of frontiers or boundaries.

TABLE OF CONTENTS

ABBREVIATIONS

EXECUTIVE SUMMARY

CONTEXT OF THIS REPORT AND WHAT TO EXPECT

1TECHNOLOGY PATHWAYS FOR INFRASTRUCTURE DEVELOPMENT

1.1 Overview of possible technologies for shipping

2AMMONIA

2.1 Technology status

2.2 Project pipeline

2.3 Conversion (ammonia synthesis)

2.4 Shipping

2.5 Reconversion (cracking)

3LIQUID HYDROGEN

3.1 Technology status

3.2 Project pipeline

3.3 Conversion (liquefaction)

3.4 Shipping

3.5 Reconversion (gasification)

4LIQUID ORGANIC HYDROGEN CARRIERS

4.1 Technology status

4.2 Project pipeline

4.3 Conversion (hydrogenation)

4.4 Shipping

4.5 Reconversion (dehydrogenation)

5HYDROGEN PIPELINES

5.1 Technology status

5.2 Project pipeline

5.3 Cost assessment

6COST COMPARISON BETWEEN ALTERNATIVES

6.1 Comparing hydrogen carriers for shipping

6.2 Comparing hydrogen pathways (shipping vs pipelines)

6.3 Potential technology development to 2050 and uncertainties

REFERENCES

APPENDIX: INTERNATIONAL AND NATIONAL STANDARDS TO BE CONSIDERED DURING THE DESIGN OF LIQUID HYDROGEN CARRIERS

FIGURES

FIGURE 0.1. Most cost-effective hydrogen transport pathway in 2050 as a function of project size and distance

FIGURE 0.2. Transport cost breakdown by carrier and stage for 2030 (left) and evolution towards 2050 (right)

FIGURE 0.3. Scope of this report series in the broader context of IRENA publications

FIGURE 1.1. Hydrogen transport cost based on distance and volume

FIGURE 1.2. Energy density and specific energy for various fuels and energy storage systems

FIGURE 1.3. Processing steps of the hydrogen value chain for each of the hydrogen transport options.

FIGURE 2.1. Global trade flows of ammonia in 2019 (Mt)

FIGURE 2.2. Ports with loading and unloading facilities for ammonia

FIGURE 2.3. Projected green ammonia capacity according to project announcements

FIGURE 2.4. Primary resources and conversion steps in various generations of ammonia production technologies

FIGURE 2.5. CAPEX for ammonia synthesis and auxiliary equipment

FIGURE 2.6. Energy consumption for ammonia synthesis and auxiliary equipment (excluding hydrogen production)

FIGURE 2.7. Levelised cost of ammonia sensitivity to minimum turndown and ramping rate of the synthesis process and air separation unit

FIGURE 2.8. Specific investment cost for an ammonia carrier

FIGURE 2.9. Specific investment cost of an ammonia storage tank

FIGURE 2.10. Efficiency of fuel cells and ICEs as a function of load compared to peak efficiency

FIGURE 2.12. Equilibrium concentrations for ammonia, nitrogen and hydrogen for various process conditions

FIGURE 2.13. CAPEX for ammonia cracking based on various literature estimates (left) and as a function of plant size (right)

FIGURE 2.14. Use of the thermal heat from a heater for a 200 tH 2 /d ammonia cracker

FIGURE 2.15. Energy consumption for ammonia cracking

FIGURE 3.1. Global hydrogen liquefaction capacity growth since the 1960s

FIGURE 3.2. Hydrogen value chain in the HySTRA project from Australia to Japan

FIGURE 3.3. Minimum liquefaction energy consumption as a function of inlet pressure

FIGURE 3.4. Breakdown of exergy losses for a Claude cycle with mixed refrigerant pre-cooling

FIGURE 3.5. Energy consumption for operating plants, conceptual designs and ideal cycles for hydrogen liquefaction

FIGURE 3.6. Specific energy consumption for liquefaction as a function of plant capacity

FIGURE 3.7. Specific energy consumption for liquefaction as a function of plant load

FIGURE 3.8. Specific CAPEX for hydrogen liquefaction as a function of plant capacity

FIGURE 3.11. CAPEX breakdown for a 3 x 200 t/d hydrogen liquefaction facility

FIGURE 3.13. Specific CAPEX of liquid hydrogen storage and uncertainty from literature

FIGURE 3.14. Specific investment cost for a liquid hydrogen carrier as a function of ship size

FIGURE 3.15. Specific investment cost of liquid hydrogen regasification

FIGURE 3.16. Cost breakdown for a 150 t/d liquid hydrogen terminal (excluding storage)0

FIGURE 4.1. Main steps and conditions of the hydrogen transport with LOHC

FIGURE 4.2. Current project pipeline for Hydrogenious

FIGURE 4.3. Renewable methanol production cost as a function of hydrogen and CO 2 cost

FIGURE 4.4. Specific investment cost for hydrogenation for different LOHC

FIGURE 4.5. Investment cost for an LOHC vessel as a function of ship size

FIGURE 4.6. Equilibrium conversion for LOHC dehydrogenation as a function of pressure and temperature

FIGURE 4.7. Specific investment cost for LOHC dehydrogenation

FIGURE 5.1. Total natural gas transmission network length by country.

FIGURE 5.2. CO 2 mitigation cost for different combinations of natural gas and hydrogen prices

FIGURE 5.3. Levelised cost of hydrogen separation from blended mix for different technologies and conditions

FIGURE 5.4. Range of specific costs for new hydrogen pipeline as a function of inner diameter

FIGURE 5.5. Capital cost of a hydrogen pipeline (left), and total transport cost (right) by cost component

FIGURE 6.1. Transport cost breakdown by hydrogen carrier, scenario and cost component in 2050

FIGURE 6.2. Capital cost breakdown by hydrogen carrier, scenario and cost component in 2050

FIGURE 6.3. Transport cost by carrier as a function of project size for a fixed distance of 5 000 km in 2050

FIGURE 6.4. Transport cost by carrier as a function of distance for a fixed capacity of 1.5 MtH 2 /yr in 2050

FIGURE 6.5. Lowest-cost carrier in 2050 for a variable project size and transport distance for an Optimistic scenario (solid line) and Pessimistic scenario (dashed line)

FIGURE 6.6. Transport cost by pathway as a function of project size for a fixed distance of 5 000 km in 2050

FIGURE 6.7. Transport cost by pathway as a function of distance for a fixed project size of 1.5 MtH 2 /yr in 2050

FIGURE 6.8. Lowest-cost pathway for a variable project size and transport distance in 2050, Optimistic scenario (solid line) and Pessimistic scenario (dashed line)

FIGURE 6.9. Lowest-cost carrier in 2050 for a variable project size and transport distance with a cost of capital of 3%

FIGURE 6.10. Cost pathway from today until 2050 and contributors to cost decrease for ammonia (top), LOHC (middle) and liquid hydrogen (bottom)

TABLES

TABLE 1.1. Advantages and disadvantages of each potential hydrogen carrier

TABLE 2.1. Volume and weight of possible different components of a 2 500 TEU container ship of 13.5 MW

TABLE 3.1. Estimated material inventory for a 50 t/d liquefaction plant

TABLE 3.2. Comparison between direct hydrogen use in fuel cells and ICEs

TABLE 3.3. Port criteria for liquid hydrogen bunkering (adapted from LNG)

TABLE 3.4. Specifications for a 1 250 m ³ liquid hydrogen carrier

TABLE 3.5. Energy consumption for liquid hydrogen regasification

TABLE 4.1. Typical conditions for hydrogenation and chemical properties of LOHC

TABLE 4.2. Energy consumption for hydrogenation of LOHC

TABLE 4.3. Prime mover efficiencies and heat recovery systems for LOHC ships

TABLE 4.4. Dimensions for different types of tankers

TABLE 4.5. Typical conditions for dehydrogenation and chemical properties of LOHC

TABLE 6.1. Cost scaling exponents for hydrogen carriers by step of the value chain

TABLE 6.2. Cost scaling exponents for hydrogen carriers by step of the value chain

TABLE 6.3. Technology performance from 2030 to 2050 for hydrogen carriers

BOXES

BOX 2.1. Shipping cost components and types of contract for operation

BOX 3.1. Lessons from LNG for hydrogen liquefaction

BOX 3.2. Lessons from LNG for liquid hydrogen transport

BOX 3.3. Lessons from LNG for cold recovery

ABBREVIATIONS

Units of measure

EXECUTIVE SUMMARY

Hydrogen can be transported across long-distances by pipeline or by ship. This report compares the transport of hydrogen by pipeline as compressed gaseous hydrogen with three shipping pathways: ammonia, liquid hydrogen and liquid organic hydrogen carriers (LOHC). The focus is on hydrogen transport rather than the transport of commodities made using hydrogen (e.g. iron), noting that ammonia can be both a hydrogen carrier and directly used as a feedstock or fuel for different applications. Carbon-containing carriers (such as methanol or methane) are excluded since they would need a sustainable carbon source (biogenic or directly from air) to be considered renewable, and the cost advantages are not sufficient to compensate for this downside. The scope covers transformation from gaseous hydrogen to a suitable form to allow its transport and storage, its use in the transport step itself, and its reconversion from the carrier back to pure hydrogen (if needed).

There are two main parameters that define the transport cost: the size of the production facility and the transporting distance. The size defines the economies of scale, and the larger the production facility’s size the lower the specific cost. The largest available benefit is achieved with project sizes of 0.4, 0.4 and 0.95 MtH2/yr for LOHC, ammonia and liquid hydrogen respectively. To put these values into perspective, 1 MtH2/yr would be equivalent to a 10 GW electrolyser running for about 60% of the year, or the hydrogen consumption of five commercial ammonia plants. These sizes translate into a cost reduction of up to 80% compared to today’s pilot projects. Figure 0.1 shows how the technology pathways compare in 2050. Identifying the most attractive pathway by 2050 allows the greatest benefits in the long term to be identified and defines where to focus short-term efforts.

Ammonia ships are the most attractive for a wide range of combinations. The shipping cost is relatively small compared to the cost of conversion to and from ammonia and the ammonia storage cost. Thus, longer distances have limited impact on the total cost, making it more attractive as the distance increases. The cost for pipelines, on the other hand, scales linearly with distance, which is why they are the cheapest option for short distances of up to 3 000 km. The cost of pipeline transport varies according to the flow transported – double the diameter means roughly double the cost but four times the flow, which reduces the specific cost per unit of hydrogen transported. For this reason, the distance at which pipelines are the most attractive expands as the project size increases. In cases where repurposed pipelines are possible (e.g. North America, Europe or eastern China), the investment cost can be 65-94% lower than the cost of a new hydrogen pipeline. This significantly expands the distance along which pipelines are attractive to up to 8 000 km. This is almost double the distance from Ukraine to Spain or from the east to the west coast of the United States. While attractive in terms of cost, it is limited by the existing infrastructure and relies upon a simultaneous (both geographically and in time) decrease in methane demand. Even for distance and flow combinations where ships are the most attractive, pipelines can still play a role in transporting the hydrogen inland to demand centres that are not on the coastline.

The main disadvantage of shipping liquid hydrogen lies in the low temperature requirement (-253°C). This translates into high energy consumption for liquefaction (currently equivalent to 30-36% of the energy contained in the hydrogen) and a high cost for all the equipment, since it needs to be designed for the cryogenic conditions. This makes liquid hydrogen attractive for relatively short distances as longer routes would require more ships to maintain a continuous flow. Short distances are the also