Switzerland

Green hydrogen i.e. produced from renewable resources is attracting attention as an alternative fuel for the future of heavy road transport and long-distance driving. However the benefits linked to zero pollution at the usage stage can be overturned when considering the upstream processes linked to the raw materials and energy requirements. To better understand the global environmental implications of fuelling heavy transport with hydrogen we quantified the environmental impacts over the full life cycle of hydrogen use in the context of the Planetary Boundaries (PBs). The scenarios assessed cover hydrogen from biomass gasification (with and without carbon capture and storage [CCS]) and electrolysis powered by wind solar bioenergy with CCS nuclear and grid electricity. Our results show that the current diesel-based-heavy transport sector is unsustainable due to the transgression of the climate change-related PBs (exceeding standalone by two times the global climate-change budget). Hydrogen-fuelled heavy transport would reduce the global pressure on the climate change-related PBs helping the transport sector to stay within the safe operating space (i.e. below one-third of the global ecological budget in all the scenarios analysed). However the best scenarios in terms of climate change which are biomass-based would shift burdens to the biosphere integrity and nitrogen flow PBs. In contrast burden shifting in the electrolytic scenarios would be negligible with hydrogen from wind electricity emerging as an appealing technology despite attaining higher carbon emissions than the biomass routes

Metal hydrides are known as a potential efficient low-risk option for high-density hydrogen storage since the late 1970s. In this paper the present status and the future perspectives of the use of metal hydrides for hydrogen storage are discussed. Since the early 1990s interstitial metal hydrides are known as base materials for Ni – metal hydride rechargeable batteries. For hydrogen storage metal hydride systems have been developed in the 2010s [1] for use in emergency or backup power units i. e. for stationary applications.<br/>With the development and completion of the first submarines of the U212 A series by HDW (now Thyssen Krupp Marine Systems) in 2003 and its export class U214 in 2004 the use of metal hydrides for hydrogen storage in mobile applications has been established with new application fields coming into focus.<br/>In the last decades a huge number of new intermetallic and partially covalent hydrogen absorbing compounds has been identified and partly more partly less extensively characterized.<br/>In addition based on the thermodynamic properties of metal hydrides this class of materials gives the opportunity to develop a new hydrogen compression technology. They allow the direct conversion from thermal energy into the compression of hydrogen gas without the need of any moving parts. Such compressors have been developed and are nowadays commercially available for pressures up to 200 bar. Metal hydride based compressors for higher pressures are under development. Moreover storage systems consisting of the combination of metal hydrides and high-pressure vessels have been proposed as a realistic solution for on-board hydrogen storage on fuel cell vehicles.<br/>In the frame of the “Hydrogen Storage Systems for Mobile and Stationary Applications” Group in the International Energy Agency (IEA) Hydrogen Task 32 “Hydrogen-based energy storage” different compounds have been and will be scaled-up in the near future and tested in the range of 500 g to several hundred kg for use in hydrogen storage applications.

Power-to-fuel systems via solid-oxide electrolysis are promising for storing excess renewable electricity by efficient electrolysis of steam (or co-electrolysis of steam and CO₂) into hydrogen (or syngas) which can be further converted into synthetic fuels with plant-wise thermal integration. Electrolysis stack performance and durability determine the system design performance and long-term operating strategy; thus solid-oxide electrolyzer based power-to-fuels were investigated from the stack to system levels. At the stack level the data from a 6000-h stack testing under laboratory isothermal conditions were used to calibrate a quasi-2D model which enables to predict practical isothermal stack performance with reasonable accuracy. Feasible stack operating windows meeting various design specifications (e.g. specific syngas composition) were further generated to support the selection of operating points. At the system level with the chosen similar stack operating points various power-to-fuel systems including power-to-hydrogen power-to-methane power-to-methanol (dimethyl ether) and power-to-gasoline were compared techno-economically considering system-level heat integration. Several operating strategies of the stack were compared to address the increase in stack temperature due to degradation. The modeling results show that the system efficiency for producing H₂ methane methanol/dimethyl ether and gasoline decreases sequentially from 94% (power-to-H₂) to 64% (power-to-gasoline) based on a higher heating value. Co-electrolysis which allows better heat integration can improve the efficiency of the systems with less exothermic fuel-synthesis processes (e.g. methanol/dimethyl ether) but offers limited advantages for power-to-methane and power-to-gasoline systems. In a likely future scenario where the growing amount of electricity from renewable sources results in increasing periods of a negative electricity price solid oxide electrolyser based power-to-fuel systems are highly suitable for levelling the price fluctuations in an economic way.

Several countries have revised their targets in recent years to reach net-zero CO2 emissions across all sectors by 2050 and the transport sector is responsible for a significant share of these emissions. This study compares possible pathways to decarbonise the transport sector through electrification including passenger cars light commercial vehicles and heavy commercial vehicles. To do so we explore 125 scenarios by varying the share of battery and hydrogen-based fuel cell electric vehicles in each of the three categories above independently. We further model the decarbonisation of the industrial hydrogen demand using electrolysers with hydrogen storage. To explore the potential role of electric and hydrogen transport as well as their trade-offs we use GRIMSEL an open-source sector coupling energy system model of Switzerland which includes the residential commercial industrial and transport sectors with four energy carriers namely electricity heat hot water and hydrogen. The total costs are minimised from a social planner perspective. We find that the full electrification of the transport sector could lead on average to a 12% increase in costs by 2050 and 1.3 MtCO2/year which represents a 90% CO2 emissions reduction for the whole sector. Second the transport energy self-sufficiency (i.e. the share of domestic electricity generation in final transport demand) may reach up to 50% for the scenarios with the largest share of battery electric vehicles mainly due to a smaller energy demand than with hydrogen vehicles. Third more than three quarters of the industrial hydrogen production is met by local photovoltaic electricity coupled with battery at minimum costs i.e. green hydrogen. Finally the use of hydrogen as an energy carrier to store electricity over a long period is not cost-optimal.

The results shown in this paper extend our research group’s previous work which presents the theoretically achievable hydrogen engine-out NOeo x (H2-NOeo x ) Pareto front of a hydrogen hybrid electric vehicle (H2-HEV). While the Pareto front is calculated offline which requires significant computing power and time this work presents an online-capable algorithm to tackle the energy management of a H2-HEV with explicit consideration of the H2-NOeo x trade-off. Through the inclusion of realistic predictive data on the upcoming driving mission a model predictive control algorithm (MPC) is utilized to effectively tackle the conflicting goal of achieving low hydrogen consumption while simultaneously minimizing NOeo x . In a case study it is shown that MPC is able to satisfy user-defined NOeo x limits over the course of various driving missions. Moreover a comparison with the optimal Pareto front highlights MPC’s ability to achieve close-to-optimal fuel performance for any desired cumulated NOeo x target on four realistic routes for passenger cars.

Self-sufficiency of buildings with carbon emission reduction can be obtained thanks to the introduction of Photovoltaics systems coupled with Hydrogen seasonal storage. To be self-sufficient over the year the electricity converted to hydrogen by electrolysis during the sunny season can be re-used with the help of fuel cells during the winter season. This article is dealing with the dimensioning methodology of a solar PV hydrogen-electrochemical system for self-sufficient buildings. We introduce the case study of the first private building in western Switzerland that will be equipped with solar hydrogen storage. Calculation results of the dimensioning of the PV system with storage will be presented. The life cycle assessment and the calculations of the environmental indicators GWP and CED will be introduced.

In light of the Paris Agreement road-freight represents a critically difficult-to-abate sector. In order to meet the ambitious European transport sector emissions reduction targets a rapid transition to zero-carbon road-freight is necessary. However limited policy assessments indicate where and how to appropriately intervene in this sector. To support policy-makers in accelerating the zero-carbon road-freight transition this paper examines the relative cost competitiveness between commercial vehicles of varying alternative drive-technologies through a total cost of ownership (TCO) assessment. We identify key parameters that when targeted enable the uptake of these more sustainable niche technologies. The assessment is based on a newly compiled database of cost parameters which were triangulated through expert interviews. The results show that cost competitiveness for low- or zero-emission niche technologies in certain application segments and European countries is exhibited already today. In particular we find battery electric vehicles to show great promise in the light- and medium-duty segments but also in the heavy-duty long-haul segments in countries that have enacted targeted policy measures. Three TCO parameters drive this competitiveness: tolls fuel costs and CAPEX subsidies. Based on our analysis we propose that policy-makers target OPEX before CAPEX parameters as well utilize a mix of policy interventions to ensure greater reach increased efficiency and increased policy flexibility.

Building heating is one of the sectors for which multiple decarbonisation options exist and current geopolitical tensions provide urgency to design adequate regional policies. Heat pumps and hydrogen boilers alongside alternative district heating systems are the most promising alternatives. Although a host of city or country-level studies exist it remains controversial what role hydrogen should play for building heating in the European Union compared with electrification and how blue and green hydrogen differ in terms of costs and environmental impacts. This works assesses the optimal technology mix for staying within planetary boundaries and the influence of international cooperation and political restrictions. To perform the analysis a bottom-up optimisation model was developed incorporating life cycle assessment constraints and covering production storage transport of energy and carbon dioxide as well as grid and non-grid connected end-users of heat. It was found that a building heating system within planetary boundaries is feasible through large-scale electrification via heat pumps although at a higher cost than the current system with abatement costs of around 200 €/ton CO2. Increasing interconnector capacity or onshore wind energy is found to be vital to staying within boundaries. A strong trade-off for hydrogen was identified with blue hydrogen being cost-competitive but vastly unsustainable (when applied to heating) and green hydrogen being 2–3 times more expensive than electrification while still transgressing several planetary boundaries. The insights from this work indicate that heat pumps and renewable electricity should be prioritised over hydrogen-based heating in most cases and grid-stability and storage aspects explored further while revealing a need for policy instruments to mitigate increased costs for consumers.

The envisioned role of hydrogen in the energy transition – or the concept of a hydrogen economy – has varied through the years. In the past hydrogen was mainly considered a clean fuel for cars and/or electricity production; but the current renewed interest stems from the versatility of hydrogen in aiding the transition to CO2 neutrality where the capability to tackle emissions from distributed applications and complex industrial processes is of paramount importance. However the hydrogen economy will not materialise without strong political support and robust infrastructure design. Hydrogen deployment needs to address multiple barriers at once including technology development for hydrogen production and conversion infrastructure co-creation policy market design and business model development. In light of these challenges we have brought together a group of hydrogen researchers who study the multiple interconnected disciplines to offer a perspective on what is needed to deploy the hydrogen economy as part of the drive towards net-zero-CO2 societies. We do this by analysing (i) hydrogen end-use technologies and applications (ii) hydrogen production methods (iii) hydrogen transport and storage networks (iv) legal and regulatory aspects and (v) business models. For each of these we provide key take home messages ranging from the current status to the outlook and needs for further research. Overall we provide the reader with a thorough understanding of the elements in the hydrogen economy state of play and gaps to be filled.

Green hydrogen allows coupling renewable electricity to hard-to-decarbonize sectors such as long-distance transport and carbon-intensive industries in order to achieve net zero emissions. Evaluating the cost and value of power-to-gas is a major challenge owing to the spatial distribution and temporal variability of renewable electricity CO2 and energy demand. Here we propose a method based on geographic information system (GIS) and techno-economic modeling to: (i) compare the levelized cost and levelized value of power-to-gas across locations; (ii) identify potential hotspots for their future implementation in Switzerland; and (iii) set cost improvement targets as well as smart deployment strategies. Our method accounts for the spatial and temporal (both hourly and seasonal) availability of renewable electricity and CO2 sources as well as the presence of gas infrastructure heating networks oxygen and gas demand centers. We find that only green hydrogen plants connected directly to run-of-river hydropower plants are currently profitable in Switzerland (with NPV per CAPEX ranging between 2.3-5.6). However considering technological progress by 2050 a few green hydrogen plants deployed in the demand centers and powered by rooftop PV electricity will also become economically attractive. Moreover a few synthetic methane plants connected to run-of-river hydropower plants currently show slight profitability (NPV per CAPEX reaching values up to 1.3) and in 2050 (NPV per CAPEX up to 3.1) whereas those connected to rooftop PV will remain uneconomical even in 2050. Based on our findings we devise a long-term roadmap for policy makers and project developers to plan future green hydrogen projects. The proposed methodology which is applied to Switzerland can be extended to other countries.