Publications

A redox dual-flow battery is distinct from a traditional redox flow battery (RFB) in that the former includes a secondary energy platform in which the pre-charged electrolytes can be discharged in external catalytic reactors through decoupled redox-mediated hydrogen evolution reaction (HER) and oxygen evolution reaction (OER). The concept offers several advantages over conventional electrolysis in terms of safety durability modularity and purity. In this work we demonstrate a vanadium-manganese redox-flow battery in which Mn3+/Mn2+ and V3+/V2+ respectively mediate the OER and the HER in Mo2C-based and RuO2-based catalysts. The flow battery demonstrates an average energy efficiency of 68% at a current density of 50 mA ⋅ cm−2 (cell voltage = 1.92 V) and a relative energy density 45% higher than the conventional all-vanadium RFB. Both electrolytes are spontaneously discharged through redox-mediated HER and OER with a faradic efficiency close to 100%.

The dissemination of fuel-cell vehicles requires cost reduction of hydrogen refueling stations. The temperature of the supplied hydrogen has currently been cooled to approximately 40 C. This has led to larger equipment and increased electric power consumption. This study achieves a relaxation of the precooling temperature to the 20 C level while maintaining the refueling time. (1) Adoption of an MC formula that can flexibly change the refueling rate according to the precooling temperature. (2) Measurement of thermal capacity of refueling system parts and re-evaluation. Selection from multiple refueling control maps according to the dispenser design (Mathison et al. 2015). (3) Calculation of the effective thermal capacity and reselection of the map in real time when the line is cooled from refueling of the previous vehicle (Mathison and Handa 2015). (4) Addition of maps in which the minimum assumed pressures are 10 and 15 MPa. The new method is named MC Multi Map

Several North American utilities are planning to blend hydrogen into gas grids as a short‐ term way of addressing the scalable demand for hydrogen and as a long‐term decarbonization strat‐ egy for ‘difficult‐to‐electrify’ end uses. This study documents the impact of 0–30% hydrogen blends by volume on the performance emissions and safety of unadjusted equipment in a simulated use environment focusing on prevalent partially premixed combustion designs. Following a thorough literature review the authors describe three sets of results: operating standard and “ultra‐low NOx” burners from common heating equipment in “simulators” with hydrogen/methane blends up to 30% by volume in situ testing of the same heating equipment and field sampling of a wider range of equipment with 0–10% hydrogen/natural gas blends at a utility‐owned training facility. The equipment was successfully operated with up to 30% hydrogen‐blended fuels with limited visual changes to flames and key trends emerged: (a) a decrease in the input rate from 0 to 30% H2 up to 11% often in excess of the Wobbe Index‐based predictions; (b) NOx and CO emissions are flat or decline (air‐free or energy‐adjusted basis) with increasing hydrogen blending; and (c) a minor de‐ crease (1.2%) or increase (0.9%) in efficiency from 0 to 30% hydrogen blends for standard versus ultra‐low NOx‐type water heaters respectively.

This paper discusses the potential of green hydrogen production in a case study of a Slovenian hydro power plant. To assess the feasibility and eligibility of hydrogen production at the power plant we present an overview of current hydrogen prices and the costs of the power-to-gas system for green hydrogen production. After defining the production cost for hydrogen at the case study hydro power plant we elaborate on the profitability of hydrogen production over electricity. As hydrogen can be used as a sustainable energy vector in industry heating mobility and the electro energetic sectors we discuss the current competitiveness of hydrogen in the heating and transport sectors. Considering the current prices of different fuels it is shown that hydrogen can be competitive in the transport sector if it is unencumbered by various environmental taxes. The second part of the paper deals with hydrogen production in the context of secondary control ancillary service provided by a case study power plant. Namely hydrogen can be produced during the time period when there is no demand for extra electric power within a secondary control ancillary service and thus the economics of power plant operation can be improved.

Dedicated offshore wind farms for hydrogen production are a promising option to unlock the full potential of offshore wind energy attain decarbonisation and energy security targets in electricity and other sectors and cope with grid expansion constraints. Current knowledge on these systems is limited particularly the economic aspects. Therefore a new integrated and analytical model for viability assessment of hydrogen production from dedicated offshore wind farms is developed in this paper. This includes the formulae for calculating wind power output electrolysis plant size and hydrogen production from time-varying wind speed. All the costs are projected to a specified time using both Discounted Payback (DPB) and Net Present Value (NPV) to consider the value of capital over time. A case study considers a hypothetical wind farm of 101.3 MW situated in a potential offshore wind development pipeline off the East Coast of Ireland. All the costs of the wind farm and the electrolysis plant are for 2030 based on reference costs in the literature. Proton exchange membrane electrolysers and underground storage of hydrogen are used. The analysis shows that the DPB and NPV flows for several scenarios of storage are in good agreement and that the viability model performs well. The offshore wind farm – hydrogen production system is found to be profitable in 2030 at a hydrogen price of €5/kg and underground storage capacities ranging from 2 days to 45 days of hydrogen production. The model is helpful for rapid assessment or optimisation of both economics and feasibility of dedicated offshore wind farm – hydrogen production systems.

Energy system integration enables raising operational synergies by coupling the energy infrastructures for electricity methane and hydrogen. However this coupling reinforces the infrastructure interdependencies increasing the need for integrated modeling of these infrastructures. To analyze the cost-efficient sustainable and secure dispatch of applied large-scale energy infrastructures an extensive and non-linear optimization problem needs to be solved. This paper introduces a nested decomposition approach with three stages. The method enables an integrated and full-year consideration of large-scale multi-energy systems in hourly resolution taking into account physical laws of power flows in electricity and gas transmission systems as boundary conditions. For this purpose a zooming technique successively reduces the temporal scope while first increasing the spatial and last the technical resolution. A use case proves the applicability of the presented approach to large-scale energy systems. To this end the model is applied to an integrated European energy system model with a detailed focus on Germany in a challenging transport situation. The use case demonstrates the temporal regional and cross-sectoral interdependencies in the dispatch of integrated energy infrastructures and thus the benefits of the introduced approach.

Considering the imperative reduction in CO2 emissions both from household heating and hot water producing facilities one of the mainstream directions is to reduce hydrocarbons in combustibles by replacing them with hydrogen. The authors analyze condensing boilers operating when hydrogen is mixed with standard gaseous fuel (CH4 ). The hydrogen (H2 ) volumetric participation in the mixture is considered to vary in the range of 0 to 20%. The operation of the condensing boilers will be numerically modeled by computational programs and prior validated by experimental studies concluded in a European Certified Laboratory. The study concluded that an increase in the combustible flow with 16% will compensate the maximum H2 concentration situation with no other implications on the boiler’s thermal efficiency together with a decrease in CO2 emissions by approximately 7%. By assuming 0.9 (to/year/boiler) the value of CO2 emissions reduction for the condensing boiler determined in the paper and extrapolating it for the estimated number of boilers to be sold for the period 2019–2024 a 254700-ton CO2/year reduction resulted.

The concept of sector coupling has been gaining increased momentum in political discourses during 18 the past few years but it has only recently received the attention of international academics. The 19 private sector is particularly relevant to foster sector coupling through entrepreneurial action – 20 specifically innovative business models for more sustainable technologies are needed to promote a 21 transition towards more sustainability. So far however the literature on business models from a 22 sector coupling perspective is scarce yet strongly emerging. To address the identified research gaps 23 and enhance the current knowledge on the emerging hydrogen vehicle industry and sector coupling 24 this study adopts a qualitative and exploratory research approach and builds on information gained 25 in 103 semi-structured interviews to discuss emerging business models in Germany. In particular 33 26 business cases have been analyzed. Anchoring business model theory to the concept of sector 27 coupling this study identifies 12 business model archetypes in the emerging hydrogen vehicle 28 industry and its value chain. It can be shown that while the market is still emerging and the market 29 players are not defined and are evolving companies are currently engaged in finding their position 30 along the value chain fostering vertical integration and promoting cooperation between the 31 different sectors. While this study is relevant for both the academia and the industry it is particularly 2 32 interesting for policy makers shaping the future of sustainable development specifically considering 33 integrated energy systems.

The deployment of low-carbon hydrogen in gas grids comes with strategic benefits in terms of energy system integration and decarbonization. However hydrogen thermophysical properties substantially differ from natural gas and pose concerns of technical and regulatory nature. The present study investigates the blending of hydrogen into distribution gas networks focusing on the steady-state fluid dynamic response of the grids and gas quality compliance issues at increasing hydrogen admixture levels. Two blending strategies are analyzed the first of which involves the supply of NG–H2 blends at the city gate while the latter addresses the injection of pure hydrogen in internal grid locations. In contrast with traditional case-specific analyses results are derived from simulations executed over a large number (i.e. one thousand) of synthetic models of gas networks. The responses of the grids are therefore analyzed in a statistical fashion. The results highlight that lower probabilities of violating fluid dynamic and quality restrictions are obtained when hydrogen injection occurs close to or in correspondence with the system city gate. When pure hydrogen is injected in internal grid locations even very low volumes (1% vol of the total) may determine gas quality violations while fluid dynamic issues arise only in rare cases of significant hydrogen injection volumes (30% vol of the total).

Ammonia is one of the most commonly used feedstock chemicals globally. Therefore decarbonisation of ammonia production is of high relevance towards achieving a carbon neutral energy system. This study investigates the global potential of green ammonia production from semi-flexible ammonia plants utilising a cost-optimised configuration of hybrid PV-wind power plants as well as conversion and balancing technologies. The global weather data used is on an hourly time scale and 0.45◦ × 0.45◦ spatial resolution. The results show that by 2030 solar PV would be the dominating electricity generation technology in most parts of the world and the role of batteries would be limited while no significant role is found for hydrogen-fuelled gas turbines. Green ammonia could be generated at the best sites in the world for a cost range of 440–630 345–420 300–330 and 260–290 €/tNH3 in 2020 2030 2040 and 2050 respectively for a weighted average capital cost of 7%. Comparing this to the decade-average fossil-based ammonia cost of 300–350 €/t green ammonia could become cost-competitive in niche markets by 2030 and substitute fossil-based ammonia globally at current cost levels. A possible cost decline of natural gas and consequently fossil-based ammonia could be fully neutralised by greenhouse gas emissions cost of about 75 €/tCO2 by 2040. By 2040 green ammonia in China would be lower in cost than ammonia from new coal-based plants even at the lowest coal prices and no greenhouse gas emissions cost. The difference in green ammonia production at the least-cost sites in the world’s nine major regions is less than 50 €/tNH3 by 2040. Thus ammonia shipping cost could limit intercontinental trading and favour local or regional production beyond 2040.