Publications

Predicting lower flammability limits (LFL) of hydrogen has become an ever-important task for safety of nuclear industry. While numerous experimental studies have been conducted LFL results applicable for the harsh environment are still lack of information. Our aim is to develop a calculated non-adiabatic flame temperature (CNAFT) model to better predict LFL of hydrogen mixtures in nuclear power plant. The developed model is unique for incorporating radiative heat loss during flame propagation using the CNAFT coefficient derived through previous studies of flame propagation. Our new model is more consistent with the experimental results for various mixtures compared to the previous model which relied on calculated adiabatic flame temperature (CAFT) to predict the LFL without any consideration of heat loss. Limitation of the previous model could be explained clearly based on the CNAFT coefficient magnitude. The prediction accuracy for hydrogen mixtures at elevated initial temperatures and high helium content was improved substantially. The model reliability was confirmed for H2-air mixtures up to 300 C and H2-air-He mixtures up to 50 vol % helium concentration. Therefore the CNAFT model developed based on radiation heat loss is expected as the practical method for predicting LFL in hydrogen risk analysis.

Recent years have seen a growing interest in water electrolysis as a way to store renewable electric energy into chemical energy through hydrogen production. However today the share of renewable energy is still limited and there is the need to have a continuous use of H2 for industrial chemicals applications. Firstly the paper discusses the use of electrolysis - connected to a conventional grid - for a continuous H2 production in terms of associated CO2 emissions and compares such emissions with conventional methane steam reforming (MSR). Therefore it explores the possibility to use electrical methane steam reforming (eMSR) as a way to reduce the CO2 emissions. As a way to have zero emissions carbon mineralization of CO2 is coupled - instead of in-situ carbon capture and storage technology (CCS) - to eMSR; associated relevant cost of production is evaluated for different scenarios. It appears that to minimize such production cost carbonate minerals must be reused in the making of other industrial products since the amount of carbonates generated by the process is quite significant.

Hydrogen will become a dominant energy carrier in the future and the efficiency and lifetime cost of its production through water electrolysis is a major research focus. Alongside efforts to offer optimum solutions through plant design and sizing it is also necessary to develop a flexible virtualised replica of renewable hydrogen plants that not only models compatibility with the “plug-and-play” nature of many facilities but that also identifies key elements for optimisation of system operation. This study presents a model for a renewable hydrogen production plant based on real-time historical and present-day datasets of PV connected to a virtualised grid-connected AC microgrid comprising different technologies of batteries electrolysers and fuel cells. Mathematical models for each technology were developed from chemical and physical metrics of the plant. The virtualised replica is the first step toward the implementation of a digital twin of the system and accurate validation of the system behaviour when updated with real-time data. As a case study a solar hydrogen pilot plant consisting of a 60 kW Solar PV a 40 kW PEM electrolyser a 15 kW LIB battery and a 5 kW PEM fuel cell were simulated and analysed. Two effective operational factors on the plant's performance are defined: (i) electrolyser power settings to determine appropriate hydrogen production over twilight periods and/or overnight and (ii) a user-defined minimum threshold for battery state of charge to prevent charge depletion overnight if the electrolyser load is higher than its capacity. The objective of this modelling is to maximise hydrogen yield while both loss of power supply probability (LPSP) and microgrid excess power are minimised. This analysis determined: (i) a hydrogen yield of 38e39% from solar DC energy to hydrogen energy produced (ii) an LPSP <2.6 104 and (iii) < 2% renewable energy lost to the grid as excess electricity for the case study.

The publication gives an overview of the production costs of synthetic methane in a Power-to-Gas process. The production costs depend in particularly on the electricity price and the full load hours of the plant sub-systems electrolysis and methanation. The full-load hours of electrolysis are given by the electricity supply concept. In order to increase the full-load hours of methanation the size of the intermediate hydrogen storage tank and the size of the methanation are optimised on the basis of the availability of hydrogen. The calculation of the production costs for synthetic methane are done with economics for 2030 and 2050 and the expenditures are calculated for one year of operation. The sources of volume of purchased electricity are the short-term market long-term contracts direct-coupled renewable energy sources or seasonal use of surpluses. Gas sales are either traded on the short-term market or guaranteed by long-term contracts. The calculations show that an intermediate storage tank for hydrogen adjustment of the methanation size and operating electrolysis and methanation separately increase the workload of the sub-system methanation. The gas production costs can be significantly reduced. With the future expected development of capital expenditures operational expenditure electricity prices gas costs and efficiencies an economic production of synthetic natural gas for the years 2030 especially for 2050 is feasible. The results show that Power-to-Gas is an option for long-term large-scale seasonal storage of renewable energy. Especially the cases with high operating hours for the sub-system methanation and low electricity prices show gas production costs below the expected market prices for synthetic gas and biogas.

This work reports a detailed chemical looping investigation of strontium ferrite (SrFeO_3−δ) a material with the perovskite structure type able to donate oxygen and stay in a nonstoichiometric form over a broad range of oxygen partial pressures starting at temperatures as low as 250°C (reduction in CO measured in TGA). SrFeO_3−δ is an economically attractive simple but remarkably stable material that can withstand repeated phase transitions during redox cycling. Mechanical mixing and calcination of iron oxide and strontium carbonate was evaluated as an effective way to obtain pure SrFeO_3−δ. In–situ XRD was performed to analyse structure transformations during reduction and reoxidation. Our work reports that much deeper reduction from SrFeO_3−δ to SrO and Fe is reversible and results in oxygen release at a chemical potential suitable for hydrogen production. Thermogravimetric experiments with different gas compositions were applied to characterize the material and evaluate its available oxygen capacity. In both TGA and in-situ XRD experiments the material was reduced below δ=0.5 followed by reoxidation either with CO₂ or air to study phase segregation and reversibility of crystal structure transitions. As revealed by in-situ XRD even deeply reduced material regenerates at 900°C to SrFeO_3−δ with a cubic structure. To investigate the catalytic behaviour of SrFeO_3−δ in methane combustion experiments were performed in a fluidized bed rig. These showed SrFeO_3−δ donates O₂ into the gas phase but also assists with CH4 combustion by supplying lattice oxygen. To test the material for combustion and hydrogen production long cycling experiments in a fluidized bed rig were also performed. SrFeO3−δ showed stability over 30 redox cycles both in experiments with a 2-step oxidation performed in CO₂ followed by air as well as a single step oxidation in CO₂ alone. Finally the influence of CO/CO₂ mixtures on material performance was tested; a fast and deep reduction in elevated pCO₂ makes the material susceptible to carbonation but the process can be reversed by increasing the temperature or lowering pCO₂.

This paper analyses the feasibility of power-to-gas in electricity markets dominated by renewables. The business case of a power-to-gas plant that is producing hydrogen is evaluated by determining the willingness to pay for electricity and by comparing this to the level and volatility of electricity prices in a number of European day-ahead markets. The short-term willingness to pay for electricity depends on the marginal costs and revenues of the plant while the long-term willingness to pay for electricity also takes into account investment and yearly fixed operational costs and therefore depends on the expected number of operating hours. The latter ultimately determines whether or not large-scale investments in the power-to-gas technology will take place.<br/>We find that power-to-gas plants are not profitable under current market conditions: even under the most optimistic assumptions for the cost and revenue parameters power-to-gas plants need to run for many hours during the year at very low prices (i.e. the long-term willingness to pay for electricity is very low) that do not currently exist in Europe. In an optimistic future scenario regarding investment costs efficiency and revenues of power-to-gas however the long-term willingness to pay for electricity is higher than the lowest recently observed day-ahead electricity prices. When prices remain at this low level investments in power-to-gas can thus become profitable.

The document provides information on safety planning implementation and reporting for projects involving hydrogen and/or fuel cell technologies. It does not intend to replace or contradict existing regulations which prevail under all circumstances. Neither is it meant to conflict with relevant international or national standards or to replace existing company safety policies codes and procedures. Instead this guidance document aims to assist projects and project partners in identifying hazards and associated risks in prevention and/or mitigation of them through a proper safety plan in implementing the safety plan and reporting safety related events. This shall help in safely delivering the project and ultimately producing inherently safer systems processes and infrastructure.

A viable hydrogen infrastructure is one of the main challenges for fuel cells in mobile applications. Several studies have investigated the most cost-efficient hydrogen supply chain structure with a focus on hydrogen transportation. However supply chain models based on hydrogen produced by electrolysis require additional seasonal hydrogen storage capacity to close the gap between fluctuation in renewable generation from surplus electricity and fuelling station demand. To address this issue we developed a model that draws on and extends approaches in the literature with respect to long-term storage. Thus we analyse Liquid Organic Hydrogen Carriers (LOHC) and show their potential impact on future hydrogen mobility. We demonstrate that LOHC-based pathways are highly promising especially for smaller-scale hydrogen demand and if storage in salt caverns remains uncompetitive but emit more greenhouse gases (GHG) than other gaseous or hydrogen ones. Liquid hydrogen as a seasonal storage medium offers no advantage compared to LOHC or cavern storage since lower electricity prices for flexible operation cannot balance the investment costs of liquefaction plants. A well-to-wheel analysis indicates that all investigated pathways have less than 30% GHG-emissions compared to conventional fossil fuel pathways within a European framework.

The volatility of renewable energy sources (RES) poses a growing problem for operation of electricity grids. In contrary the necessary decarbonisation of sectors such as heat supply and transport requires a rapid expansion of RES. Load management in the context of power-to-heat systems can help to simultaneously couple the electricity and heat sectors and stabilise the electricity grid thus enabling a higher share of RES. In addition power-to-hydrogen offers the possibility of long-term energy storage options. Within this work we present a novel optimization approach for heat pump operation with the aim to counteract the volatility and enable a higher usage of RES. For this purpose a detailed simulation model of buildings and their energy supply systems is created calibrated and validated based on a plus energy settlement. Subsequently the potential of optimized operation is determined with regard to PV and small wind turbine self-consumption. In addition the potential of seasonal hydrogen storage is examined. The results show that on a daily basis a 33% reduction of electricity demand from grid is possible. However the average optimization potential is reduced significantly by prediction inaccuracy. The addition of a hydrogen system for seasonal energy storage basically eliminates the carbon dioxide emissions of the cluster. However this comes at high carbon dioxide prevention costs of 1.76 e kg−1 .

This study seeks to answer a simple question: will we have enough renewable electricity to meet all of the EU's decarbonisation objectives and if not what should be the priorities and how to address the remaining needs for energy towards carbon neutrality? Indeed if not the policy push for green hydrogen would not be covered by enough green electricity to match the “energy efficiency and electrification first” approach outlined in the system integration communication and a prioritization of green electricity uses complemented by other solutions (import of green electricity or sustainable fuels CCS...) would be advisable [1]. On one hand we show that the principle “Energy efficiency and electrification first” results in an electricity demand which will be very difficult to satisfy domestically with renewable energy. On the other hand green hydrogen and other sustainable fuels will be needed for a carbon neutral industry for the replacement of the fuel for aviation and navigation and as strategic green energy reserves. The detailed modelling of these interactions is challenging given the large uncertainties on technology and infrastructure development. Therefore we offer a “15 minutes” decarbonization scenario based on general and transparent technical considerations and very straightforward “back-of-envelope” calculations. This working paper contains the calculations and assumptions in support of the accompanying policy brief with the same title which focuses instead on the main take-aways.