Publications

Austria is committed to the net-zero climate goal along with the European Union. This requires all sectors to be decarbonized. Hereby hydrogen plays a vital role as stated in the national hydrogen strategy. A report commissioned by the Austrian government predicts a minimum hydrogen demand of 16 TWh per year in Austria in 2040. Besides hydrogen imports domestic production can ensure supply. Hence this study analyses the levelized cost of hydrogen for an off-grid production plant including a proton exchange membrane electrolyzer wind power and solar photovoltaics in Austria. In the first step the capacity factors of the renewable electricity sources are determined by conducting a geographic information system analysis. Secondly the levelized cost of electricity for wind power and solarphotovoltaics plants in Austria is calculated. Thirdly the most cost-efficient portfolio of wind power and solar photovoltaics plants is determined using electricity generation profiles with a 10-min granularity. The modelled system variants differ among location capacity factors of the renewable electricity sources and the full load hours of the electrolyzer. Finally selected variables are tested for their sensitivities. With the applied model the hydrogen production cost for decentralized production plants can be calculated for any specific location. The levelized cost of hydrogen estimates range from 3.08 EUR/kg to 13.12 EUR/kg of hydrogen whereas it was found that the costs are most sensitive to the capacity factors of the renewable electricity sources and the full load hours of the electrolyzer. The novelty of the paper stems from the model applied that calculates the levelized cost of renewable hydrogen in an off-grid hydrogen production system. The model finds a cost-efficient portfolio of directly coupled wind power and solar photovoltaics systems for 80 different variants in an Austria-specific context.

This study aims to provide a comprehensive review of the potential of geothermal energy for producing hydrogen with a focus on the Australian context where low-temperature geothermal reservoirs particularly hot sedimentary aquifers (HSAs) are prevalent. The work includes an overview of various geothermal technologies and hydrogen production routes and evaluates potential alternatives for hydrogen production in terms of energy and exergy efficiency economic performance and hydrogen production rate. Values for energy efficiency are reported in the literature to range from 3.51 to 47.04% 7.4–67.5% for exergy efficiency a cost ranging from 0.59 to 5.97 USD/kg of hydrogen produced and a hydrogen production rate ranging from 0.11 to 5857 kg/h. In addition the article suggests and evaluates multiple metrics to appraise the feasibility of HSAs geothermal reservoirs with results tailored to Australia but that can be extended to jurisdictions with similar conditions worldwide. Furthermore the performance of various hydrogen production systems is investigated by considering important operating conditions. Lastly the key factors and possible solutions associated with the hydrogeological and financial conditions that must be considered in developing hydrogen production using lowtemperature geothermal energy are summarised. This study shows that low-temperature HSAs (~100 ◦C) can still be used for hydrogen generation via supplying power to conventional electrolysis processes by implementing several improvements in heat source temperature and energy conversion efficiency of Organic Rankine Cycle (ORC) power plants. Geothermal production from depleted or even active oilfields can reduce the capital cost of a hydrogen production system by up to 50% due to the use of pre-existing wellbores under the right operating conditions. Thus the results of this study bring novel insights in terms of both the opportunities and the challenges in producing clean hydrogen from geothermal energy applicable not only to the hydro-geological and socio-economic conditions in Australia but also worldwide exploring the applicability of geothermal energy for clean hydrogen production with similar geothermal potential.

In this episode Tony Green Hydrogen Director at National Grid and John Williams Head of Hydrogen Expertise Cluster at AFRYManagement Consulting join us to discuss the challenges in implementing hydrogen. Tony is involved in two exciting hydrogen projects: FutureGrid andProject Union. FutureGrid involves building a facility to create a representative whole-network to trial hydrogen. Project Union will develop a UK hydrogen ‘backbone’ joining together clusters around the country potentially creating a 2000km hydrogen network.

In addition to discussing these projects this episode will explore the following issues:

♦ Managing the transition and challenges in repurposing natural gas pipelines to hydrogen

♦ The potential for blending and de-blending hydrogen

♦ The impact of hydrogen on National Grid’s regulatory approach

♦ How to take the first steps towards a hydrogen wholesale market"

The podcast can be found on their website.

Hydrogen eliminates carbon emissions from compression ignition (CI) engines while noble gases eliminate nitrogen oxide (NOx) emissions by replacing nitrogen. Noble gases can increase the in-cylinder temperature during the compression stroke due to their high specific heat ratio. This paper aims to find the optimum parameters for hydrogen combustion in an argon–oxygen atmosphere and to study hydrogen combustion in all noble gases providing hydrogen combustion data with suitable engine parameters to predict hydrogen ignitability under different conditions. Simulations are performed with Converge CFD software based on the Yanmar NF19SK direct injection CI (DICI) engine parameters. The results are validated with the experimental results of hydrogen combustion in an argon–oxygen atmosphere with a rapid compression expansion machine (RCEM) and modifications of the hydrogen injection timing and initial temperature are proposed. Hydrogen ignition in an argon atmosphere is dependent on a minimum initial temperature of 340 K but the combustion is slightly unstable. Helium and neon are found to be suitable for hydrogen combustion in low compression ratio (CR) engines. However krypton and xenon require temperature modification and a high CR for stable ignition. Detailed parameter recommendations are needed to improve hydrogen ignitability in conventional diesel engines with the least engine modification.

The steelmaking industry is responsible for 7% of global CO2 emissions making decarbonization a significant challenge. This review provides a comprehensive analysis of current steel-production processes assessing their environmental impact in terms of CO2 emissions at a global level. Limitations of the current pathways are outlined by using objective criteria and a detailed review of the relevant literature. Decarbonization strategies are rigorously evaluated across various scenarios emphasizing technology feasibility. Focusing on three pivotal areas—scrap utilization hydrogen integration and electricity consumption—in-depth assessments are provided backed by notable contributions from both industrial and scientific fields. The intricate interplay of technical economic and regulatory considerations substantially affects CO2 emissions particularly considering the EU Emissions Trading System. Leading steel producers have established challenging targets for achieving carbon neutrality requiring a thorough evaluation of industry practices. This paper emphasizes tactics to be employed within short- medium- and long-term periods. This article explores two distinct case studies: One involves a hot rolling mill that utilizes advanced energy techniques and uses H2 for the reheating furnace resulting in a reduction of 229 kt CO2 -eq per year. The second case examines DRI production incorporating H2 and achieves over 90% CO2 reduction per ton of DRI.

This paper uses a whole-system approach to examine different strategies related to the future role of the gas grid in a low-carbon heat system. A novel model of integrated gas electricity and heat systems HEGIT is used to investigate four key sets of scenarios for the future of the gas grid using the UK as a case study: (a) complete electrification of heating; (b) conversion of the existing gas grid to deliver hydrogen; (c) a hybrid heat pump system; and (d) a greener gas grid. Our results indicate that although the infrastructure requirements the fuel or resource mix and the breakdown of costs vary significantly over the complete electrification to complete conversion of the gas grid to hydrogen spectrum the total system transition cost is relatively similar. This reduces the significance of total system cost as a guiding factor in policy decisions on the future of the gas grid. Furthermore we show that determining the roles of low-carbon gases and electrification for decarbonising heating is better guided by the trade-offs between short- and long-term energy security risks in the system as well as trade-offs between consumer investment in fuel switching and infrastructure requirements for decarbonising heating. Our analysis of these trade-offs indicates that although electrification of heating using heat pumps is not the cheapest option to decarbonise heat it has clear co-benefits as it reduces fuel security risks and dependency on carbon capture and storage infrastructure. Combining different strategies such as grid integration of heat pumps with increased thermal storage capacity and installing hybrid heat pumps with gas boilers on the consumer side are demonstrated to effectively moderate the infrastructure requirements consumer costs and reliability risks of widespread electrification. Further reducing demand on the electricity grid can be accomplished by complementary options at the system level such as partial carbon offsetting using negative emission technologies and partially converting the gas grid to hydrogen.

This work presents the design and application of two control techniques—a model predictive control (MPC) and a proportional integral derivative control (PID) both in combination with a multilayer perceptron neural network—to produce hydrogen gas on-demand in order to use it as an additive in a spark ignition internal combustion engine. For the design of the controllers a control-oriented model identified with the Hammerstein technique was used. For the implementation of both controllers only 1% of the overall air entering through the throttle valve reacted with hydrogen gas allowing maintenance of the hydrogen–air stoichiometric ratio at 34.3 and the air–gasoline ratio at 14.6. Experimental results showed that the average settling time of the MPC controller was 1 s faster than the settling time of the PID controller. Additionally MPC presented better reference tracking error rates and standard deviation of 1.03 × 10−7 and 1.06 × 10−14 and had a greater insensitivity to measurement noise resulting in greater robustness to disturbances. Finally with the use of hydrogen as an additive to gasoline there was an improvement in thermal and combustion efficiency of 4% and 0.6% respectively and an increase in power of 545 W translating into a reduction of fossil fuel use.

In recent years several approaches and pathways have been discussed to decarbonise the transport sector; however any effort to reduce emissions might be complex due to specific socio-economic and technical characteristics of different regions. In Mexico the transport sector is the highest energy consumer representing 38.9% of the national final energy demand with gasoline and diesel representing 90% of the sector´s total fuel consumption. Energy systems models are powerful tools to obtain insights into decarbonisation pathways to understand costs emissions and rate of deployment that could serve for energy policy development. This paper focuses on the modelling of the current Mexican transport system using the MUSE-MX multi-regional model with the aim to project a decarbonisation pathway through two different scenarios. The first approach being business as usual (BAU) which aims to analyse current policies implementation and the second being a goal of net zero carbon emissions by 2050. Under the considered net zero scenario results show potential deployment of hydrogen-based transport technologies especially for subsectors such as lorries (100% H2 by 2050) and freight train (25% H2 by 2050) while cars and buses tend to full electrification by 2050.

Germany the European Union member state with the largest fiscal space and its leading manufacturer of industrial goods is pursuing an ambitious hydrogen strategy aiming at establishing itself as a major technology provider and importer of green hydrogen. The success of its hydrogen strategy represents not only a key element in realizing the European vision of climate neutrality but also a central driver of an emerging global hydrogen economy. This article provides a detailed review of German policy highlighting its prominent international dimension and its implications for the development of a global renewable hydrogen economy. It provides an overview of the strategy’s central goals and how these have evolved since the launch of the strategy in 2020. Next it moves on to provide an overview of the strategy’s main areas of intervention and highlights corresponding policy instruments. For this we draw on a comprehensive assessment of hydrogen policy instruments which have been systematically analyzed and coded. This was complemented by a detailed analysis of policy documents and information gathered in six interviews with government officials and staff of key implementing agencies. The article places particular emphasis on the strategy’s international dimension. While less significant in financial terms than domestic hydrogen-related spending it represents a defining feature of the German hydrogen strategy setting it apart from strategies in other major economies. The article closes with a reflection on the key features of the strategy compared to other important countries identifies gaps of the strategy and discusses important avenues for future research.

This paper presents a mathematical model for a multi-period hydrogen supply chain design problem considering several design features not addressed in other studies. The model is formulated as a mixed-integer program allowing the production and storage facilities to be extended over time. Pipeline and tube trailer transport modes are considered for carrying hydrogen. The model also allows finding the optimal pipeline routes and the number of transport units. The objective is to obtain an efficient supply chain design within a given time frame in a way that the demand and carbon dioxide emissions constraints are satisfied and the total cost is minimized. A computer program is developed to ease the problem-solving process. The computer program extracts the geographical information from Google Maps and solves the problem using an optimization solver. Finally the applicability of the proposed model is demonstrated in a case study from Oman.