Norway

The energy transition with transformation into predominantly renewable sources requires technology development to secure power production at all times despite the intermittent nature of the renewables. Micro gas turbines (MGTs) are small heat and power generation units with fast startup and load-following capability and are thereby suitable backup for the future’s decentralized power generation systems. Due to MGTs’ fuel flexibility a range of fuels from high-heat to lowheat content could be utilized with different greenhouse gas generation. Developing micro gas turbines that can operate with carbon-free fuels will guarantee carbon-free power production with zero CO2 emission and will contribute to the alleviation of the global warming problem. In this paper the redevelopment of a standard 100-kW micro gas turbine to run with methane/hydrogen blended fuel is presented. Enabling micro gas turbines to run with hydrogen blended fuels has been pursued by researchers for decades. The first micro gas turbine running with pure hydrogen was developed in Stavanger Norway and launched in May 2022. This was achieved through a collaboration between the University of Stavanger (UiS) and the German Aerospace Centre (DLR). This paper provides an overview of the project and reports the experimental results from the engine operating with methane/hydrogen blended fuel with various hydrogen content up to 100%. During the development process the MGT’s original combustor was replaced with an innovative design to deal with the challenges of burning hydrogen. The fuel train was replaced with a mixing unit new fuel valves and an additional controller that enables the required energy input to maintain the maximum power output independent of the fuel blend specification. This paper presents the test rig setup and the preliminary results of the test campaign which verifies the capability of the MGT unit to support intermittent renewable generation with minimum greenhouse gas production. Results from the MGT operating with blended methane/hydrogen fuel are provided in the paper. The hydrogen content varied from 50% to 100% (volume-based) and power outputs between 35 kW to 100kW were tested. The modifications of the engine mainly the new combustor fuel train valve settings and controller resulted in a stable operation of the MGT with NOx emissions below the allowed limits. Running the engine with pure hydrogen at full load has resulted in less than 25 ppm of NOx emissions with zero carbon-based greenhouse gas production.

This paper evaluates the predictive capabilities of the advanced consequence model FLACS-CFD for deflagrations involving hydrogen. Two modelling approaches are presented: the extensively validated model system originally developed for hydrocarbons included in FLACS-CFD 22.1 and a Markstein number dependent model implemented in the in-house version FLACS-CFD 22.1 IH. The ability of the models to predict the overpressure and the flame arrival time for scenarios with different concentrations of hydrogen and thus different Lewis and Markstein numbers is assessed. Furthermore the effect of adding methane or nitrogen on overpressure for different regimes of premixed combustion are investigated. The validation dataset includes deflagrations in the open or in congested open areas and vented deflagrations in empty or congested enclosures. The overpressure predictions by FLACS-CFD 22.1 IH are found to be more accurate than those obtained with FLACS-CFD 22.1 for scenarios with varying hydrogen concentrations and/or added nitrogen or methane in the mixture. The predictions by FLACS-CFD 22.1 IH for lean hydrogen mixtures are within a factor of 2 of the values observed in the experiments. Further development of the model is needed for more accurate prediction of deflagrations involving rich hydrogen mixtures as well as scenarios with other fuels and/or conditions where the initial pressure or temperature deviate significantly from ambient conditions.

Understanding what people think about hydrogen energy and how this influences their acceptance of the associated technology is a critical area of research. The public’s willingness to adopt practical applications of hydrogen energy such as hydrogen fuel-cell vehicles (HFCVs) is a key factor in their deployment. To analyse the direct and indirect effects of key attitudinal variables that could influence the intention to use HFCVs in Spain an online questionnaire was administered to a representative sample of the Spanish population (N = 1000). A path analysis Structural Equation Model (SEM) was applied to determine the effect of different attitudinal variables. A high intention to adopt HFCVs in Spain was found (3.8 out of 5) assuming their wider availability in the future. The path analysis results indicated that general acceptance of hydrogen technology and perception of its benefits had the greatest effect on the public’s intention to adopt HFCVs. Regarding indirect effects the role of trust in hydrogen technology was notable having significant mediating effects not only through general acceptance of hydrogen energy and local acceptance of hydrogen refuelling stations (HRS) but also through positive and negative emotions and benefits perception. The findings will assist in focusing the future hydrogen communication strategies of both the government and the private (business) sector.

Hydrogen is considered a promising solution for global decarbonisation as an alternative to fossil fuels. However it can interact with and brittle most metallic materials and is highly flammable. These properties call for a systematic investigation of physical and chemical hazards and for the definition of a comprehensive risk management and monitoring framework including proper maintenance planning. This study aims at establishing a hydrogen monitoring scheme and it provides a descriptive bibliometric and interpretative review of the current state-of-the-art of suitable techniques to ensure the safe handling of hydrogen systems. The descriptive analysis outlines the technologies available to supervise the hydrogen-material interactions and detect hydrogen leaks and flames. The bibliometric analysis shows quantitative data to identify the most relevant research groups. The interpretative study discusses the findings and examines the possibility of combining the identified techniques with maintenance programs to prevent catastrophic events.

LNG carriers play a crucial role in the shipping industry meeting the global demand for natural gas (NG). However the energy losses resulting from the propulsion system and the excess boil-off gas (BOG) cannot be overlooked. The present article investigates the H2 production on board LNG carriers employing both the engine's waste heat (WH) and the excess BOG. Conventional (ORC) and dual-pressure (2P-ORC) organic Rankine cycles coupled separately with a solid oxide electrolysis (SOEC) have been simulated and compared. The hydrogen (H2) produced is then compressed at 150 bar for subsequent use as required. According to the results the 2P-ORC generates 14.79 % more power compared to ORC allowing for an increased energy supply to the SOEC; hence producing more H2 (34.47 kg/h compared to 31.14 kg/h). Including the 2P-ORC in the H2 production plant results in a cheaper H2 cost by 0.04 $/kgH2 compared to ORC a 1.13 %LHV higher system efficiency when leveraging all the available waste heat. The plant including 2P-ORC exploits more than 86 % of the of the available waste compared to 70 % when using ORC. Excluding the compression system decreases the capital cost by almost the half regardless of the WH recovery system used yet it plays in favour of the plant with ORC making the cost of H2 cheaper by 0.29 $/kgH2 in this case. Onboard H2 production is a versatile process independent from the propulsion system ensuring the ship's safety and availability throughout a sea journey.

The European Union aims to increase its climate ambition and achieve climate neutrality by 2050. This necessitates expanding offshore wind energy and green hydrogen production especially for hard-to-abate industrial sectors. A study examines the impact of green hydrogen on offshore wind projects specifically focusing on a potential future North Sea offshore grid. The study utilizes data from the TYNDP 2020 Global Ambition scenario 2040 considering several European countries. It aims to assess new transmission and generation capacity utilization and understand the influencing factors. The findings show that incorporating green hydrogen production increases offshore wind utilization and capture prices. The study estimates that by 2040 the levelized cost of hydrogen could potentially decrease to e1.2-1.6/kg H2 assuming low-cost electricity supply and declining capital costs of electrolysers. These results demonstrate the potential benefits and cost reductions of integrating green hydrogen production into North Sea offshore wind projects.

This paper establishes a framework of boundary conditions for implementing hydrogen energy systems in ships identifying what is feasible within maritime constraints. To support a comprehensive understanding of hydrogen systems onboard vessels an extensive technical review of hydrogen storage and power systems is provided covering the entire power value chain. Key aspects include equipment arrangement integration of fuel cell powertrain and presentation of the complete storage system in compliance with regulations. Engineering considerations such as material selection and insulation equipment specifications (e.g. pressure relief valves and hydrogen purity) and system configurations are analysed. Key findings reveal that fuel cells must achieve operational lifespans exceeding 46000 h to be viable for maritime applications. Additionally reliance solely on volumetric energy density underestimates storage needs necessitating provisions for cofferdams ullage space tank heels and hydrogen conditioning areas. Regulatory gaps are identified including inadequate safety provisions and inappropriate material guidelines.

Chapters:<br/>♦ Introduction by Rainer Quitzow and Yana Zabanova<br/>♦ The EU in the Global Hydrogen Race: Bringing Together Climate Action Energy Security and Industrial Policy by Yana Zabanova<br/>♦ Germany’s Hydrogen Strategy: Securing Industrial Leadership in a Carbon–Neutral Economy by Almudena Nunez and Rainer Quitzow<br/>♦ France’s Hydrogen Strategy: Focusing on Domestic Hydrogen Production to Decarbonise Industry and Mobility by Ines Bouacida<br/>♦ International Dimension of the Polish Hydrogen Strategy. Conditions and Potential for Future Development by Michał Smoleń and Wojciech Żelisko<br/>♦ Hydrogen Affairs in Hungary’s Politically Confined Ambition byJohn Szabo<br/>♦ Spain’s Hydrogen Ambition: Between Reindustrialisation and Export-Led Energy Integration with the EU by Ignacio Urbasos and Gonzalo Escribano<br/>♦  Italian Hydrogen Policy: Drivers Constraints and Recent Developments by Andrea Prontera<br/>♦  Hydrogen Policy in the Netherlands: Laying the Foundations for a Scalable Hydrogen Value Chain by Roelof Stam Coby van der Linde and Pier Stapersma<br/>♦ Hydrogen Strategy of Sweden: Unpacking the Multiple Drivers and Potential Barriers to Hydrogen Development by Stefan Ćetković and Janek Stockburger<br/>♦  Norway’s Hydrogen Strategy: Unveiling Green Opportunities and Blue Export Ambitions by Jon Birger Skjærseth Per Ove Eikeland Tor Håkon Jackson Inderberg and Mari Lie Larsen<br/>♦ The Geopolitics of Hydrogen in Europe: The Interplay between EU and Member State Policies by Rainer Quitzow and Yana Zabanova

In light of offshore wind expansions in the North and Baltic Seas in Europe further ideas on using offshore space for renewable-based energy generation have evolved. One of the concepts is that of energy islands which entails the placement of energy conversion and storage equipment near offshore wind farms. Offshore placement of electrolysers will cause interdependence between the availability of electricity for hydrogen production and for power transmission to shore. This paper investigates the trade-offs between integrating energy islands via electricity versus hydrogen infrastructure. We set up a combined capacity expansion and electricity dispatch model to assess the role of electrolysers and electricity cables given the availability of renewable energy from the islands. We find that the electricity system benefits more from connecting close-to-shore wind farms via power cables. In turn electrolysis is more valuable for far-away energy islands as it avoids expensive long-distance cable infrastructure. We also find that capacity investment in electrolysers is sensitive to hydrogen prices but less to carbon prices. The onshore network and congestion caused by increased activity close to shore influence the sizing and siting of electrolysers.

The hydrogen economy is receiving increasing attention as a complement to electrification in the global energy transition. Clean hydrogen production is often viewed as a competition between natural gas reforming with CO2 capture and electrolysis using renewable electricity. However solid fuel gasification with CO2 capture presents another viable alternative especially when considering the potential of biomass to achieve negative CO2 emissions. This study investigates the techno-economic potential of hydrogen production from large-scale coal/ biomass co-gasification plants with CO2 capture. With a CO2 price of 50 €/ton the benchmark plant using commercially available technologies achieved an attractive hydrogen production cost of 1.78 €/kg with higher CO2 prices leading to considerable cost reductions. Advanced configurations employing hot gas clean-up membrane-assisted water-gas shift and more efficient gasification with slurry vaporization and a chemical quench reduced the hydrogen production cost to 1.50–1.62 €/kg with up to 100% CO2 capture. Without contingencies added to the pre-commercial technologies the lowest cost reduces to 1.43 €/kg. It was also possible to recover waste heat in the form of hot water at 120 ◦C for district heating potentially unlocking further cost reductions to 1.24 €/kg. In conclusion gasification of locally available solid fuels should be seriously considered next to natural gas and electrolysis for supplying the emerging hydrogen economy.