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.

Economical offshore wind developments depend on alternatives for cost-efficient transmission of the generated energy to connecting markets. Distance to shore availability of an offshore power grid and scale of the wind farm may impede export through power cables. Conversion to H2 through offshore electrolysis may for certain offshore wind assets be a future option to enable energy export. Here we analyse the cost sensitivity of offshore electrolysis for harvesting offshore wind in the North Sea using a technology-detailed multi-carrier energy system modelling framework for analysis of energy export. We include multiple investment options for electric power and hydrogen export including HVDC cables new hydrogen pipelines tie-in to existing pipelines and pipelines with linepacking. Existing hydropower is included in the modelling and the effect on offshore electrolysis from increased pumping capacity in the hydropower system is analysed. Considering the lack of empirical cost data on offshore electrolysis as well as the high uncertainty in future electricity and H2 prices we analyse the cost sensitivity of offshore electrolysis in the North Sea by comparing costs relative to onshore electrolysis and energy prices relative to a nominal scenario. Offshore electrolysis is shown to be particularly sensitive to the electricity price and an electricity price of 1.5 times the baseline assumption was needed to provide sufficient offshore energy for any significant offshore electrolysis investments. On the other hand too high electricity prices would have a negative impact on offshore electrolysis because the energy is more valuable as electricity even at the cost of increased wind power curtailment. This shows that there is a window-of-opportunity in terms of onshore electricity where offshore electrolysis can play a significant role in the production of H2 . Pumped hydropower increases the maximum installed offshore electrolysis at the optimal electricity and H2 prices and makes offshore electrolysis more competitive at low electricity prices. Linepacking can make offshore electrolysis investments more robust against low H2 and high electricity prices as it allow for more variable H2 production through storing excess energy from offshore. The increased electrolysis capacity needed for variable electrolyser operation and linepacking is installed onshore due to its lower CAPEX compared to offshore installations.

This study proposes a country-based life-cycle assessment (LCA) of several conversion pathways related 10 to both on grid-connected Power-to-X (PtX) fuels and advanced biofuel production for maritime transport 11 in Europe. We estimate the biomass resource availability (both agricultural and forest residues and 12 second-generation energy crops from abandoned cropland) electricity mix and a future-oriented 13 prospective LCA to assess how future climate change mitigation policies influence the results. Our results 14 indicate that the potential of PtX fuels to achieve well-to-wake greenhouse gas intensities lower than 15 those of fossil fuels is limited to countries with a carbon intensity of the electricity mix below 100 gCO2eq kWh-1 16 . The more ambitious FuelEU Maritime goal could be achieved with PtX only if connected to electricity sources below ca. 17 gCO2eq kWh-1 17 which can become possible for most of the national 18 electricity mix in Europe by 2050 if renewable energy sources will become deployed at large scales. For 19 drop-in and hydrogen-based biofuels biomass residues have a higher potential to reduce emissions than 20 dedicated energy crops. In Europe the potentials of energy supply from all renewable and low-carbon 21 fuels (RLFs) range from 32-149% of the current annual fuel consumption in European maritime transport. 22 The full deployment of RLFs with carbon capture and storage technologies could mitigate up to 184% of 23 the current well-to-wake shipping emissions in Europe. Overall our study highlights how the strategic use 24 of both hydrogen-based biofuels and PtX fuels can contribute to the climate mitigation targetsfor present 25 and future scenarios of European maritime transport.

With the aim of reducing carbon emissions and seeking independence from Russian gas in the wake of the conflict in Ukraine the use of hydrogen in the European Union is expected to rise in the future. In this regard hydrogen transport via pipeline will become increasingly crucial either through the utilization of existing natural gas infrastructure or the construction of new dedicated hydrogen pipelines. This study investigates the effects of hydrogen blending in existing pipelines on the European energy system by the year 2050 by introducing hydrogen blending sensitivities to the Global Energy System Model (GENeSYS-MOD). Results indicate that hydrogen demand in Europe is inelastic and limited by its high costs and specific use cases with hydrogen production increasing by 0.17% for 100%-blending allowed compared to no blending allowed. The availability of hydrogen blending has been found to impact regional hydrogen production and trade with countries that can utilize existing natural gas pipelines such as Norway experiencing an increase in hydrogen and synthetic gas exports from 44.0 TWh up to 105.9 TWh in 2050 as the proportion of blending increases. Although the influence of blending on the overall production and consumption of hydrogen in Europe is minimal the impacts on the location of production and dependence on imports must be thoroughly evaluated in future planning efforts.

This paper studies fast fueling of gaseous hydrogen into large hydrogen (H2) tanks suitable for maritime applications. Three modeling methods have been developed and evaluated: (1) Two-dimensional computational fluid dynamic (CFD) modeling (2) One-dimensional wall discretized modeling and (3) Zero-dimensional modeling. A detailed 2D CFD simulation of a small H2-tank was performed and validated with data from literature and then used to simulate a large H2-tank. Results from the 2D-model show non-uniform temperature distribution inside the large tank but not in the small H2-tank. The 1D-model can predict the mean temperature in small H2-tanks but not the inhomogeneous temperature field in large H2-tanks. The 0D-model is suitable as a screening tool to obtain rough estimates. Results from the modeling of the large H2-tank show that the heat transfer to the wall during fast filling is inhibited by heat conduction in the wall which leads to an unacceptably high mean hydrogen temperature.

This paper provides an in-depth examination of critical and strategic raw materials (CRMs) and their crucial role in the development of electrolyzer and fuel cell technologies within the hydrogen economy. It methodically analyses a range of electrolyzer technologies including alkaline proton-exchange membrane solid-oxide anion-exchange membrane and proton-conducting ceramic systems. Each technology is examined for its specific CRM dependencies operational characteristics and the challenges associated with CRM availability and sustainability. The study further extends to hydrogen storage and separation technologies focusing on the materials employed in high-pressure cylinders metal hydrides and hydrogen separation processes and their CRM implications. A key aspect of this paper is its exploration of the supply and demand dynamics of CRMs offering a comprehensive view that encompasses both the present sttate and future projections. The aim is to uncover potential supply risks understand strategies and identify potential bottlenecks for materials involved in electrolyzer and fuel cell technologies addressing both current needs and future demands as well as supply. This approach is essential for the strategic planning and sustainable development of the hydrogen sector emphasizing the importance of CRMs in achieving expanded electrolyzer capacity leading up to 2050.

This review presents state-of-the-art for representative sampling of hydrogen from hydrogen refueling stations. Documented sampling strategies are presented as well as examples of commercially available equipment for sampling at the hydrogen refueling nozzle. Filter media used for sampling is listed and the performance of some of the filters evaluated. It was found that the filtration efficiency of 0.2 and 5 mm filters were not significantly different when exposed to 200 and 300 nm particles. Several procedures for gravimetric analysis are presented and some of the challenges are identified to be filter degradation pinhole formation and conditioning of the filter prior to measurement. Lack of standardization of procedures was identified as a limitation for result comparison. Finally the review summarizes results including particulate concentration in hydrogen fuel quality data published. It was found that less than 10% of the samples were in violation with the tolerance limit.

Turquoise hydrogen from natural gas pyrolysis has recently emerged as a promising alternative for low-carbon hydrogen production with a high-value pure carbon by-product. However the implications of this technology on the broader energy system are not well understood at present. To close this literature gap this study presents an assessment of the integration of natural gas pyrolysis into a simplified European energy system. The energy system model minimizes the cost by optimizing investment and hourly dispatch of a broad range of electricity and fuel production transmission and storage technologies as well as imports/exports on the global market. Norway is included as a major natural gas producer and Germany as a major energy importer. Results reveal that pyrolysis is economically attractive at modest market shares where the carbon by-product can be sold into highvalue markets for 400 €/ton. However pyrolysis-dominated scenarios that employ methane as a hydrogen carrier also hold promise as they facilitate deep decarbonization without the need for vast expansions of international electricity hydrogen and CO2 transmission networks. The simplicity and security benefits of such pyrolysis-led decarbonization pathways justify the modest 11 % cost premium involved for an energy system where natural gas is the only energy trade vector. In conclusion there is a strong case for turquoise hydrogen in future energy systems and further efforts for commercialization of natural gas pyrolysis are recommended.

Environmental concerns regarding greenhouse gases have spurred research into alternative energy sources. One of the most prevalent waste products in the beverage industry is spent coffee grains (SCG) an estimated 60 million tons globally each year. These quantities justify the need to find effective ways to recycle this waste through the adoption of closed-loop circular economies (CE) and sustainable biofuel strategies. One promising approach is the conversion of SCG into biofuels particularly biohydrogen and biomethane through biological processes. However prior to commercialization it is critical to validate its potential profitability via technical and economic analyses such as techno-economic assessment (TEA). To this end in this study the profitability of two scenarios for biohydrogen and biomethane production has been assessed to explore feasible processing routes for SCG valorization. First a two-step dark fermentation and anaerobic digestion (DF-AD) process and second a two-step dark fermentation and photo fermentation (DF-PF) process. The profitability and sensitivity analysis results clarified that Scenario I should be chosen over Scenario II due to its higher net present value (NPV) of 138 million $ internal rate of return (IRR) of 15.3 % gross margin (GM) of 56.9 % return on investment (ROI) of 12.7 % and shorter payback period (PBP) of 6.2 years.

Hydrogen as an energy carrier is a promising alternative to fossil fuels and it becomes more and more popular in developed countries as a carbon-free fuel. The low boiling temperature of hydrogen (20 K or −253.15 ◦C) provides a unique opportunity to implement superconductors with a critical temperature above 20 K such as MgB2 or high-temperature superconductors. Superconductors increase efficiency and reduce the loss of energy which could compensate for the high price of LH2 to some extent. Norway is one of the pioneer countries with adequate infrastructure for using liquid hydrogen in the industry especially in marine technology where a superconducting propulsion system can make a remarkable impact on its economy. Using superconductors in the motor of a propulsion system can increase its efficiency from 95% to 98% when the motor operates at full power. The difference in efficiency is even greater when the motor does not work at full power. Here we survey the applications of liquid hydrogen and superconductors and propose a realistic roadmap for their synergy specifically for the Norwegian economy in the marine industry.

Hydrogen tanks used in transportation are equipped with thermal pressure relief devices to prevent a tank rapture in case of fire exposure. The opening of the pressure relief valve in such a scenario would likely result in an impinging and (semi-) confined hydrogen jet fire. Therefore twelve largescale experiments of hydrogen jet fires and one large-scale propane reference experiment have been conducted with various degrees of confinement orientations of the jet and distances from the nozzle to the impinging surface. Infrared and visible light videos temperatures heat fluxes and mass flow rate of hydrogen or propane were recorded in each experiment. It was found that the hydrogen flame can be visible under certain conditions. The main difference between an open impinging jet and an enclosed impinging jet fire is the extent of the high-temperature region in the steel target. During the impinging jet fire test 51% of the exposed target area exceeded 400C while 80% of the comparable area exceeded 400C during the confined jet fire test. A comparison was also made to an enclosed propane jet fire. The temperature distribution during the propane fire was more uniform than during the hydrogen jet fire and the localized hot spot in the impact region as seen in the hydrogen jet fires was not recorded.

Biohydrogen production from industrial wastewater has been a focus of interest in recent years. The in depth knowledge in lab scale parameters and emerging strategies are needed to be investigated in order to implement the biohydrogen production process at large scale. The operating parameters have great influence on biohydrogen productivity. With the aim to gain major insight into biohydrogen production process this review summarizes recent updates on dark fermentation inoculum pretreatment methods operating parameters (hydraulic retention time organic loading rate pH temperature volatile fatty acids bioreactor configuration nutrient availability partial pressure etc.). The challenges and limitations associated with the biohydrogen production are lack of biohydrogen producers biomass washout and accumulation of metabolites are discussed in detail. The advancement strategies to overcome these limitations are also briefly discussed.

In the wake of unprecedented global weather events and the ever-pressing urgency of climate change the discourse around energy transition has become more critical than ever.<br/>The United Kingdom once at the forefront of the energy transition movement finds itself at a crossroads. The initial rapid progress towards a low-carbon future is now facing hurdles threatening the achievement of the 'net zero by 2050' target.<br/>This revelation comes from the third edition of our UK Energy Transition Outlook (ETO) which leverages an independent model incorporating the UK's energy system's extensive connections with Europe and beyond.<br/>This report has a comprehensive analysis of:<br/>♦ Renewable energy technology scaling and costs<br/>♦ The continuing dependence on fossil fuel and need to decarbonize<br/>♦ Energy demand by sector and source<br/>♦ Energy efficiency<br/>♦ Energy supply<br/>♦ Electricity and infrastructure<br/>♦ Hydrogen<br/>♦ Energy expenditure<br/>♦ Policies driving the transition<br/>♦ Digitalization.

This study explores the potential of solar tracking technologies to enhance South Africa’s energy transition focusing on their role in supporting green hydrogen production for domestic use and export. Using the Global Energy System Model (GENeSYS-MOD) it evaluates four solar tracking technologies — horizontal axis tilted horizontal axis vertical axis and dual-axis — across six scenarios: tracking and non-tracking versions of a Business-as-Usual (BAU) scenario a 2 ◦C scenario and a high hydrogen demand and export (HighH2) scenario. The results identify horizontal axis tracking as the most cost-effective option followed by tilted horizontal axis tracking which is particularly prominent in the HighH2 scenario. Tracking systems enhance hydrogen production by extending power output and increasing electrolyzer full-load hours. In the HighH2 scenario they reduce hydrogen production costs in 2050 from 1.47 e/kg to 1.34 e/kg and system cost by 0.66% positioning South Africa competitively in the global hydrogen market. By integrating tracking technologies South Africa can align hydrogen production ambitions with renewable energy growth while mitigating grid and financial challenges. The research underscores the need for targeted energy investments and policies to maximize renewable energy and hydrogen potential ensuring a just energy transition that supports export opportunities domestic energy security and equitable socio-economic growth.

Hydrogen energy is critical in replacing fossil fuels and achieving net zero carbon emissions by 2050. Three measures can be implemented to promote hydrogen energy: reduce the cost of low-carbon hydrogen through technological improvements increase the production capacity of low-carbon hydrogen by stimulating investment and enhance hydrogen use as an energy carrier and in industrial processes by demand-side policies. This article examines how effective these measures are if successfully implemented in boosting the hydrogen market and reducing global economy-wide carbon emissions using a global computable general equilibrium model. The results show that all the measures increase the production and use of low-carbon hydrogen whether implemented alone or jointly. Notably the emissions reduced by joint implementation of all the measures in 2050 become 2.5 times the sum of emissions reduced by individual implementation indicating a considerable multiplier effect. This suggests supply and demand side policies be implemented jointly to maximize their impact on reducing emissions.

This paper presents multiple hydrogen electrolysers integrations in the power grid and their operational stra tegies for better performance. Electrolysers have been considered as electrical loads and multi-state load model for the operation of an electrolysers have been proposed. Strategy for the operation of multiple electrolysers at different positions in a grid are formulated and Multi-State Round Robin strategy is proposed. The proposed strategy is validated by implementing that to a coastal power grid and to meet the hydrogen energy demand of vessels at the ports. Simulation has been conducted modeling the grid and electrolysers in DIgSILENT Power factory. A comparison has been performed between two state load model and multi state load model considering Multi-State Round Robin operational strategy. Line loading and hydrogen production are the considered per formance indicators. The results show that the proposed model and strategy improves the hydrogen production and operational flexibility of the system.

With increasing global interest in molecular hydrogen to replace fossil fuels more attention is being paid to potential leakages of hydrogen into the atmosphere and its environmental consequences. Hydrogen is not directly a greenhouse gas but its chemical reactions change the abundances of the greenhouse gases methane ozone and stratospheric water vapor as well as aerosols. Here we use a model ensemble of five global atmospheric chemistry models to estimate the 100-year time-horizon Global Warming Potential (GWP100) of hydrogen. We estimate a hydrogen GWP100 of 11.6 ± 2.8 (one standard deviation). The uncertainty range covers soil uptake photochemical production of hydrogen the lifetimes of hydrogen and methane and the hydroxyl radical feedback on methane and hydrogen. The hydrogeninduced changes are robust across the different models. It will be important to keep hydrogen leakages at a minimum to accomplish the benefits of switching to a hydrogen economy.

Hydrogen could gradually replace fossil fuels mitigating the human impact on the environment. However equipment exposed to hydrogen is subjected to damaging effects due to H2 absorption and permeation through metals. Hence inspection activities are necessary to preserve the physical integrity of the containment systems and the risk-based (RBI) methodology is considered the most beneficial approach. This review aims to provide relevant information regarding hydrogen embrittlement its effect on materials’ properties and the synergistic interplay of the factors influencing its occurrence. Moreover an overview of predictive maintenance strategies is presented focusing on the RBI methodology. A systematic review was carried out to identify examples of the application of RBI to equipment exposed to hydrogenated environments and to identify the most active research groups. In conclusion a significant lack of knowledge has been highlighted along with difficulties in applying the RBI methodology for equipment operating in a pure hydrogen environment.

This review explores recent advancements in hydrogen gas (H2 ) safety through the lens of artificial intelligence (AI) techniques. As hydrogen gains prominence as a clean energy source ensuring its safe handling becomes paramount. The paper critically evaluates the implementation of AI methodologies including artificial neural networks (ANN) machine learning algorithms computer vision (CV) and data fusion techniques in enhancing hydrogen safety measures. By examining the integration of wireless sensor networks and AI for real-time monitoring and leveraging CV for interpreting visual indicators related to hydrogen leakage issues this review highlights the transformative potential of AI in revolutionizing safety frameworks. Moreover it addresses key challenges such as the scarcity of standardized datasets the optimization of AI models for diverse environmental conditions etc. while also identifying opportunities for further research and development. This review foresees faster response times reduced false alarms and overall improved safety for hydrogen-related applications. This paper serves as a valuable resource for researchers engineers and practitioners seeking to leverage state-of-the-art AI technologies for enhanced hydrogen safety systems.

Ahead of a potential large-scale implementation of hydrogen as an energy carrier in society safety regulation systems should be in place to provide a systematic consideration of safety related concerns. Knowledge is essential for regulatory activities. At the same time it is challenging to obtain sufficient information when regulating emerging technologies – it may be difficult to address informational shortcomings in regulatory matters as analysts can be prone to under-communicate the significance of uncertainties. Furthermore Strength of Knowledge (SoK) has been developed to address the quality of background knowledge in risk analyses. An example of a SoK framework is based on the following four conditions that is used to assess whether knowledge can be considered weak or strong: the issue of simplifications availability and reliability of data consensus among experts and general understanding of the phenomena in question. In theory this concept seems relevant for the introduction of hydrogen as an energy carrier mainly because there is little historical data to develop sound analyses creating uncertainties. However there are no clear-cut guidelines as to how knowledge gaps should be handled in the development of regulatory requirements. In this paper we consider the relevance of a specific approach for SoK assessment in the context of safety and security regulation of hydrogen as an energy carrier in society. We conclude that there are some challenges with the proposed framework and argue that further research should be conducted to identify or develop a method for handling uncertainties in regulatory processes regarding hydrogen systems as energy carriers in societies.

This paper proposes a techno-economic model for a high-speed hydrogen ferry. The model can describe the system properties i.e. energy demand weight and daily operating expenses of the ferry. A novel aspect is the consideration of superconductivity as a measure for cost saving in the setting where liquid hydrogen (LH2) can be both coolant and fuel. We survey different scenarios for a high-speed ferry that could carry 300 passengers. The results show that despite higher energy demand compressed hydrogen gas is more economical compared with LH2 for now; however constructing large-scale hydrogen liquefaction plants make it competitive in the future. Moreover compressed hydrogen gas is restricted to a shorter distance while LH2 makes longer distances possible and whenever LH2 is accessible using a superconducting propulsion system has a beneficial impact on both energy and cost savings. These effects strengthen if the operational time or the weight of the ferry increases.

Through mathematical modeling this paper integrates economic safety and environmental assessments to evaluate alternative hydrogen supply options (on-site production and external supply) and various hydrogenbased system configurations for decarbonizing energy-intensive industries. The model is applied to a case study in the glass sector. While reliance on natural gas remains the most cost-effective and safest solution it does not align with decarbonization objectives. Assuming a complete hydrogen transition on-site production reduces emissions by 85 % compared to current levels and improves safety performance over external supply. External supply of grey hydrogen becomes counterproductive increasing emissions by 68 % compared to natural gas operations. Nevertheless hydrogen cost rises from 3.6 €/kg with external supply to 4.2 €/kg with on-site production doubling the fuel cost relative to natural gas. To address the trade-offs the paper explores how specific constraints influence system design. A sensitivity analysis on key factors affecting hydrogen-related decisions provides additional support for strategic decision-making.

A large portion of astronomy’s carbon footprint stems from fossil fuels supplying the power demand of astronomical observatories. Here we explore various isolated low-carbon power system setups for the newly planned Atacama Large Aperture Submillimeter Telescope and compare them to a business-as-usual diesel power generated system. Technologies included in the designed systems are photovoltaics concentrated solar power diesel generators batteries and hydrogen storage. We adapt the electricity system optimization model highRES to this case study and feed it with the telescope’s projected energy demand cost assumptions for the year 2030 and site-specific capacity factors. Our results show that the lowest-cost system with LCOEs of $116/MWh majorly uses photovoltaics paired with batteries and fuel cells running on imported and on-site produced green hydrogen. Some diesel generators run for backup. This solution would reduce the telescope’s power-side carbon footprint by 95% compared to the businessas-usual case.

Safety and reliability have long been recognized as key issues for the development commercialization and implementation of new technologies and infrastructure and hydrogen systems are no exception to this rule. Reliability engineering quantitative risk assessment (QRA) and knowledge exchange each play a key role in proactive addressing safety – before problems happen – and help us learn from problems if they happen. Many international research activities are focusing on both reliability and risk assessment for hydrogen systems. However the element of knowledge exchange is sometimes less visible. To support international collaboration and knowledge exchange the International Energy Agency (IEA) convened a new Technology Collaboration Program “Task 43: Safety and Regulatory Aspects of Emerging Large Scale Hydrogen Energy Applications” started in June 2022. Within Task 43 Subtask E focuses on Hydrogen Systems Safety. This paper discusses the structure of the Hydrogen Systems Safety subtask and the aligned activities and introduces opportunities for future work.

Social risk is a comprehensive concept that considers not only internal/external physical risks but also risks (which are multiple varied and diverse) associated with social activity. It should be considered from diverse perspectives and requires a comprehensive evaluation framework that takes into account the synergistic impact of each element on others rather than evaluating each risk individually. Social risk assessment is an approach that is not limited to internal system risk from an engineering perspective but also considers the stakeholders development stage and societal readiness and resilience to change. This study aimed to introduce a social risk approach to assess the public safety of large-scale hydrogen systems. Guidelines for comprehensive social risk assessment were developed to conduct appropriate risk assessments for advanced science and technology activities with high uncertainties to predict major impacts on society before an accident occurs and to take measures to mitigate the damage and to ensure good governance are in place to facilitate emergency response and recovery in addition to preventive measures. In a case study this approach was applied to a hydrogen refueling station in Japan and risk-based multidisciplinary approaches were introduced. These approaches can be an effective supporting tool for social implementation with respect to large-scale hydrogen systems such as liquefied hydrogen storage tanks. The guidelines for social risk assessment of large-scale hydrogen systems are under the International Energy Agency Technology Collaboration Program Hydrogen Safety Task 43. This study presents potential case studies of social risk assessment for large-scale hydrogen systems for future.

The central role of hydrogen in the EU’s decarbonization strategy has increased the importance of critical raw materials. To address this the EU has taken legislative steps including the 2023 Critical Raw Materials Act (CRMA) to ensure a stable supply. Using a leader–follower Stackelberg game framework this study analyzes CRM market dynamics integrating CRMA compliance through rules on sourcing and stockpiling value chain resilience via the inclusion of supply diversification strategies and geopolitical influences by modeling exporter behaviors and trade dependencies. Results highlight the potential for strategic behavior by major exporters stressing the benefits of diversifying export sources and maintaining strategic stockpiles to stabilize supply. The findings provide insights into the EU’s efforts to secure CRM supplies key to achieving decarbonization goals and fostering a sustainable energy transition. Future research should explore alternative cost-reduction strategies mitigate exporter market power and evaluate the implications for pricing mechanisms market outcomes and consumer welfare

With the long-standing efforts of green transition in our society underground hydrogen storage (UHS) has emerged as a viable solution to buffering seasonal fluctuations of renewable energy supplies and demands. Like operations in hydrocarbon production and geological CO2 storage a successful UHS project requires a good understanding of subsurface formations while having different operational objectives and practical challenges. Similar to the situations in hydrocarbon production and geological CO2 storage in UHS problems the information of subsurface formations at the field level cannot be obtained through direct measurements due to the resulting high costs. As such there is a need for subsurface characterization and monitoring at the field scale which uses a certain history matching algorithm to calibrate a numerical subsurface model based on available field data. Whereas subsurface characterization and monitoring have been widely used in hydrocarbon production activities for a better understanding of hydrocarbon reservoirs to the best of our knowledge at present it appears to be a relatively less touched area in UHS problems. This work aims to narrow this noticed gap and investigates the use of an ensemble-based workflow for subsurface characterization and monitoring in a 3D UHS case study. Numerical results in this case study indicate that the ensemble-based workflow works reasonably well while also identifying some particular challenges that would be relevant to real-world problems.

Hydrogen safety is a general concern because of the high reactivity compared to hydrocarbon-based fuels. The strength of knowledge in risk assessments related to the physical phenomena and the ability of models to predict the consequence of accidental releases is a key aspect for the safe implementation of new technologies. Nuclear safety considers the possibility of accidental leakages of hydrogen gas and subsequent explosion events in risk analysis. In many configurations the considered gaseous streams involve a large fraction of nitrogen gas mixed with hydrogen. This work presents the results of a large scale explosion experimental campaign for hydrogen-nitrogen-air mixtures. The experiments were performed in a 50 m3 vessel at Gexcon’s test site in Bergen Norway. The nitrogen fraction the equivalence ratio and the congestion level were investigated. The experiments are simulated in the FLACS-CFD software to inform about the current level of conservatism of the predictions for engineering application purposes. The study shows the reduced overpressure with nitrogen added to hydrogen mixtures and supports the use of FLACS-CFD-based risk analysis for hydrogen-nitrogen scenarios.

Decarbonising energy systems is a prevalent topic in the current literature on climate change mitigation but the additional climate burden caused by methane emissions along the natural gas value chain is rarely discussed at the system level. Considering a two-basket greenhouse gas neutrality objective (both CO2 and methane) we model cost-optimal European energy transition pathways towards 2050. Our analysis shows that adoption of best available methane abatement technologies can entail an 80% reduction in methane leakage limiting the additional environmental burden to 8% of direct CO2 emissions (vs. 35% today). We show that while renewable energy sources are key drivers of climate neutrality the role of natural gas strongly depends on actions to abate both associated CO2 and methane emissions. Moreover clean hydrogen (produced mainly from renewables) can replace natural gas in a substantial proportion of its end-uses satisfying nearly a quarter of final energy demand in a climate-neutral Europe.

Hydrogen and carbon capture and storage are pivotal to decarbonize the European energy system in a broad range of pathway scenarios. Yet their timely uptake in different sectors and distribution across countries are affected by supply options of renewable and fossil energy sources. Here we analyze the decarbonization of the European energy system towards 2060 covering the power heat and industry sectors and the change in use of hydrogen and carbon capture and storage in these sectors upon Europe’s decoupling from Russian gas. The results indicate that the use of gas is significantly reduced in the power sector instead being replaced by coal with carbon capture and storage and with a further expansion of renewable generators. Coal coupled with carbon capture and storage is also used in the steel sector as an intermediary step when Russian gas is neglected before being fully decarbonized with hydrogen. Hydrogen production mostly relies on natural gas with carbon capture and storage until natural gas is scarce and costly at which time green hydrogen production increases sharply. The disruption of Russian gas imports has significant consequences on the decarbonization pathways for Europe with local energy sources and carbon capture and storage becoming even more important. Given the highlighted importance of carbon capture and storage in reaching the climate targets it is essential that policymakers ameliorate regulatory challenges related to these value chains.

Polymer electrolyte membrane (PEM) fuel cells and electrolysers offer efficient use and production of hydrogen for emission-free transport and sustainable energy systems. Perfluorosulfonic acid (PFSA) membranes like Nafion® and Aquivion® are the state-of-the-art PEMs but there is a need to increase the operating temperature to improve mass transport avoid catalyst poisoning and electrode flooding increase efficiency and reduce the cost and complexity of the system. However PSFAs-based membranes exhibit lower mechanical and chemical stability as well as proton conductivity at lower relative humidities and temperatures above 80 ◦C. One approach to sustain performance is to introduce inorganic fillers and improve water retention due to their hydrophilicity. Alternatively polymers where protons are not conducted as hydrated H3O+ ions through liquid-like water channels as in the PSFAs but as free protons (H+) via Brønsted acid sites on the polymer backbone can be developed. Polybenzimidazole (PBI) and sulfonated polyetheretherketone (SPEEK) are such materials but need considerable acid doping. Different composites are being investigated to solve some of the accompanying problems and reach sufficient conductivities. Herein we critically discuss a few representative investigations of composite PEMs and evaluate their significance. Moreover we present advances in introducing electronic conductivity in the polymer binder in the catalyst layers.

This paper proposes a technical and cost analysis model to assess the change in costs of a zeroemission high-speed ferry when retrofitting from diesel to green hydrogen. Both compressed gas and liquid hydrogen are examined. Different scenarios explore energy demand energy losses fuel consumption and cost-effectiveness. The methodology explores how variation in the ferry's total weight and equipment efficiency across scenarios impact results. Applied to an existing diesel high-speed ferry on one of Norway's longest routes the study under certain assumptions identifies compressed hydrogen gas as the current most economical option despite its higher energy consumption. Although the energy consumption of the compressed hydrogen ferry is slightly more than the liquid hydrogen counterpart its operating expenses are considerably lower and comparable to the existing diesel ferry on the route. However constructing large hydrogen liquefaction plants could reduce liquid hydrogen's cost and make it competitive with both diesel and compressed hydrogen gas. Moreover liquid hydrogen allows the use of a superconducting motor to enhance efficiency. Operating the ferry with liquid hydrogen and a superconducting motor besides its technical advantages offers promising economic viability in the future comparable to diesel and compressed hydrogen gas options. Reducing the ferry's speed and optimizing equipment improves fuel efficiency and economic viability. This research provides valuable insights into sustainable zero-emission high-speed ferries powered by green hydrogen.

Autonomous underwater vehicles (AUVs) are programmable robotic vehicles that can drift drive or glide through the ocean without real-time control by human operators. AUVs that also can follow a planned trajectory with a chosen depth profile are used for geophysical surveys subsea pipeline inspection marine archaeology and more. Most AUVs are followed by a mother ship that adds significantly to the cost of an AUV mission. One pathway to reduce this need is to develop long-endurance AUVs by improving navigation autonomy and energy storage. Long-endurance AUVs can open up for more challenging mission types than what is possible today. Fuel cell systems are a key technology for increasing the endurance of AUVs beyond the capability of batteries. However several challenges exist for underwater operation of fuel cell systems. These are related to storage or generation of hydrogen and oxygen buoyancy and trim and the demanding environment of the ambient seawater. Protecting the fuel cell inside a sealed container brings along more challenges related to condensation cooling and accumulation of inert gases or reactants. This paper elaborates on these technical challenges and describes the solutions that the Norwegian Defence Research Establishment (FFI) has chosen in its development of a fuel cell system for long-endurance AUVs. The reported solutions enabled a 24 h demonstration of FFI's fuel cell system under water. The remaining work towards a prototype sea trial is outlined.

Climate policy will inevitably lead to the stranding of fossil energy assets such as production and transport assets for coal oil and natural gas. Resourcerich developing countries are particularly aected as they have a higher risk of asset stranding due to strong fossil dependencies and wider societal consequences beyond revenue disruption. However there is only little academic and political awareness of the challenge to manage the asset stranding in these countries as research on transition risk like asset stranding is still in its infancy. We provide a research framework to identify wider societal consequences of fossil asset stranding. We apply it to a case study of Nigeria. Analyzing dierent policy measures we argue that compensation payments come with implementation challenges. Instead of one policy alone to address asset stranding a problem-oriented mix of policies is needed. Renewable hydrogen and just energy transition partnerships can be a contribution to economic development and SDGs. However they can only unfold their potential if fair benefit sharing and an improvement to the typical institutional problems in resource-rich countries such as the lack of rule of law are achieved. We conclude with presenting a future research agenda for the global community and acade

The underground hydrogen storage (UHS) capacities of shut down oil and gas (O&G) fields along the Norwegian continental shelf (NCS) are evaluated based on the publicly available geological and hydrocarbon production data. Thermodynamic equilibrium and geochemical models are used to describe contamination of hydrogen loss of hydrogen and changes in the mineralogy. The contamination spectrum of black oil fields and retrograde gas fields are remarkably similar. Geochemical models suggest limited reactive mineral phases and meter-scale hydrogen diffusion into the caprock. However geochemical reactions between residual oil reservoir brine host rock and hydrogen are not yet studied in detail. For 23 shut down O&G fields a theoretical maximum UHS capacity of ca. 642 TWh is estimated. We conclude with Frigg Nordost Frigg and Odin as the best-suited shut down fields for UHS having a maximum UHS capacity of ca. 414 TWh. The estimates require verification by site-specific dynamic reservoir models.

Global warming’s major cause is the emission of greenhouse-effect gases (GHG) especially carbon dioxide (CO2) whose main source is the combustion of fossil fuels. Fossil fuels serve as the primary energy source in many industries including shipping which is the focus of this study. One of the measures proposed to tackle GHG emissions is the development of green shipping corridors - carbon-free shipping routes that require the transition to alternative fuels which are gaining competitiveness. One of the reasons for that is carbon pricing which taxes CO2 emissions. However the lack of consensus on the most cost-advantageous alternative fuel in the long run results in the delay of the implementation of green shipping corridors. To make it more accessible for stakeholders to conduct an economic analysis of the various options a framework to determine and minimize the costs of transitioning from fossil fuels to any alternative fuel is proposed over the period of one voyage considering the lost opportunity cost the deployment cost of bunkering vessels at the necessary call ports the cost of converting the vessel the car-bon emissions tax cost and the fuel cost. This will allow stakeholders to choose the most economical alternative fuel accelerating the development of green shipping corridor initiatives. To validate the effectiveness of the framework it was applied in a case study involving a shipowner seeking to transition from heavy fuel oil (HFO) to Ammonia Hydrogen Liquefied Natural Gas (LNG) or Methanol. This study faced limitations due to the unknown costs of installing bunkering vessels for Ammonia and Hydrogen. However it evaluates the cost-effectiveness of alternative fuels providing insights into their short-term economic viability. The results showed that Hydrogen is the most costadvantageous fuel until a deployment cost per bunkering vessel of 1990285$ for a sailing speed of 22 knots and 2190171$ for a sailing speed of 18 knots is reached after which LNG becomes the most economical option regardless of variations in the carbon tax. Moreover a sensitivity analysis was conducted to determine the effects of variations in parameters such as carbon tax fuel prices and vessel conversion costs in the total cost of each fuel option. Results highlighted that even though HFO remains the most economical fuel option even when considering a high increase in carbon tax the cost gap between HFO and alternative fuels narrows significantly with the increase in carbon tax. Furthermore the sailing speed impacts the fuels’ competitiveness as the cost difference between HFO and alternative fuels decreases at higher speeds.

Achieving a net-zero energy system in Europe by 2050 will likely require large-scale deployment of hydrogen and seasonal energy storage to manage variability in renewable supply and demand. This study addresses two key objectives: (1) to develop a modeling framework that integrates seasonal storage into a stochastic multihorizon capacity expansion model explicitly capturing tactical uncertainty across timescales; and (2) to assess the impact of seasonal hydrogen storage on long-term investment decisions in European power and hydrogen infrastructure under three hydrogen demand scenarios. To this end the multi-horizon stochastic programming model EMPIRE is extended with tactical stages within each investment period enabling operational decisions to be modeled as a multi-stage stochastic program. This approach captures short-term uncertainty while preserving long-term investment foresight. Results show that seasonal hydrogen storage considerably enhances system flexibility displacing the need for up to 600 TWh/yr of dispatchable generation in Europe after 2040 and sizing down cross-border hydrogen transmission capacities by up to 12%. Storage investments increase by factors of 5–14 which increases the investments in variable renewables and improve utilization particularly solar. Scenarios with seasonal storage also show up to 6% lower total system costs and more balanced infrastructure deployment across regions. These findings underline the importance of modeling temporal uncertainty and seasonal dynamics in long-term energy system planning.

Renewable hydrogen offers compelling climate mitigation prospects with Norway possessing the opportunity to become a main global producer given its unique combination of wind energy potential available infrastructure and political motivation. However comprehensive environmental impact assessments of hydrogen from offshore wind are lacking and hydrogen leakage rates remain uncertain. A life-cycle assessment of hydrogen production from offshore wind farms in Norway is presented where different combinations of turbines (floating or bottomfixed) storage options (tank or salt cavern) and distribution methods (trucks or pipelines) are considered. Climate change impacts are assessed across the supply chain using global warming potential 100 (GWP100) and 20 (GWP20) and include hydrogen leakage contributions. The results range from 1.56 ± 0.14–2.28 ± 0.14 kg CO2-eq/kg H2 for GWP100 and 2.96 ± 0.76 and 3.75 ± 0.76 kg CO2-eq/kg H2 for GWP20 and are on average 55 % and 45 % lower than those of blue hydrogen respectively. At a default rate of 5 % hydrogen leakage contributes 50–63 % of the total impact for GWP20 and 25–37 % for GWP100. If higher-end leakage rates from literature are considered the impacts increase to 3.46 kg CO2-eq/kg H2 for GWP100 which is still lower than that of blue hydrogen. The scenario combining bottom-fixed turbines salt cavern storage and pipeline distribution presents the lowest environmental impacts. However while bottom-fixed turbines generally offer lower impacts floating turbines pose lesser risk to marine biodiversity. Overall infrastructure represents the main driver of environmental impacts. Mitigation in this area will improve potential benefits.

Integrating microbial activity into underground hydrogen storage models is crucial for simulating longterm reservoir behavior. In this work we present a coupled framework that incorporates bio-geochemical reactions and compositional flow models within the Matlab Reservoir Simulation Toolbox (MRST). Microbial growth and decay are modeled using a double Monod formulation with populations influenced by hydrogen and carbon dioxide availability. First a refined Equation of State (EoS) is employed to accurately capture hydrogen dissolution thereby improving phase behavior and modeling of microbial activity. The model is then discretized using a cell-centered finite-volume method with implicit Euler time discretization. A fully coupled fully implicit strategy is considered. Our implementation builds upon MRST’s compositional module by incorporating the Søreide–Whitson EoS microbial reaction kinetics and specific effects such as bio-clogging and molecular diffusion. Through a series of 1D 2D and 3D simulations we analyze the effects of microbialinduced bio-geochemical transformations on underground hydrogen storage in porous media.These results highlight that accounting for bio-geochemical effects can substantially impact hydrogen loss purity and overall storage performance.

Transitioning to renewable energy is vital to achieving decarbonization at the global level but energy storage is still a major challenge. This review discusses the role of energy storage in the energy transition and the blue economy focusing on technological development challenges and directions. Effective storage is vital for balancing intermittent renewable energy sources like wind solar and marine energy with the power grid. The development of battery technologies hydrogen storage pumped hydro storage and emerging technologies like sodium-ion and metal-air batteries is discussed for their potential for large-scale deployment. Shortages in critical raw materials environmental impact energy loss and costs are some of the challenges to large-scale deployment. The blue economy promises opportunities for offshore energy storage notably through ocean thermal energy conversion (OTEC) and compressed air energy storage (CAES). Moreover the capacity of datadriven optimization and artificial intelligence to enhance storage efficiency is discussed. Policy interventions and economic incentives are necessary to spur the development and deployment of sustainable energy storage technology. Education and workforce training are also important in cultivating future researchers engineers and policymakers with the ability to drive energy innovation. Merging sustainability training with an interdisciplinary approach can potentially establish an efficient workforce that is capable of addressing energy issues. Future work needs to focus on higher energy density efficiency recyclability and cost-effectiveness of the storage technologies without sacrificing their environmental sustainability. The study underlines the need for converging technological economic and educational approaches to enable a sustainable and resilient energy future.

Towards low-carbon buildings with resilient energy performance renewable energy resources and flexible energy assets play key roles in managing the electrical and heat demands. Hydrogen-based systems represent a promising solution through renewable hydrogen production and long-term storage. This paper systematically reviews 35 peer-reviewed studies (1990–2024) on hydrogen integration in buildings focusing on demand-side management (DSM) optimization methods and system performance. The review covers the environmental impacts feasibility and economic viability of integrating different hydrogen systems for supplying energy. Across critical reviews case studies hydrogen supplementary systems achieved CO2 reductions between 12 % and 87 % operational cost decreases of up to 40 % and efficiency gains exceeding 80 %. Payback periods varied widely between 9 and 20 years demonstrating high investment costs. Key gaps include limited field validation economic feasibility and public acceptance of hydrogen homes. One key area for future investigation is optimizing energy flows across production storage and demand particularly in Vehicle-to-Building (V2B) applications. This review paper highlights opportunities especially the potential of hydrogen system in decarbonization of buildings by long-term energy storage barriers and policy needs for implementing hydrogen technologies in grid-connected and remote areas to enhance sustainable and resilient buildings.