Norway

Alternative fuels are crucial to decarbonize the European maritime transport but their net climate benefits vary with the type of fuel and production country. In this study we assess the energy potential and climate change mitigation benefits of using agricultural and forest residues in different European countries for drop-in (Fast Pyrolysis Hydrothermal Liquefaction and Gasification to Fischer-Tropsch fuels or Bio-Synthetic Natural Gas) and hydrogen-based biofuels (hydrogen ammonia and methanol) with or without carbon capture and storage (CCS). Our results show the combinations of countries and biofuel options that successfully achieve the decarbonization targets set by the FuelEU Maritime initiative for the next years including a prospective analysis that include technological changes projected for the biofuel supply chains until 2050. With the current technologies the largest greenhouse gas (GHG) mitigation potential per year at a European scale is obtained with bio-synthetic natural gas and hydrothermal liquefaction. Among carbon-free biofuels ammonia currently has higher mitigation but hydrogen can achieve a lower GHG intensity per unit of energy with the projected decarbonization of the electricity mixes until 2050. The full deployment of CCS can further accelerate the decarbonization of the maritime sector. Choosing the most suitable renewable fuels requires a regional perspective and a transition roadmap where countries coordinate actions to meet ambitious climate targets.

Decarbonisation of the iron and steel industry would require the use of innovative low-carbon production technologies. Use of 100% hydrogen in a shaft furnace (SF) to reduce iron ore has the potential to reduce emissions from iron and steel production significantly. In this work results from the techno-economic assessment of a H2-SF connected to an electric arc furnace(EAF) for steel production are presented under two scenarios. In the first scenario H2 is produced from molten metal methane pyrolysis in an electrically heated liquid metal bubble column reactor. Grid connected low-temperature alkaline electrolyser was considered for H2 production in the second scenario. In both cases 59.25 kgH2 was required for the production of one ton of liquid steel (tls). The specific energy consumption (SEC) for the methane pyrolysis based system was found to be 5.16 MWh/tls. The system used 1.51 MWh/tls of electricity and required 263 kg/tls of methane corresponding to an energy consumption of 3.65 MWh/tls. The water electrolysis based system consumed 3.96 MWh/tls of electricity at an electrolyser efficiency of 50 KWh/kgH2. Both systems have direct emissions of 129.4 kgCO2/tls. The indirect emissions are dependent on the source of natural gas pellet making process and the grid-emission factor. Indirect emissions for the electrolysis based system could be negligible if the electricity is generated from renewable energy sources. The levellized cost of production(LCOP) was found to be $631 and $669 respectively at a discount rate of 8% for a plant-life of 20 years. The LCOP of a natural gas reforming based direct reduction steelmaking plant of operating under similar conditions was found to be $414. Uncertainty analysis was conducted for the NPV and IRR values.

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.

This paper compares six (6) alternatives for green hydrogen transport at sea. Two (2) alternatives of liquid hydrogen (LH2) by ship two (2) alternatives of compressed hydrogen (cH2) by ship and two (2) alternatives of hydrogen by pipeline. The ship alternatives study having hydrogen storage media at both end terminals to reduce the ships’ time at port or prescinding of them and reduce the immobilized capital. In the case of the pipeline new models are proposed by considering pressure costs. One scenario considers that there are compression stations every 500 km and the other one considers that there are none along the way. These alternatives are assessed under nine different scenarios that combine three distances: 100 km 2500 km and 5000 km; and three export rates of hydrogen 100 kt/y 1 Mt/y and 10 Mt/y. The results show including uncertainty bands that for the 100 km of distance the best alternative is the pipeline. For 2500 km and 100 kt/y the top alternative is cH2 shipping without storage facilities at the port terminals. For 2500 km and 1 Mt/y and for 5000 km and 100 kt/y the best alternatives are cH2 or LH2 shipping. For the remaining scenarios the best alternative is LH2 shipping.

The urgency to achieve net-zero carbon dioxide (CO2) emissions by 2050 as first presented by the IPCC special report on 1.5°C Global Warming has spurred renewed interest in hydrogen to complement electrification for widespread decarbonization of the economy. We present reflections on estimates of future hydrogen demand optimization of infrastructure for hydrogen production transport and storage development of viable business cases and environmental impact evaluations using life cycle assessments. We highlight challenges and opportunities that are common across studies of the business cases for hydrogen in Germany the UK the Netherlands Switzerland and Norway. The use of hydrogen in the industrial sector is an important driver and could incentivise large-scale hydrogen value chains. In the long-term hydrogen becomes important also for the transport sector. Hydrogen production from natural gas with capture and permanent storage of the produced CO2 (CCS) enables large-scale hydrogen production in the intermediate future and is complementary to hydrogen from renewable power. Furthermore timely establishment of hydrogen and CO2 infrastructures serves as an anchor to support the deployment of carbon dioxide removal technologies such as direct air carbon capture and storage (DACCS) and biohydrogen production with CCS. Significant public support is needed to ensure coordinated planning governance and the establishment of supportive regulatory frameworks which foster the growth of hydrogen markets.

Norwegian offshore wind farms may be able to supply power to offshore oil and gas platforms in the near future thanks to the expeditious development of offshore wind technology. This would result in a reduction in CO2 emissions from oil and gas offshore installations which are currently powered predominantly by gas turbines. The challenge with using wind power is that offshore oil and gas installations require a fairly constant and stable source of power whereas wind power typically exhibits significant fluctuations over time. The purpose of this study is to perform a technical feasibility evaluation of using wind power to supply an offshore oil and gas installation on the basis of dynamic process simulations. Throughout the study only the topside processing system is considered since it is the most energy-intensive part of an oil and gas facility. An offshore field on the Norwegian Continental Shelf is used as a case study. The results indicate that when the processing system operates in steady-state conditions it cannot be powered solely by wind energy and another power source is required to compensate for low wind power generation intervals. An alternative would be to store wind energy during periods of high generation (e.g. by producing hydrogen or ammonia) and use it during periods of low generation. Utilizing energy storage methods wind energy can be continuously used for longer periods of time and provide a suitable constant power source for the studied case. Higher constant power can also be provided by increasing the efficiency of energy recovery and storage processes. Alternatively these two technologies may be integrated with gas turbines if the required storage cannot be provided or higher power is required. It was estimated that the integration of wind energy could result in noticeable reductions in CO2 emissions for the case study. Additionally according to the results the production storage and reuse of hydrogen and ammonia on-site may be viable options for supplying power.

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.

Hydrogen as a carbon-free energy carrier has emerged as a crucial component in the decarbonization of the energy system serving as both an energy storage option and fuel for dispatchable power generation to mitigate the intermittent nature of renewable energy sources. However the unique physical and combustion characteristics of hydrogen which differ from conventional gaseous fuels such as biogas and natural gas present new challenges that must be addressed. To fully integrate hydrogen as an energy carrier in the energy system the development of low-emission and highly reliable technologies capable of handling hydrogen combustion is imperative. This study presents a ground-breaking achievement - the first successful test of a micro gas turbine running on 100% hydrogen with NOx emissions below the standard limits. Furthermore the combustor of the micro gas turbine demonstrates exceptional fuel flexibility allowing for the use of various blends of hydrogen biogas and natural gas covering a wide range of heating values. In addition to a comprehensive presentation of the test rig and its instrumentation this paper illuminates the challenges of hydrogen combustion and offers real-world operational data from engine operation with 100% hydrogen and its blends with methane.

Remote locations and off-grid regions still rely mainly on diesel generators despite the high operating costs and greenhouse gas emissions. The exploitation of local renewable energy sources (RES) in combination with energy storage technologies can be a promising solution for the sustainable electrification of these areas. The aim of this work is to investigate the potential for decarbonizing remote islands in Norway by installing RES-based energy systems with hydrogen-battery storage. A national scale assessment is presented: first Norwegian islands are characterized and classified according to geographical location number of inhabitants key services and current electrification system. Then 138 suitable installation sites are pinpointed through a multiple-step sorting procedure and finally 10 reference islands are identified as representative case studies. A site-specific methodology is applied to estimate the electrical load profiles of all the selected reference islands. An optimization framework is then developed to determine the optimal system configuration that minimizes the levelized cost of electricity (LCOE) while ensuring a reliable 100% renewable power supply. The LCOE of the RES-based energy systems range from 0.21 to 0.63 €/kWh and a clear linear correlation with the wind farm capacity factor is observed (R2 equal to 0.87). Hydrogen is found to be crucial to prevent the oversizing of the RES generators and batteries and ensure long-term storage capacity. The techno-economic feasibility of alternative electrification strategies is also investigated: the use of diesel generators is not economically viable (0.87–1.04 €/kWh) while the profitability of submarine cable connections is highly dependent on the cable length and the annual electricity consumption (0.14–1.47 €/kWh). Overall the cost-effectiveness of RES-based energy systems for off-grid locations in Northern Europe can be easily assessed using the correlations derived in this analysis.

Hydrogen will be important in decarbonized energy systems. The primary ways to produce low emission hydrogen are from renewable electricity using electrolyzers called green hydrogen and by reforming natural gas and capturing and storing the CO2 known as blue hydrogen. In this study the degrees to which blue and green hydrogen are complementary or competitive are analyzed through a sensitivity analysis on the electrolyzer costs and natural gas price. This analysis is performed on four bases: what is the cost-effective relative share between blue and green hydrogen deployment how their deployment influences the price of hydrogen how the price of CO2 changes with the deployment of these two technologies and whether infrastructure can economically be shared between these two technologies. The results show that the choice of green and blue hydrogen has a tremendous impact where an early deployment of green leads to higher hydrogen costs and CO2 prices in 2030. Allowing for blue hydrogen thus has notable benefits in 2030 giving cheaper hydrogen with smaller wider socioeconomic impacts. In the long term these competitive aspects disappear and green and blue hydrogen can coexist in the European market without negatively influencing one another.

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.

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.

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.

The hydrogen compatibility of two X65 pipeline steels for transport of hydrogen gas is investigated through microstructural characterization hydrogen permeation measurements and fracture mechanical testing. The investigated materials are a quenched and tempered pipeline steel with a fine-grained homogeneously distributed ferrite-bainite microstructure and hot rolled pipeline steel with a ferrite-pearlite banded microstructure. All tests are performed both under electrochemical and gaseous hydrogen charging conditions. A correlation between electrochemical hydrogen charging and gaseous charging is determined. The results point to inherent differences in the interaction between hydrogen and the two material microstructures. Further research is needed to unveil the influence of material microstructure on hydrogen embrittlement.

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.

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.

Hydrogen is an environmentally friendly fuel that can facilitate the upcoming energy transition. The development of an extensive infrastructure for hydrogen transport and storage is crucial. However the mechanical properties of structural materials are significantly degraded in H2 environments leading to early component failures. Pipelines are designed following defect-tolerant principles and are subjected to periodic pressure fluctuations. Hence these systems are potentially prone to fatigue degradation often accelerated in pressurized hydrogen gas. Inspection and maintenance activities are crucial to guarantee the integrity and fitness for service of this infrastructure. This study predicts the severity of hydrogen-enhanced fatigue in low-alloy steels commonly employed for H2 transport and storage equipment. Three machine-learning algorithms i.e. Linear Model Deep Neural Network and Random Forest are used to categorize the severity of the fatigue degradation. The models are critically compared and the best-performing algorithm are trained to predict the Fatigue Acceleration Factor. This approach shows good prediction capability and can estimate the fatigue crack propagation in lowalloy steels. These results allow for estimating the probability of failure of hydrogen pipelines thus facilitating the inspection and maintenance planning.

Green hydrogen is expected to play a vital role in decarbonizing the energy system in Europe. However large-scale deployment of green hydrogen has associated potential trade-offs in terms of climate and other environmental impacts. This study aims to shed light on a comprehensive sustainability assessment of this large-scale green hydrogen deployment based on the EMPIRE energy system modeling compared with other decarbonization paths. Process-based Life Cycle Assessment (LCA) is applied and connected with the output of the energy system model revealing 45% extra climate impact caused by the dedicated 50% extra renewable infrastructure to deliver green hydrogen for the demand in the sectors of industry and transport in Europe towards 2050. Whereas the analysis shows that green hydrogen eventually wins on the climate impact within four designed scenarios (with green hydrogen with blue hydrogen without green hydrogen and baseline) mainly compensated by its clean usage and renewable electricity supply. On the other hand green hydrogen has a lower performance in other environmental impacts including human toxicity ecotoxicity mineral use land use and water depletion. Furthermore a monetary valuation of Life Cycle Impact (LCI) is estimated to aggregate 13 categories of environmental impacts between different technologies. Results indicate that the total monetized LCI cost of green hydrogen production is relatively lower than that of blue hydrogen. In overview a large-scale green hydrogen deployment potentially shifts the environmental pressure from climate and fossil resource use to human health mineral resource use and ecosystem damage due to its higher material consumption of the infrastructure.

Hydrogen is on the rise as a substitute for fossil fuel in the energy sector. While this substitution does not happen dramatically the steady increase in hydrogen related research might be a good indicator of such desire. As it stands there are issues regarding its safe handling and use; consequently the health and safety subsectors observe the situation conspicuously. As we yet to know the behavior of hydrogen in critical situations uncertainties make these tasks prone to emerging risks. Thus hydrogen safety falls under emerging risk studies. Conventional perspective on safety especially regarding the flammable material focuses on calculating the hypothetical risks of failures in system. Resilience Engineering has another perspective as it focuses on normal operations offering new perspectives to tackle emerging risks from a new angle. Born from the heart of Resilience Engineering the Functional Resonance Analysis Method (FRAM) captures sociotechnical systems’ essence in a tangible way. In this study FRAM has been used to model a series of experiments done on hydrogen management to analyze its jet fire. FRAM is used to test whether the method could be suitable to model a system in which emerging risks are present. It is the conclusion of this study that FRAM seems promising in raising risk awareness especially when available data is limited.

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.

Reserves of fossil fuels such as coal oil and natural gas on earth are finite. The continuous use and burning of these fossil fuel resources in the industrial domestic and transport sectors has resulted in the extremely high emission of greenhouse gases GHGs (e.g. CO2) and solid particulates into the atmosphere. Therefore it is necessary to explore pollution free and more efficient energy sources in order to replace depleting fossil fuels. The use of hydrogen (H2) as an alternative fuel source is particularly attractive due to its very high specific energy compared to other conventional fuels and its zero GHG emission when used in a fuel cell. Hydrogen can be produced through various process technologies such as thermal electrolytic photolytic and biological processes. Thermal processes include gas reforming renewable liquid and biooil processing biomass and coal gasification; however these processes release a huge amount of greenhouse gases. Production of electrolytic hydrogen from water is an attractive method to produce clean hydrogen. It could even be a more promising technology when combining water electrolysis with power ultrasound to produce hydrogen efficiently where sonication enhances the electrolytic process in several ways such as enhanced mass transfer removal of hydrogen and oxygen (O2) gas bubbles and activation of the electrode surface. In this review production of hydrogen through sonochemical and sonoelectrochemical methods along with a brief description of current hydrogen production methods and power ultrasound are discussed.

Many countries have announced hydrogen promotion strategies to achieve net zero CO2 emissions around 2050. The cost of producing low-carbon (green and blue) hydrogen has been projected to fall considerably as production is scaled up although more so for green hydrogen than for blue hydrogen. This article uses a global computable general equilibrium (CGE) model to explore whether the cost reduction of green and blue hydrogen production can mitigate the use of fossil fuels and related carbon emissions. The results show that cost reduction can raise low-carbon hydrogen consumption markedly in relative terms but marginally in absolute terms resulting in a modest decrease in fossil fuel use and related carbon emissions. The cost reduction of low-carbon hydrogen slightly lowers the use of coal and gas but marginally increases the use of oil. If regional CO2 taxes are introduced the increase in green hydrogen production is considerably larger than in the case of low-carbon hydrogen cost reduction alone. However if cost reduction in low-carbon hydrogen is introduced in addition to the CO2 tax the emissions from fossil fuels are only marginally reduced. Hence synergy efects between the two measures on emissions are practically absent. A low-carbon hydrogen cost reduction alone is efective but insufcient to have a substantial climate impact. This study also calls for modeling development to capture special user preferences for low-carbon hydrogen related to climate mitigation when phasing in new energy carriers like hydrogen.

Hydrogen is considered a clean and efficient energy carrier crucial for shapingthe net-zero future. Large-scale production transportation storage and use of greenhydrogen are expected to be undertaken in the coming decades. As the smallest element inthe universe however hydrogen can adsorb on diffuse into and interact with many metallicmaterials degrading their mechanical properties. This multifaceted phenomenon isgenerically categorized as hydrogen embrittlement (HE). HE is one of the most complexmaterial problems that arises as an outcome of the intricate interplay across specific spatialand temporal scales between the mechanical driving force and the material resistancefingerprinted by the microstructures and subsequently weakened by the presence of hydrogen. Based on recent developments in thefield as well as our collective understanding this Review is devoted to treating HE as a whole and providing a constructive andsystematic discussion on hydrogen entry diffusion trapping hydrogen−microstructure interaction mechanisms and consequencesof HE in steels nickel alloys and aluminum alloys used for energy transport and storage. HE in emerging material systems such ashigh entropy alloys and additively manufactured materials is also discussed. Priority has been particularly given to these lessunderstood aspects. Combining perspectives of materials chemistry materials science mechanics and artificial intelligence thisReview aspires to present a comprehensive and impartial viewpoint on the existing knowledge and conclude with our forecasts ofvarious paths forward meant to fuel the exploration of future research regarding hydrogen-induced material challenges.

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 large-scale deployment of technologies that enable energy from renewables is essential for a successful transition to a carbon-neutral future. While photovoltaic panels are one of the main technologies commonly used for harvesting energy from the Sun storage of renewable solar energy still presents some challenges and often requires integration with additional devices. It is believed that hydrogen – being a perfect energy carrier – can become one of the broadly utilised storage alternatives that would effectively mitigate the energy supply and demand issues associated with the intermittent nature of renewable energy sources. Current pathways in the development of green technologies indicate the need for more sustainable material utilisation and more efficient device operation. To address this requirement integration of various technologies for renewable energy harvesting conversion and storage in a single device appears as an advantageous option. From the hydrogen economy perspective systems driven by green solar electricity that allow for (photo)electrochemical water splitting would generate hydrogen with the minimal CO2 footprint. If at the same time one of the device electrodes could store the generated gas and release it on demand the utilisation of critical and often costly elements would be reduced with possible gain in more effective device operation. Although conceptually attractive this cross-disciplinary concept has not gained yet enough attention and only limited number of experimental setups have been designed tested and reported. This review presents the first exhaustive overview and critical examination of various laboratory-scale prototype setups that attempt to combine both the hydrogen production and storage processes in a single unit via integration of a metal hydride-based electrode into a photoelectrochemical cell. The architectures of presented configurations enables direct solar energy to hydrogen conversion and its subsequent storage in a single device which – in some cases – can also release the stored (hydrogen) energy on demand. In addition this work explores perspectives and challenges related with the potential upscaling of reviewed solar-to-hydrogen storage systems trying to map and indicate the main future directions of their technological development and optimization. Finally the review also combines information and expertise scattered among various research fields with the aim of stimulating much-needed exchange of knowledge to accelerate the progress in the development and deployment of optimum green hydrogen-based solutions.