Publications

This paper introduces a value chain design for transportation fuels and a respective business case taking into account hybrid PV-Wind power plants electrolysis and hydrogen-to-liquids (H2tL) based on hourly resolved full load hours (FLh). The value chain is based on renewable electricity (RE) converted by power-to-liquids (PtL) facilities into synthetic fuels mainly diesel. Results show that the proposed RE-diesel value chains are competitive for crude oil prices within a minimum price range of about 79 - 135 USD/barrel (0.44 – 0.75 €/l of diesel production cost) depending on the chosen specific value chain and assumptions for cost of capital available oxygen sales and CO2 emission costs. A sensitivity analysis indicates that the RE-PtL value chain needs to be located at the best complementing solar and wind sites in the world combined with a de-risking strategy and a special focus on mid to long-term electrolyser and H2tL efficiency improvements. The substitution of fossil fuels by hybrid PV-Wind power plants could create a PV-wind market potential in the order of terawatts.

This article investigates the potential of renewable and low-carbon fuel production for the maritime shipping sector using Sweden as a case in focus. Techno-economic modelling and socio-technical transition studies are combined to explore the conditions opportunities and barriers to decarbonising the maritime shipping industry. A set of scenarios have been developed considering demand assumptions and potential instruments such as carbon price energy tax and blending mandate. The study finds that there are opportunities for decarbonising the maritime shipping industry by using renewable marine fuels such as advanced biofuels (e.g. biomethanol) electrofuels (e.g. e-methanol) and hydrogen. Sweden has tremendous resource potential for bio-based and hydrogen-based renewable liquid fuel production. In the evaluated system boundary biomethanol presents the cheapest technology option while e-ammonia is the most expensive one. Green electricity plays an important role in the decarbonisation of the maritime sector. The results of the supply chain optimisation identify the location sites and technology in Sweden as well as the trade flows to bring the fuels to where the bunker facilities are potentially located. Biomethanol and hydrogen-based marine fuels are cost-effective at a carbon price beyond 100 €/tCO2 and 200 €/tCO2 respectively. Linking back to the socio-technical transition pathways the study finds that some shipping companies are in the process of transitioning towards using renewable marine fuels thereby enabling niche innovations to break through the carbon lock-in and eventually alter the socio-technical regime while other shipping companies are more resistant. Overall there is increasing pressure from (inter)national energy and climate policy-making to decarbonise the maritime shipping industry.

The rapid expansion of renewable energies has the potential to decarbonize the electricity supply. This is more challenging in difficult-to-electrify sectors. The use of hydrogen provides a massive potential for this issue. However expanding hydrogen production increases electricity demand while providing additional flexibility to the electricity market. This paper mainly aims to analyze the economic effects of this sector coupling between the European electricity and national hydrogen markets. The developed energy market model jointly considers both markets to reach an overall welfare optimum. A novel modeling approach allows the interaction of these markets without the need for several iterative optimization runs. This allows for a detailed analysis of various market participants’ changes in consumer and producer surpluses. The optimization is conducted in 13 connected Central European countries to account for various power plant fleets generation mixes and electricity prices. Results show an overall welfare increase of EUR 4 to 28 billion in 2030 and an EUR 5 to 158 billion increase in 2040. However there is a surplus shift from consumers to producers. The consumer surplus is reduced by up to EUR 44 billion in 2030 and EUR 60 billion while producers benefit to achieve the overall welfare benefits. The reduction of consumer surplus changes if significant price peaks occur. Fuel cell applications can avoid these price peaks resulting in a surplus shift from thermal power plants to consumers. Hence consumer surplus can increase by up to EUR 146 billion in the respective 2040 scenarios. Pink hydrogen accounts for a sizable portion of total hydrogen production up to 58 percent in 2030 and up to 30 percent in 2040. As a result nuclear power plants that are nearly entirely allocated in France stand to benefit greatly from this sector coupling. Additional efforts could be made to address the link between hydrogen and natural gas prices. Furthermore the potential for cross-border hydrogen trade and the implementation of national legal and regulatory frameworks could be assessed.

A proton exchange membrane (PEM) electrolyzer is fed with water and powered by electric power to electrochemically produce hydrogen at low operating temperatures and emits oxygen as a by-product. Due to the complex nature of the performance of PEM electrolyzers the application of an artificial neural network (ANN) is capable of predicting its dynamic characteristics. A handful of studies have examined and explored ANN in the prediction of the transient characteristics of PEM electrolyzers. This research explores the estimation of the transient behavior of a PEM electrolyzer stack under various operational conditions. Input variables in this study include stack current oxygen pressure hydrogen pressure and stack temperature. ANN models using three differing learning algorithms and time delay structures estimated the hydrogen mass flow rate which had transient behavior from 0 to 1 kg/h and forecasted better with a higher count (>5) of hidden layer neurons. A coefficient of determination of 0.84 and a mean squared error of less than 0.005 were recorded. The best-fitting model to predict the dynamic behavior of the hydrogen mass flow rate was an ANN model using the Levenberg–Marquardt algorithm with 40 neurons that had a coefficient of determination of 0.90 and a mean squared error of 0.00337. In conclusion optimally fit models of hydrogen flow from PEM electrolyzers utilizing artificial neural networks were developed. Such models are useful in establishing an agile flow control system for the electrolyzer system to help decrease power consumption and increase efficiency in hydrogen generation.

This paper presents the HEGIT (Heat Electricity and Gas Infrastructure and Technology) model for optimal infrastructure planning for decarbonising heating in buildings. HEGIT is an optimisation model based on Mixed Integer Linear Programming. The model co-optimises the integrated operation and capacity expansion planning of electricity and gas grids as well as heating technologies on the consumer side while maintaining the security of supply and subject to different environmental operational and system-wide constraints. The three main features of the HEGIT model are: • It incorporates an integrated unit commitment and capacity expansion problem for coordinated operation and long-term investment planning of the electricity and gas grids. • It incorporates the flexible operation of heating technologies in buildings and demand response in operation and long-term investment planning of gas and electricity grids. • It incorporates a multi-scale techno-economic representation of heating technologies design features into the whole energy system modelling and capacity planning. These features enable the model to quantify the impacts of different policies regarding decarbonising heating in buildings on the operation and long-term planning of electricity and gas grids identify the cost-optimal use of available resources and technologies and identify strategies for maximising synergies between system planning goals and minimising trade-offs. Moreover the multi-scale feature of the model allows for multi-scale system engineering analysis of decarbonising heating including system-informed heating technology design identifying optimal operational setups at the consumer end and assessing trade-offs between consumer investment in heating technologies and infrastructure requirements in different heat decarbonisation pathways.

This work evaluates the effectiveness of chemical-based solutions for storing large amounts of renewable electricity. Four “Power-to-X-to-Power” pathways are examined comprising hydrogen methane methanol and ammonia as energy carriers. The pathways are assessed using a model scenario where they are produced with electricity from an onshore wind farm stored in suitable facilities and then reconverted to electricity to meet the energy demand of a chemical site. An energy management and storage capacity estimation tool is used to calculate the annual load coverage resulting from each pathway. All four pathways offer a significant increase in load coverage compared to a scenario without storage solution (56.19%). The hydrogen-based pathway has the highest load coverage (71.88%) and round-trip efficiency (36.93%) followed by the ammonia-based (69.62% 31.37%) methanol-based (67.85% 27.00%) and methane-based (67.64% 26.47% respectively) pathways. The substantially larger storage capacity required for gaseous energy carriers to ensure a steady supply to the consumer could be a decisive factor. The hydrogen pathway requires a storage volume up to 10.93 times larger than ammonia and 16.87 times larger than methanol. Notably ammonia and methanol whose load coverages are only 2.26 and 4.03 percentage points lower than that of hydrogen offer the possibility of implementing site-specific storage solutions avoiding potential bottlenecks due to limited pipeline and cavern capacities.

Investing in green hydrogen systems has become a global objective to achieve the net-zero emission goal. Therefore it is seen as the primary force behind efforts to restructure the world’s energy lessen our reliance on gas attain carbon neutrality and combat climate change. This paper proposes a power management for a net zero emission PV microgrid-based decentralized green hydrogen system. The hybrid microgrid combines a fuel cell battery PV electrolyzer and compressed hydrogen storage (CHSU) unit aimed at power sharing between the total components of the islanded DC microgrid and minimizing the equivalent hydrogen consumption (EHC) by the fuel cell and the battery. In order to minimize the EHC and maintain the battery SOC an optimization-based approach known as the Equivalent Consumption Minimization Strategy (ECMS) is used. A rulebased management is used to manage the power consumed by the electrolyzer and the CHSU by the PV system in case of excess power. The battery is controlled by an inverse droop control to regulate the dc bus voltage and the output power of the PV system is maximized by the fuzzy logic controller-based MPPT. As the hybrid microgrid works in the islanded mode a two-level hierarchical control is applied in order to generate the voltage and the frequency references. The suggested energy management approach establishes the operating point for each system component in order to enhance the system’s efficiency. It allows the hybrid system to use less hydrogen while managing energy more efficiently.

This is a summary report of a study which aimed to understand the safety feasibility cost and impacts for 7 industrial sites to switch from natural gas to 100% hydrogen for heating. The volunteer industrial sites:<br/>♦ are located away from industrial clusters<br/>♦ use natural gas to meet most of their energy demand<br/>♦ will likely be most impacted by decisions on the future of the natural gas grid<br/>We have published the report in order to share its findings with other industrial sites and wider industry in particular those considering hydrogen as an option for decarbonisation.<br/>Note that:<br/>♦ some work was carried out on a non-hydrogen alternative energy source but to a lesser level of detail and not to determine the optimal decarbonisation solution<br/>♦ the findings do not apply to other end user environments because of differences between these environments and the consumption of gas<br/>The study was commissioned in 2022 by the former Department for Business and Energy and undertaken by AECOM and their safety sub-contractor ESR.<br/>The evidence will inform strategic decisions in 2026 on the role of low carbon hydrogen as a replacement for natural gas heating.

A proton exchange membrane fuel cell (PEMFC) system requires an adequate hydrogen supply and circulation to achieve its expected performance and operating life. An ejector-based hydrogen circulation system can reduce the operating and maintenance costs noise and parasitic power consumption by eliminating the recirculation pump. However the ejector’s hydrogen entrainment capability restricted by its geometric parameters and flow control variability can only operate properly within a relatively narrow range of fuel cell output power. This research introduced the optimal design and operation control methods of a dual-ejector hydrogen supply/circulation system to support the full range of PEMFC system operations. The technique was demonstrated on a 70 kW PEMFC stack with an effective hydrogen entrainment ratio covering 8% to 100% of its output power. The optimal geometry design ensured each ejector covered a specific output power range with maximized entrainment capability. Furthermore the optimal control of hydrogen flow and the two ejectors’ opening and closing times minimized the anode gas pressure fluctuation and reduced the potential harm to the PEMFC’s operation life. The optimizations were based on dedicated computational fluid dynamics (CFD) and system dynamics models and simulations. Bench tests of the resulting ejector-based hydrogen supply/circulation system verified the simulation and optimization results.

The world is facing an urgent global climate challenge and hydrogen (H2) is increasingly valued as a carbon-free energy carrier that can play a prominent role in decarbonising economies. However the environmental impact of the different methods for hydrogen production are sometimes overlooked. This work provides a comprehensive overview of the environmental impacts and costs of a diverse range of methods for producing hydrogen. Ninety nine life cycle assessments (LCAs) of hydrogen production published between 2015 and 2022 are categorised by geography production method energy source goal and scope and compared by data sources and methodology. A meta-analysis of methodological choices is used to identify a subset of mutually comparable studies whose results are then compared initially by global warming potential (GWP) then low-GWP scenarios are compared by other indicators. The results show that the lowest GWP is achieved by methods that are currently more expensive (~US $4–9/kg H2) compared to the dominant methods of producing hydrogen from fossil fuels (~US $1–2/kg H2). The research finds that data are currently limited for comparing environmental indicators other than GWP such as terrestrial acidification or freshwater eutrophication. Recommendations are made for future LCAs of hydrogen production.

To reach the decarbonisation goals a zero CO2 emissions large ship propulsion system is proposed in this work. The ship selected is a large ferry propelled by an internal combustion engine fuelled by an ammonia-hydrogen blend. The only fuel loaded in the vessel will be ammonia. The hydrogen required for the combustion in the engine will be produced onboard employing ammonia decomposition. The heat required for this decomposition section will be supplied by using the hot flue gases of the combustion engine. To address the issues regarding NOx emissions a selective catalytic reduction (SCR) reactor was designed. The main operating variables for all the equipment were computed for engine load values of 25% 50% 75% and 100%. Considering the lowest SCR removal rate (91% at an engine load of 100%) the NOx emissions of the vessel were less than 0.5 g/kWh lower than the IMO requirements. An energy analysis of the system proposed to transform ammonia into energy for shipping was conducted. The global energy and exergy efficiencies were 42.4% and 48.1%. In addition an economic analysis of the system was performed. The total capital cost (CAPEX) for the system can be estimated at 8.66 M€ (784 €/kW) while the operating cost (OPEX) ranges between 210 €/MWh (engine load 100%) and 243 €/MWh (engine load of 25%). Finally a sensitivity analysis for the price of ammonia was performed resulting in the feasibility of reducing the operating cost to below 150 €/MWh in the near horizon.

Liquid hydrogen is one of the high-quality energy carriers but a large leak of liquid hydrogen can pose significant safety risks. Understanding its diffusion law after accidental leakage is an important issue for the safe utilization of hydrogen energy. In this paper a series of open-space large-volume liquid hydrogen release experiments are performed to observe the evolution of visible clouds during the release and an array of hydrogen concentration sensors is set up to monitor the fluctuation in hydrogen concentration at different locations. Based on the experimental conditions the diffusion of hydrogen clouds in the atmosphere under different release hole diameters and different ground materials is compared. The results show that with the release of liquid hydrogen the white visible cloud formed by air condensation or solidification is generated rapidly and spread widely and the visible cloud is most obvious near the ground. With the termination of liquid hydrogen release solid air is deposited on the ground and the visible clouds gradually shrink from the far field to the release source. Hydrogen concentration fluctuations in the far field in the case of the cobblestone ground are more dependent on spontaneous diffusion by the hydrogen concentration gradient. In addition compared with the concrete ground the cobblestone ground has greater resistance to liquid hydrogen extension; the diffusion of hydrogen clouds to the far field lags. The rapid increase stage of hydrogen concentration at N8 in Test 7 lags about 3 s behind N12 in Test 6 N3 lags about 7.5 s behind N1 and N16 lags about 8.25 s behind N14. The near-source space is prone to high-concentration hydrogen clouds. The duration of the high-concentration hydrogen cloud at N12 is about 15 s which is twice as long as the duration at N8 increasing the safety risk of the near-source space.

To achieve carbon neutrality in Japan by 2050 renewable energy needs to be used as the main energy source. Based on the constraints of various renewable energies the importance of hydrogen cannot be ignored. This study aimed to investigate the diffusion of hydrogen demand technologies in various sectors and used projections and assumptions to investigate the hydrogen supply side. By performing simulations with the E3ME-FTT model and comparing various policy scenarios with the reference scenario the economic and environmental impacts of the policy scenarios for hydrogen diffusion were analyzed. Moreover the impact of realizing carbon neutrality by 2050 on the Japanese economy was evaluated. Our results revealed that large-scale decarbonization via hydrogen diffusion is possible (90% decrease of CO2 emissions in 2050 compared to the reference) without the loss of economic activity. Additionally investments in new hydrogen-based and other low-carbon technologies in the power sector freight road transport and iron and steel industry can improve the gross domestic product (1.6% increase in 2050 compared to the reference) as they invoke economic activity and require additional employment (0.6% increase in 2050 compared to the reference). Most of the employment gains are related to decarbonizing the power sector and scaling up the hydrogen supply sector while a lot of job losses can be expected in the mining and fossil fuel industries.

This study develops a an optimization model focused on the layout and dispatch of a low-carbon hydrogen supply chain. The objective is to identify the lowest Levelized Cost of Hydrogen for a given demand. The model considers various elements including electricity supply from the local grid and renewable sources (photovoltaic and wind) alongside hydrogen production compression storage and transportation to end users. Applied to an industrial case study in Sweden the findings indicate that the major cost components are linked to electricity generation and investment in electrolyzers with the LCOH reaching 5.2 EUR/kgH2 under typical demand conditions. Under scenarios with higher peak demands and greater demand volatility the LCOH increases to 6.8 EUR/kgH2 due to the need for additional renewable energy capacity. These results highlight the critical impact of electricity availability and demand fluctuations on the LCOH emphasizing the complex interdependencies within the hydrogen supply chain. This study provides valuable insights into the feasibility and cost-effectiveness of adopting hydrogen as an energy carrier for renewable electricity in the context of decarbonizing industrial processes in the energy system.

Green hydrogen produced by water electrolysis is one of the most promising technologies to realize the efficient utilization of intermittent renewable energy and the decarbonizing future. Among various electrolysis technologies the emerging anion-exchange membrane water electrolysis (AEMWE) shows the most potential for producing green hydrogen at a competitive price. In this review we demonstrate a comprehensive introduction to AEMWE including the advanced electrode design the lab-scaled testing system establishment and the electrochemical performance evaluation. Specifically recent progress in developing high activity transition metal-based powder electrocatalysts and self-supporting electrodes for AEMWE is summarized. To improve the synergistic transfer behaviors between electron charge water and gas inside the gas diffusion electrode (GDE) two optimizing strategies are concluded by regulating the pore structure and interfacial chemistry. Moreover we provide a detailed guideline for establishing the AEMWE testing system and selecting the electrolyzer components. The influences of the membrane electrode assembly (MEA) technologies and operation conditions on cell performance are also discussed. Besides diverse electrochemical methods to evaluate the activity and stability implement the failure analyses and realize the in-situ characterizations are elaborated. In end some perspectives about the optimization of interfacial environment and cost assessments have been proposed for the development of advanced and durable AEMWE.

Hydrogen is a new promising energy source. Three operating parameters including inlet gas flow rate pH and impeller speed mainly determine the biohydrogen production from membrane bioreactor. The work aims to boost biohydrogen production by determining the optimal values of the control parameters. The proposed methodology contains two parts: modeling and parameter estimation. A robust ANIFS model to simulate a membrane bioreactor has been constructed for the modeling stage. Compared with RMS thanks to ANFIS the RMSE decreased from 2.89 using ANOVA to 0.0183 using ANFIS. Capturing the proper correlation between the inputs and output of the membrane bioreactor process system encourages the constructed ANFIS model to predict the output performance exactly. Then the optimal operating parameters were identified using the honey badger algorithm. During the optimization process inlet gas flow rate pH and impeller speed are used as decision variables whereas the biohydrogen production is the objective function required to be maximum. The integration between ANFIS and HBA boosted the hydrogen production yield from 23.8 L to 25.52 L increasing by 7.22%.

The majority penetration of Variable Renewable Energy (VRE) will challenge the stability of electrical transmission grids due to unpredictable peaks and troughs of VRE generation. With renewable generation located further from high demand urban cores there will be a need to develop new transmission pathways to deliver the power. This paper compares the transport and storage of VRE through a hydrogen pipeline to the transport of VRE through a High Voltage Direct Current (HVDC) transmission line. The analysis found a hydrogen pipeline can offer a cost-competitive method for VRE transmission compared to a HVDC transmission line on a life-cycle cost basis normalized by energy flows for distances at 1000 miles with 2030 technology. This finding has implications for policy makers project developers and system operators for the future development of transmission infrastructure projects given the additionality which hydrogen pipelines can provide in terms of energy storage.

This study presents a novel framework for improving the resilience of microgrids based on the power-to-hydrogen concept and the ability of microgrids to operate independently (i.e. islanded mode). For this purpose a model is being developed for the resilient operation of microgrids in which the compressed hydrogen produced by power-to-hydrogen systems can either be used to generate electricity through fuel cells or sold to other industries. The model is a bi-objective optimization problem which minimizes the cost of operation and resilience by (i) reducing the active power exchange with the main grid (ii) reducing the ohmic power losses and (iii) increasing the amount of hydrogen stored in the tanks. A solution approach is also developed to deal with the complexity of the bi-objective model combining a goal programming approach and Generalized Benders Decomposition due to the mixed-integer nonlinear nature of the optimization problem. The results indicate that the resilience approach although increasing the operation cost does not lead to load shedding in the event of main grid failures. The study concludes that integrating distributed power-to-hydrogen systems results in significant benefits including emission reductions of up to 20 % and cost savings of up to 30 %. Additionally the integration of the decomposition method improves computational performance by 54 % compared to using commercial solvers within the GAMS software.

The article presents a new carbon-free heat production technology for district heating which consists of a combined heat and power generation fuel cell (FC CHP) with CO2 capture and a two-stage cascade high-temperature heat pump (TCHHP). The FC generates heat and electricity the latter being used to drive the compressors of the TCHHP. During the winter period the water temperature achieved can occasionally be too low so it would be heated up with hydrogen gas boilers. The hydrogen would be produced by reforming natural gas synthetic methane or biogas. The results are presented with natural gas utilization—the ratio between the obtained heat flow transferred directly to the water for district heating and the input heat flow of natural gas. In the case of a return water temperature of 60 ◦C and district heating temperature of 85 ◦C the TCHHP whose heat source is groundwater achieves plant efficiency of 270.04% in relation to the higher heating value (HHV) and 241.74% in relation to the lower heating value (LHV) of natural gas. A case with a TCHHP whose heat source is low-temperature geothermal water achieves a plant efficiency of 361.36% in relation to the HHV and 323.49% in relation to the LHV

The demand for fossil fuels is rising rapidly leading to increased greenhouse gas emissions. Hydrogen has emerged as a promising clean energy alternative that could help meet future demands way sustainably especially if produced using renewable methods. For hydrogen to meaningfully contribute to energy transitions it needs more integration into sectors like transportation buildings and power that currently have minimal hydrogen usage. This requires developing extensive cross-sector hydrogen infrastructure. This review examines hydrogen combustion as a fuel by exploring and comparing production techniques enriching ammonia with hydrogen as a CO2-free option and hydrogen applications in engines. Additionally a techno-economic environmental risk analysis is discussed. Results showed steam methane reforming is the most established and cost-effective production method at $1.3–1.5/kg H2 and 70–85% efficiency but generates CO2. Biomass gasification costs $1.25–2.20/kg H2 and pyrolysis $1.77–2.05/kg H2 offering renewable options. However bio-photolysis currently has high costs of $1.42–2.13/kg H2 due to low conversion rates requiring large reactors. Blending H2/NH3 could enable carbon-free combustion aiding carbon neutrality pursuits but minimizing resultant NOx is crucial. Hydrogen’s wide uses from transportation to power underline its potential as a transformational energy carrier.

To facilitate the rapid and large-scale developments of offshore wind energy scholars policymakers and infrastructure developers must start considering its integration into the larger onshore energy system. Such offshore system integration is defined as the coordinated approach to planning and operation of energy generation transport and storage in the offshore energy system across multiple energy carriers and sectors. This article conducts a systematic literature review to identify infrastructure components of offshore energy system integration (including alternative cable connections offshore energy storage and power-to-hydrogen applications) and barriers to their development. An interdisciplinary perspective is provided where current offshore developments require not only mature and economically feasible technologies but equally strong legal and governance frameworks. The findings demonstrate that current literature lacks a holistic perspective on the offshore energy system. To date techno-economic assessments solving challenges of specific infrastructure components prevail over an integrated approach. Nevertheless permitting issues gaps in legal frameworks strict safety and environmental regulations and spatial competition also emerge as important barriers. Overall this literature review emphasizes the necessity of aligning various disciplines to provide a fundamental approach for the development of an integrated offshore energy system. More specifically timely policy and legal developments are key to incentivize technical development and enable economic feasibility of novel components of offshore system integration. Accordingly to maximize real-world application and policy learning future research will benefit from an interdisciplinary perspective.

Geological structures in deep aquifers and salt caverns can play an important role in large-scale hydrogen storage. However more work needs to be done to address the hydrogen storage demand for zero-emission energy systems. Thus the aim of the article is to present the demand for hydrogen storage expressed in the number of salt caverns in bedded rock salt deposits and salt domes or the number of structures in deep aquifers. The analysis considers minimum and maximum hydrogen demand cases depending on future energy system configurations in 2050. The method used included the estimation of the storage capacity of salt caverns in bedded rock salt deposits and salt domes and selected structures in deep aquifers. An estimation showed a large hydrogen storage potential of geological structures. In the case of analyzed bedded rock salt deposits and salt domes the average storage capacity per cavern is 0.05–0.09 TWhH2 and 0.06–0.20 TWhH2 respectively. Hydrogen storage capacity in analyzed deep aquifers ranges from 0.016 to 4.46 TWhH2. These values indicate that in the case of the upper bound for storage demand there is a need for the 62 to 514 caverns depending on considered bedded rock salt deposits and salt domes or the 9 largest analyzed structures in deep aquifers. The results obtained are relevant to the discussion on the global hydrogen economy and the methodology can be used for similar considerations in other countries.

The importance of the energy transition and the role of green hydrogen in facilitating this transition cannot be denied. Therefore it is crucial to pay close attention to and thoroughly understand hydrogen storage which is a critical aspect of the hydrogen supply chain. In this comprehensive review paper we have undertaken the task of categorising and evaluating various hydrogen storage technologies across three different scales. These scales include small-scale and laboratory-based methods such as metal-based hydrides physical adsorbents and liquid organic hydrogen carriers. Also we explore medium and large-scale approaches like compressed gaseous hydrogen liquid cryogenic hydrogen and cryocompressed hydrogen. Lastly we delve into very large-scale options such as salt caverns aquifers depleted gas/oil reservoirs abandoned mines and hard rock caverns. We have thoroughly examined each storage technology from technical and maturity perspectives as well as considering its techno-economic viability. It is worth noting that development has been ongoing for each storage mechanism; however numerous technical and economic challenges persist in most areas. Particularly the cost per kilogramme of hydrogen for most current technologies demands careful consideration. It is recommended that small-scale hydrogen storage technologies such as metal hydrides (e.g. MgH2 LiBH4) need ongoing research to enhance their performance. Physical adsorbents have limited capacity except for activated carbon. Some liquid organic hydrogen carriers (LCOHs) are suitable for medium-scale storage in the near term. Ammonia-borane (AB) with its high gravimetric and volumetric properties is a promising choice for medium-scale storage pending effective dehydrogenation. It shows potential as a hydrogen carrier due to its high storage capacity stability and solubility surpassing DOE targets for storage capabilities. Medium-scale storage utilising compressed gas cylinders and advancements in liquefied and cryocompressed hydrogen storage requires cost reduction measures and a strategic supply chain. Large-scale storage options include salt caverns aquifers and depleted gas/oil reservoirs with salt caverns offering pure hydrogen need further technoeconomic analysis and deployment projects to mature but storage costs are reasonable ranging mostly from €0.25/kg to €1.5/kg for location specific large-scale options.

The intermittency of renewable energy technologies requires adequate storage technologies. Hydrogen systems consisting of electrolysers storage tanks and fuel cells can be implemented as well as batteries. The requirements of the hydrogen purification unit is missing from literature. We measured the same for a 4.5 kW PEM electrolyser to be 0.8 kW for 10 min. A simulation to hybridize the hydrogen system including its purification unit with lithium-ion batteries for energy storage is presented; the batteries also support the electrolyser. We simulated a scenario for operating a Dutch household off-electric-grid using solar and wind electricity to find the capacities and costs of the components of the system. Although the energy use of the purification unit is small it influences the operation of the system affecting the sizing of the components. The battery as a fast response efficient secondary storage system increases the ability of the electrolyser to start up.

Energy and environmental issues are of great importance in the present era. The transition to renewable energy sources necessitates technological political and behavioral transformations. Hydrogen is a promising solution and many countries are investing in the hydrogen economy. Global demand for hydrogen is expected to reach 120 million tonnes by 2024. The incorporation of hydrogen for efficient energy transport and storage and its integration into the transport sector are crucial measures. However to fully develop a hydrogen-based economy the sustainability and safety of hydrogen in all its applications must be ensured. This work describes and compares different technologies for hydrogen production storage and utilization (especially in fuel cell applications) with focus on the research activities under study at SaRAH group of the University of Naples Federico II. More precisely the focus is on the production of hydrogen from bio-alcohols and its storage in formate solutions produced from renewable sources such as biomass or carbon dioxide. In addition the use of materials inspired by nature including biowaste as feedstock to produce porous electrodes for fuel cell applications is presented. We hope that this review can be useful to stimulate more focused and fruitful research in this area and that it can open new avenues for the development of sustainable hydrogen technologies.