Publications

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.

The forthcoming implementation of national policies towards hydrogen blending into the natural gas grid will affect the technical and economic parameters that must be taken into account in the design of building heating systems. This study evaluates the implications of using hydrogenenriched natural gas (H2NG) blends in condensing boilers and Gas Adsorption Heat Pumps (GAHPs) in a residential building in Rome Italy. The analysis considers several parameters including nonrenewable primary energy consumption CO2 emissions Levelized Cost of Heat (LCOH) and Carbon Abatement Cost (CAC). The results show that a 30% hydrogen blend achieves a primary energy consumption reduction of 12.05% and 11.19% in boilers and GAHPs respectively. The presence of hydrogen in the mixture exerts a more pronounced influence on the reduction in fossil primary energy and CO2 emissions in condensing boilers as it enhances combustion efficiency. The GAHP system turns out to be more cost-effective due to its higher efficiency. At current hydrogen costs the LCOH of both technologies increases as the volume fraction of hydrogen increases. The forthcoming cost reduction in hydrogen will reduce the LCOH and the decarbonization cost for both technologies. At low hydrogen prices the CAC for boilers is lower than for GAHPs; therefore replacing boilers with other gas technologies rather than electric heat pumps increases the risk of creating stranded assets. In conclusion blending hydrogen into the gas grid can be a useful policy to reduce emissions from the overall natural gas consumption during the process of end-use electrification while stimulating the development of a hydrogen economy.

Given China’s ambition to realize carbon peak by 2030 and carbon neutralization by 2060 hydrogen is gradually becoming the pivotal energy source for the needs of energy structure optimization and energy system transformation. Thus hydrogen combined with renewable energy has received more and more attention. Nowadays power-to-hydrogen power-to-methanol and power-to-ammonia are regarded as the most promising three hydrogen-driven power-to-X technologies due to the many commercial or demonstration projects in China. In this paper these three hydrogen-driven power-to-X technologies and their application status in China are introduced and discussed. First a general introduction of hydrogen energy policies in China is summarized and then the basic principles technical characteristics trends and challenges of the three hydrogen-driven power-to-X technologies are reviewed. Finally several typical commercial or demonstration projects are selected and discussed in detail to illustrate the development of the power-to-X technologies in China.

A sustainable future hydrogen economy hinges on the development of green hydrogen and the shift away from grey hydrogen but this is highly reliant on reducing production costs which are currently too high for green hydrogen to be competitive. This study predicts the cost trajectory of alkaline and proton exchange membrane (PEM) electrolyzers based on ongoing research and development (R&D) scale effects and experiential learning consequently influencing the levelized cost of hydrogen (LCOH) projections. Electrolyzer capital costs are estimated to drop to 88 USD/kW for alkaline and 60 USD/kW for PEM under an optimistic scenario by 2050 or 388 USD/kW and 286 USD/kW respectively under a pessimistic scenario with PEM potentially dominating the market. Through a combination of declining electrolyzer costs and a levelized cost of electricity (LCOE) the global LCOH of green hydrogen is projected to fall below 5 USD/kgH2 for solar onshore and offshore wind energy sources under both scenarios by 2030. To facilitate a quicker transition the implementation of financial strategies such as additional revenue streams a hydrogen/carbon credit system and an oxygen one (a minimum retail price of 2 USD/kgO2 ) and regulations such as a carbon tax (minimum 100 USD/tonCO2 for 40 USD/MWh electricity) and a contract-for-difference scheme could be pivotal. These initiatives would act as financial catalysts accelerating the transition to a greener hydrogen economy.

Clean hydrogen is a key pillar for the net zero economy which can be deployed by consistent utilization on heavy-duty transport. This study investigates a distributed green hydrogen infrastructure (DHI) for heavy-duty transportation consisting of on-site hydrogen production storage compression and refueling systems in Italy. Two options for energy supply are analyzed: grid connection using green energy via Power Purchasing Agreements (PPAs) and direct connection to the photovoltaic field respectively. Radiation data are representative of the three main Italian areas namely South (Catania) Center (Roma) and North (Milano). The sensitivity analysis varies the PPA value between 50 V/MWh and 200 V/MWh and the water electrolysis capacity factor between 20% and 100%. The study finds that the LCOH ranges from 7.4 V/kgH2 to 67.8 V/kgH2 for the first option and 5.5 V/kgH2 to 27.5 V/kgH2 for the second option with Southern Italy having the lowest LCOH due to higher solar irradiation. The research shows that a DHI can offer economic and technical benefits for heavy-duty mobility. However the performance is highly influenced by external conditions such as hydrogen demand and electricity prices. This study provides valuable insights into designing and operating a DHI for heavy-duty mobility promoting a carbon-free society.

This study introduced the methodology for integrating ethylene glycol/water mixture (GW) systems which supply heat energy to the liquid hydrogen (LH2 ) fuel gas supply system (FGSS) and manage the temperature conditions of the battery system. All systems were designed and simulated based on the power demand of a 2 MW class platform supply vessel assumed as the target ship. The LH2 FGSS model is based on Aspen HYSYS V14 and the cell model that makes up the battery system is implemented based on a Thevenin model with four parameters. Through three different simulation cases the integrated GW system significantly reduced electric power consumption for the GW heater during ship operations achieving reductions of 1.38% (Case 1) 16.29% (Case 2) and 27.52% (Case 3). The energy-saving ratio showed decreases of 1.86% (Case 1) 21.01% (Case 2) and 33.80% (Case 3) in overall energy usage within the GW system. Furthermore an examination of the battery system’s thermal management in the integrated GW system demonstrated stable cell temperature control within ±3 K of the target temperature making this integration a viable solution for maintaining normal operating temperatures despite relatively higher fluctuations compared to an independent GW system.

To address the inherent intermittency and instability of renewable energy the construction of large-scale energy storage facilities is imperative. Salt caverns are internationally recognized as excellent sites for large-scale energy storage. They have been widely used to store substances such as natural gas oil air and hydrogen. With the global transition in energy structures and the increasing demand for renewable energy load balancing there is broad market potential for the development of salt cavern energy storage technologies. There are three types of energy storage in salt caverns that can be coupled with renewable energy sources namely salt cavern compressed air energy storage (SCCAES) salt cavern hydrogen storage (SCHS) and salt cavern flow battery (SCFB). The innovation of this paper is to comprehensively review the current status and future development trends of these three energy storage methods. Firstly the development status of these three energy storage methods both domestically and internationally is reviewed. Secondly according to the characteristics of these three types of energy storage methods some key technical challenges are proposed to be focused on. The key technical challenge for SCCAES is the need to further reduce the cost of the ground equipment; the key technical challenge for SCHS is to prevent the risk of hydrogen leakage; and the key technical challenge for SCFB is the need to further increase the concentration of the active substance in the huge salt cavern. Finally some potential solutions are proposed based on these key technical challenges. This work is of great significance in accelerating the development of salt cavern energy storage technologies in coupled renewable energy.

The development of a Clean Hydrogen Standard based on life-cycle greenhouse gas (GHG) emissions is gaining prominence on the international agenda. Thus a framework for assessing life-cycle GHG emissions for clean hydrogen pathways is necessary. In this study the comprehensive datasets and effects of various scenarios encompassing hydrogen production carriers (liquid hydrogen ammonia methylcyclohexane) carbon capture and storage (CCS) target analysis year (2021 2030) to reflect trends of greening grid electricity and potential import countries on aggregated life-cycle GHG emissions were presented. South Korea was chosen as a case study region and the low-carbon alternatives were suggested for reducing aggregated emissions to meet the Korean standard (5 kgCO2e/kgH2). First capturing and storing nearly entire (>90%) CO2 from fossil- and waste-based production pathways is deemed essential. Second when repurposing the use of hydrogen that was otherwise used internally applying a penalty for substitution is appropriate leading to results notably exceeding the standard. Third for electrolysis-based hydrogen using renewable or nuclear electricity is essential. Lastly when hydrogen is imported in a well-to-point-of-delivery (WtP) perspective using renewable electricity during hydrogen conversion into a carrier and reusing the produced hydrogen for endothermic reconversion reaction are recommended. By implementing the developed calculation framework to other countries' cases it was observed that importing hydrogen to regions having scope of WtP or above (e.g. well-to-wheel) might not meet the threshold due to additional emissions from importation processes. Additionally for hydrogen carriers undergoing the endothermic reconversion the approach to reduce WtP emissions (reusing produced hydrogen) may conflict with the approach to reduce well-to-gate (WtG) emission (using external fossilbased fuel). The discrepancy highlights the need to set a broader scope of emissions assessment to effectively promote the life-cycle emission reduction efforts of hydrogen importers. This study contributes to the field of clean hydrogen GHG emission assessment offering a robust database and calculation framework while addressing the effects of greening grid electricity and CCS implementation proposing low-carbon alternatives and GHG assessment scope to achieve global GHG reduction.

This study develops a novel community-based integrated energy system where hydrogen and a combination of renewable energy sources are considered uniquely for implementation. In this regard three different communities situated in Kenya the United States and Australia are studied for hydrogen production and meeting the energy demands. To provide a variety of energy demands this study combines a multigenerational geothermal plant with a hybrid concentrated solar power and photovoltaic solar plant. Innovations in hydrogen production and renewable energy are essential for reducing carbon emissions. By combining the production of hydrogen with renewable energy sources this system seeks to move away from the reliance on fossil fuels and toward sustainability. The study investigates various research subjects using a variety of methods. The performance of the geothermal source is considered through energetic and exergetic thermodynamic analysis. The software System Advisor Model (SAM) and RETscreen software packages are used to analyze the other sub-systems including Concentrate Solar PV solar and Combined Heat and Power Plant. Australian American and Kenyan communities considered for this study were found to have promising potential for producing hydrogen and electricity from renewable sources. The geothermal output is expected to be 35.83 MW 122.8 MW for space heating 151.9 MW for industrial heating and 64.25 MW for hot water. The overall geothermal energy and exergy efficiencies are reported as 65.15% and 63.54% respectively. The locations considered are expected to have annual solar power generation and hydrogen production capacities of 158MW 237MW 186MW 235 tons 216 tons and 313 tons respectively.

This research conducted a probabilistic life-cycle assessment (pLCA) into the greenhouse gas (GHG) emissions performance of nine combinations of truck size and powertrain technology for a recent past and a future (largely decarbonised) situation in Australia. This study finds that the relative and absolute life-cycle GHG emissions performance strongly depends on the vehicle class powertrain and year of assessment. Life-cycle emission factor distributions vary substantially in their magnitude range and shape. Diesel trucks had lower life-cycle GHG emissions in 2019 than electric trucks (battery hydrogen fuel cell) mainly due to the high carbon-emission intensity of the Australian electricity grid (mainly coal) and hydrogen production (mainly through steam–methane reforming). The picture is however very different for a more decarbonised situation where battery electric trucks in particular provide deep reductions (about 75–85%) in life-cycle GHG emissions. Fuel-cell electric (hydrogen) trucks also provide substantial reductions (about 50–70%) but not as deep as those for battery electric trucks. Moreover hydrogen trucks exhibit the largest uncertainty in emissions performance which reflects the uncertainty and general lack of information for this technology. They therefore carry an elevated risk of not achieving the expected emission reductions. Battery electric trucks show the smallest (absolute) uncertainty which suggests that these trucks are expected to deliver the deepest and most robust emission reductions. Operational emissions (on-road driving and vehicle maintenance combined) dominate life-cycle emissions for all vehicle classes. Vehicle manufacturing and upstream emissions make a relatively small contribution to life-cycle emissions from diesel trucks (

This paper provides an in-depth analysis of alternative fuels including liquefied natural gas (LNG) hydrogen ammonia and biofuels assessing their feasibility based on operational requirements availability safety concerns and the infrastructure needed for large-scale adoption. Moreover it examines hybrid and fully electric propulsion systems considering advancements in battery technology and the integration of renewable energy sources such as wind and solar power to further reduce SOV emissions. Key findings from this research indicate that LNG serves as a viable short- to medium-term solution for reducing GHG emissions in the SOV sector due to its relatively lower carbon content compared to MDO and HFO. This paper finally insists that while LNG presents an immediate opportunity for emission reduction in the SOV sector a combination of hydrogen ammonia and hybrid propulsion systems will be necessary to meet long-term decarbonisation goals. The findings underscore the importance of coordinated industry efforts technological innovation and supportive regulatory frameworks to overcome the technical economic and infrastructural challenges associated with decarbonising the maritime industry.

Environmental concerns such as global warming and human health damage are intensifying and the transportation sector significantly contributes to carbon and harmful emissions. This review examines the life cycle assessment (LCA) of alternative fuels (AF) evaluating current research on fuel types LCA framework development life cycle inventory (LCI) and impact selection. The objectives of this paper are: (1) to compare various AF LCA frameworks and develop a comprehensive framework for the transportation sector; (2) to identify emission hotspots of different AFs through simulations and real-world cases; (3) to review AF LCA research; (4) to extract valuable information for potential future research directions. The analysis reveals that all stages except for hydrogen use have an environmental impact. LCA boundaries and LCIs vary considerably depending on the raw materials production processes and products involved leading to different emission hotspots. Due to knowledge or data limitations some stages remain uncalculated in the current study emphasizing the need for further refinement of the AF LCI. Future research should also explore the various impacts of widespread adoption of alternative fuels in transportation encompassing social economic and environmental aspects. Lastly the review provides structured recommendations for future research directions.

Decarbonizing road transportation is vital for addressing climate change given that the sector currently contributes to 16% of global GHG emissions. This paper presents a comparative analysis of electric and hydrogen mobility infrastructures in a remote context i.e. an off-grid island. The assessment includes resource assessment and sizing of renewable energy power plants to facilitate on-site self-production. We introduce a comprehensive methodology for sizing the overall infrastructure and carry out a set of techno-economic simulations to optimize both energy performance and cost-effectiveness. The levelized cost of driving at the hydrogen refueling station is 0.40 e/km i.e. 20% lower than the electric charging station. However when considering the total annualized cost the battery-electric scenario (110 ke/year) is more favorable compared to the hydrogen scenario (170 ke/year). To facilitate informed decision-making we employ a multi-criteria decision-making analysis to navigate through the techno-economic findings. When considering a combination of economic and environmental criteria the hydrogen mobility infrastructure emerges as the preferred solution. However when energy efficiency is taken into account electric mobility proves to be more advantageous.

Hydrogen is crucial in achieving global energy transition and carbon neutrality goals. Existing market estimates typically presume linear or exponential growth but fail to consider how market demand responds to the declining cost of underlying technologies. To address this this study utilizes a learning curve model to project the cost of electrolyzers and its subsequent impact on hydrogen market aligning with a premise that the market demand is proportional to the cost of hydrogen. In a case study of China’s hydrogen market projecting from 2020 to 2060 we observed substantial differences in market evolution compared to exponential growth scenarios. Contrary to exponential growth scenarios China’s hydrogen market experiences faster growth during the 2020–2040 period rather than later. Such differences underscore the necessity for proactive strategic planning in emerging technology markets particularly for those experiencing rapid cost decline such as hydrogen. The framework can also be extended to other markets by using local data providing valuable insights to investors policymakers and developers engaged in the hydrogen market.

As one core component in hydrogen fuel cells and water electrolysis cells bipolar plates (BPs) perform multiple important functions such as separating the fuel and oxidant flow providing mechanical support conducting electricity and heat connecting the cell units into a stack etc. On the path toward commercialization the manufacturing costs of bipolar plates have to be substantially reduced by adopting low-cost and easy-to-process metallic materials (e.g. stainless steel aluminum or copper). However these materials are susceptible to electrochemical corrosion under harsh operating conditions resulting in long-term performance degradation. By means of advanced thermal spraying technologies protective coatings can be prepared on bipolar plates so as to inhibit oxidation and corrosion. This paper reviews several typical thermal spraying technologies including atmospheric plasma spraying (APS) vacuum plasma spraying (VPS) and high-velocity oxygen fuel (HVOF) spraying for preparing coatings of bipolar plates particularly emphasizing the effect of spraying processes on coating effectiveness. The performance of coatings relies not only on the materials as selected or designed but also on the composition and microstructure practically obtained in the spraying process. The temperature and velocity of in-flight particles have a significant impact on coating quality; therefore precise control over these factors is demanded.

Hydrogen is deemed as a crucial component in the transition to a carbon-free energy system and researchers are actively working to realize the hydrogen economy. While hydrogen derived from renewable energy sources is a promising means of providing clean energy to households and industries its practical usage is currently hindered by difficulties in transportation and storage. Due to the extreme operating conditions required for liquefying hydrogen various hydrogen carriers are being considered which can be transported and stored at mild operating conditions and provide hydrogen at the site of usage. Among various candidates green hydrogen carriers obtained via carbon dioxide utilization have been proposed as an economically and environmentally feasible option. Herein the potential of using methanol and formic acid as green hydrogen carriers are evaluated regarding various production and dehydrogenation pathways within a hydrogen distribution system including the recycle of carbon dioxide. Recent progress in carbon dioxide utilization processes especially conversion of carbon dioxide captured in amine solutions have demonstrated promising results for methanol and formic acid production. This study analyzes seven scenarios that consider carbon dioxide utilization-based thermocatalytic and electrochemical methanol and formic acid production as well as different dehydrogenation pathways and compares them to the scenario of delivering liquefied hydrogen. The scenarios are thoroughly analyzed via techno-economic analysis and life cycle assessment methods. The results of the study indicate that methanol-based options are economically viable reducing the cost up to 43% compared to liquefied hydrogen delivery. As for formic acid only the electrochemical production method is profitable retaining 10% less cost compared to liquefied hydrogen delivery. In terms of environmental impact all of the scenarios show higher global warming impact values than liquefied hydrogen distribution. However results show that in an optimistic case where wind electricity is widely used electrochemical formic acid production is competitive with liquefied hydrogen distribution retaining 39% less global warming impact values. This is because high conversion can be achieved at mild operating conditions for the production and dehydrogenation reactions of formic acid reducing the input of utilities other than electricity. This study suggests that while methanol can be a shortterm solution for hydrogen distribution electrochemical formic acid production may be a viable long-term option.

Solar hydrogen production is a promising pathway for sustainable CO2 -free hydrogen production. It is mainly classified into three systems: photovoltaic electrolysis (PV-EC) photoelectrochemical (PEC) system and particulate photocatalytic (PC) system. However it still has trouble in commercialization due to the limitation of performance and economic feasibility in the large-scale system. In this review the challenges of each large-scale system are respectively summarized. Based on this summary recent approaches to solving these challenges are introduced focusing on core components fabrication processes and systematic designs. In addition several demonstrations of large-scale systems under outdoor conditions and performances of upscaled systems are introduced to understand the current technical level of solar-driven hydrogen production systems for commercialization. Finally the future outlooks and perspectives on the practical application of large-scale solar-driven hydrogen production are discussed.

Transporting hydrogen gas has long been identified as one of the key issues to scaling up the hydrogen economy. Among various means of transportation many countries are considering using the existing natural gas pipeline networks for hydrogen transmission. This paper examines the implications of transporting hydrogen on the operational metrics of the high-pressure natural gas networks. A model of the GB high-pressure gas network was developed which has a high granularity with 294 nodes 356 pipes and 24 compressor stations. The model was developed using Synergi Gas a hydraulic pipeline network simulation software. By performing unsteady-state analysis pressure levels linepack levels and compressor energy consumption were simulated with 10-minute time steps. Additionally component tracing analysis was utilised to examine the variations in gas composition when hydrogen is injected into the gas network. Five scenarios were developed: one benchmark scenario representing the network transporting natural gas in 2018; one scenario where demand and supply levels are projected for 2035 but no hydrogen was transported by the network; two hydrogen injection scenarios in 2035 considering different geographical locations for hydrogen injection into the gas network; and lastly one pure hydrogen transmission scenario for 2050. The studies found that the GB’s high-pressure gas network could accept 20% volumetric hydrogen injection without significantly impacting network operation. Pressure levels and compressor energy consumption remain within the operational range. The geographical distribution of hydrogen injection points would highly affect the percentage of hydrogen across the network. Pure hydrogen transportation will cause significant variations in network linepack and increase compressor energy consumption significantly compared to other case studies. The findings signal that operating a network with pure hydrogen is possible only when it is prepared for these changes.

Ever more stringent emission regulations for vehicles encourage increasing numbers of battery electric vehicles on the roads. A drawback of storing electric energy in a battery is the comparable low energy density low driving range and the higher propensity to deplete the energy storage before reaching the destination especially at low ambient temperatures. When the battery is depleted stranded vehicles can either be towed or recharged with a mobile recharging station. Several technologies of mobile recharging stations already exist however most of them use fossil fuels to recharge battery electric vehicles. The proposed novel zero emission solution for mobile charging is a combined high voltage battery and hydrogen fuel cell charging station. Due to the thermal characteristics of the fuel cell and high voltage battery (which allow only comparable low coolant temperatures) the thermal design for this specific application (available heat exchanger area zero vehicle speed air flow direction) becomes challenging and is addressed in this work. Experimental methods were used to obtain reliable thermal and electric power measurement data of a 30 kW fuel cell system which is used in the Mobile Hydrogen Powersupply. Subsequently simulation methods were applied for the thermal design and optimisation of the coolant circuits and heat exchangers. It is shown that an battery electric vehicle charging power of 22 kW requires a heat exchanger area of 1 m2 of which 60 % is used by the fuel cell heat exchanger and the remainder by the battery heat exchanger to achieve steady state operation at the highest possible ambient temperature of 436 °C. Furthermore the simulation showed that when the charging power of 22 kW is solely provided by the high voltage battery the highest possible ambient temperature is 42 °C. When the charging power is decreased operation up to the maximum ambient temperatures of 45 °C can be achieved. The results of maximum charging power and limiting ambient temperature give insights for further system improvements which are: sizing of fuel cell or battery trailer design and heat exchanger area operation strategy of the system (power split between high voltage battery and fuel cell) as well as possible dynamic operation scenarios.

Nowadays there is an intense debate in the European Union (EU) regarding the limits to achieve the European Green Deal to make Europe the first climate-neutral continent in the world. In this context there are also different opinions about the role that thermal engines should play. Furhermore there is no clear proposal regarding the possibilities of the use of green hydrogen in the transport decarbonization process even though it should be a key element. Thus there are still no precise guidelines regarding the role of green hydrogen with it being exclusively used as a raw material to produce E-fuels. This review aims to evaluate the possibilities of applying the different alternative technologies available to successfully complete the process already underway to achieve Climate Neutrality by about 2050 depending on the maturity of the technologies currently available and those anticipated to be available in the coming decades.

The study presents a thermodynamic and economic assessment of different hydrogen storage solutions for heating purposes powered by PV panels of a 10-apartment residential building in Milan and it focuses on compressed hydrogen liquid hydrogen and metal hydride. The technical assessment involves using Python to code thermodynamic models to address technical and thermodynamic performances. The economic analysis evaluates the CAPEX the ROI and the cost per unit of stored hydrogen and energy. The study aims to provide an accurate assessment of the thermodynamic and economic indicators of three of the storage methods introduced in the literature review pointing out the one with the best techno-economic performance for further development and research. The performed analysis shows that compressed hydrogen represents the best alternative but its cost is still too high for small residential applications. Applying the technology to a big system case would enable the solution making it economically feasible.

The importance of new alternative fuels has assumed great relevance in the last decades to face the issues of global warming and pollutant emissions from energy production. The scientific community is responsible for developing solutions to achieve the necessary environmental restriction policies. In this context ammonia appears as a potential fuel candidate and energy vector that may solve the technological difficulties of using hydrogen (H2 ) directly in internal combustion engines. Its high hydrogen content per unit mass higher energy density than liquid hydrogen well-developed infrastructure and experience in handling and storage make it suitable to be implemented as a long-term solution. In this work a virtual engine model was developed to perform prospective simulations of different operating conditions using ammonia and H2 -enriched ammonia as fuel in a spark-ignition (SI) engine integrating a chemical kinetics model and empirical correlations for combustion prediction. In addition specific conditions were evaluated to consider and to understand the governing parameters of ammonia combustion using computational fluid dynamics (CFD) simulations. Results revealed similar thermal efficiency than methane fuel with considerable improvements after appropriate H2 - enrichment. Moreover increasing the intake temperature and the turbulence intensity inside the cylinder evinced significant reductions in combustion duration. Finally higher compression ratios ensure efficiency gains with no evidence of abnormal combustion (knocking) even at high compression ratios (above 16:1) and low engine speeds (800 rpm). Numerical simulations showed the direct influence of the flame front surface area and the turbulent combustion velocity on efficiency reflecting the need for optimizing the SI engines design paradigm for ammonia applications.

As part of executing 25 hydrogen-based Power to X (PtX) projects our team of Safety consultants has completed safety and risk assessments for a number of hydrogen production developments. Drawing on this experience we will present the importance of making comparisons between hydrogen specific data sources such as HyRAM and conventional oil and gas data sets and calculation methods to ensure that project design is carried out to the most appropriate data and provides a robust solution to demonstrate risks are managed. This presentation will be based on case studies where Fire and Explosion Risk Assessments (FERA) and Quantitative Risk Assessments (QRA) were conducted. The frequency calculations for these assessments used the release frequencies and ignition probabilities provided in HyRAM. However it is noted that the HyRAM ignition probabilities are derived from a correlation from oil and gas assessments in the 1990s. The oil and gas approach has moved on from this data source and now derives ignition probabilities based on the type of facility and fluid characteristics. To address this evolution a comparison was made between the leak frequencies for equipment in hydrogen service and established oil and gas release frequencies from IOGP. In addition a comparison between the HyRAM recommended ignition probabilities and the correlations used for oil and gas (from OEUK formerly UKOOA) was conducted. By taking this approach it was confirmed that the UKOOA data was more conservative and sensitivity calculations were carried out. It was also noted that as hydrogen technologies are emerging there is a level of uncertainty around the data and comparisons must be regularly made to ensure the most appropriate basis for calculations is used.

Well characterized experimental data for consequence model validation is important in progressing the use of liquid hydrogen as an energy carrier. In 2019 the Health and Safety Executive (HSE) undertook a series of liquid hydrogen dispersion and combustion experiments as a part of the Pre-normative Research for Safe Use of Liquid Hydrogen (PRESLHY) project. In partnership between the National Renewable Energy Laboratory (NREL) and HSE time and spatially varying hydrogen concentration measurements were made in 25 dispersion experiments and 23 congested ignition experiments associated with PRESLHY WP3 and WP5 respectively. These measurements were undertaken using the hydrogen wide area monitoring system developed by NREL. During the 23 congested ignition experiments high variability was observed in the measured explosion severity during experiments with similar initial conditions. This led to the conclusion that wind including localized gusts had a large influence on the dispersion of the hydrogen and therefore the quantity of hydrogen that was present in the congested region of the explosions. Using the hydrogen concentration measurements taken immediately prior to ignition the hydrogen clouds were visualized in an attempt to rationalize the variability in overpressure between the tests. Gaussian process regression was applied to quantify the variability of the measured hydrogen concentrations. This analysis could also be used to guide modifications in experimental designs for future research on hydrogen combustion behavior.

An energy source transition is necessary to realize carbon neutrality emphasizing the importance of a hydrogen economy. The transportation sector accounted for 27% of annual carbon emissions in 2019 highlighting the increasing importance of transitioning to hydrogen vehicles and establishing hydrogen refueling stations (HRSs). In particular HRSs need to be prioritized for deploying hydrogen vehicles and developing hydrogen supply chains. Thus research on HRS is important for achieving carbon neutrality in the transportation sector. In this study we improved the efficiency and scaled up the capacity of an on-site HRS (based on steam methane reforming with a hydrogen production rate of 30 Nm3/h) in Seoul Korea. This HRS was a prototype with low efficiency and capacity. Its efficiency was increased through thermodynamic analysis and heat exchanger network synthesis. Furthermore the process was scaled up from 30 Nm3/h to 150 Nm3/h to meet future hydrogen demand. The results of exergy analysis indicated that the exergy destruction in the reforming reactor and heat exchanger accounted for 58.1% and 19.8% respectively of the total exergy destruction. Thus the process was improved by modifying the heat exchanger network to reduce the exergy losses in these units. Consequently the thermal and exergy efficiencies were increased from 75.7% to 78.6% and from 68.1% to 70.4% respectively. The improved process was constructed and operated to demonstrate its performance. The operational and simulation data were similar within the acceptable error ranges. This study provides guidelines for the design and installation of low-carbon on-site HRSs.