Publications

During the last two decades the use of hydrogen (H2 ) as fuel for aircraft applications has been drawing attention; more specifically its storage in liquid state (LH2 ) which is performed in extreme cryogenic temperatures (−253 ◦C) is a matter of research. The motivation for this effort is enhanced by the predicted growth of the aviation sector; however it is estimated that this growth could be sustainable only if the strategies and objectives set by global organizations for the elimination of greenhouse gas emissions during the next decades such as the European Green Deal are taken into consideration and consequently technologies such as hydrogen fuel are promoted. Regarding LH2 in aircraft substantial effort is required to design analyze and manufacture suitable tanks for efficient storage. Important tools in this process are computational methods provided by advanced engineering software (CAD/CAE). In the present work a computational study with the finite element method is performed in order to parametrically analyze proper tanks examining the effect of the LH2 level stored as well as the tank geometric configuration. In the process the need for powerful numerical models is demonstrated owing to the highly non-linear dependence on temperature of the involved materials. The present numerical models’ efficiency could be further enhanced by integrating them as part of a total aircraft configuration design loop.

Hydrogen addition affects the composition of exhaust gases in vehicles. However the effects of hydrogen addition to compression ignition engines in running vehicles have not been evaluated. Hydrogen‑mixed air was introduced into the air intake of a truck equipped with a direct‑ injection diesel engine and running on a chassis dynamometer to investigate the effect of hydrogen addition on fuel consumption and exhaust gas components. The reduction in diesel consumption and the increase in hydrogen energy share (HES) showed almost linear dependence where the percentage decrease in diesel consumption is approximately 0.6 × HES. The percentage reduction of CO2 showed a one‑to‑one relationship to the reduction in diesel consumption. The reduction in emissions of CO PM and hydrocarbons (except for ethylene) had one to one or a larger correlation with the reduction of diesel consumption. On the other hand it was observed that NOx emissions increased and the percentage increase of NOx was 1.5~2.0 times that of HES. The requirement for total energy supply was more when hydrogen was added than for diesel alone. In the actual running mode only 50% of the energy of added hydrogen was used to power the truck. As no adjustments were made to the engine in this experiment a possible disadvantage that could be improved by adjusting the combustion conditions.

Legislation regulating the sustainability requirements for hydrogen technologies relies more and more on life cycle assessments (LCAs). Due to different scopes and development processes different pieces of EU legislation refer to different LCA methodologies with differences in the way multifunctional processes (i.e. co-productions recycling and energy recovery) are treated. These inconsistencies arise because incentive mechanisms are not standardized across sectors even though the end product hydrogen remains the same. The goal of this paper is to compare the life-cycle greenhouse gas (GHG) emissions of hydrogen from four production pathways depending on the multifunctional approach prescribed by the different EU policies (e.g. using substitution or allocation). The study reveals a large variation in the LCA results. For instance the life-cycle GHG emissions of hydrogen co-produced with methanol is found to vary from 1 kg CO2-equivalent/kg H2 (when mass allocation is considered) to 11 kg CO2-equivalent/kg H2 (when economic allocation is used). These inconsistencies could affect the market (e.g. hydrogen from a certain pathway could be considered sustainable or unsustainable depending on the approach) and the environment (e.g. pathways that do not lead to a global emission reduction could be promoted). To mitigate these potential negative effects we urge for harmonized and strict guidelines to assess the life-cycle GHG emissions of hydrogen technologies in an EU policy context. Harmonization should cover international policies too to avoid the same risks when hydrogen will be traded based on its GHG emissions. The appropriate methodological approach for each production pathway should be chosen by policymakers in collaboration with the LCA community and stakeholders from the industry based on the potential market and environmental consequences of such choice.

An integrated system is studied to supply green hydrogen feedstock for ammonia production in the Netherlands. The system is modeled to compare wind and solar resources when coupled to Alkaline Electrolysis (AEL) and Proton Exchange Membrane Electrolysis (PEMEL) technologies with a compressed hydrogen storage system. The nominal installed capacity of the electrolysis plant is around 2.3 GW with the most suitable energy source offshore wind and the preferred storage technology pressurized tubes. For Alkaline Electrolysis and Proton Exchange Membrane Electrolysis technologies the levelized cost of hydrogen is 5.30 V/kg H2 and 6.03 V/kg H2 respectively.

This paper presents a comparative analysis of two hydrogen station configurations during the refueling process: the conventional “directly pressurized refueling process” and the innovative “cascade refueling process.” The objective of the cascade process is to refuel vehicles without the need for booster compressors. The experiments were conducted at the Hydrogen Research and Fueling Facility located at California State University Los Angeles. In the cascade refueling process the facility buffer tanks were utilized as high-pressure storage enabling the refueling operation. Three different scenarios were tested: one involving the cascade refueling process and two involving compressor-driven refueling processes. On average each refueling event delivered 1.6 kg of hydrogen. Although the cascade refueling process using the high-pressure buffer tanks did not achieve the pressure target it resulted in a notable improvement in the nozzle outlet temperature trend reducing it by approximately 8 ◦C. Moreover the overall hydrogen chiller load for the two directly pressurized refuelings was 66 Wh/kg and 62 Wh/kg respectively whereas the cascading process only required 55 Wh/kg. This represents a 20% and 12% reduction in energy consumption compared to the scenarios involving booster compressors during fueling. The observed refueling range of 150–350 bar showed that the cascade process consistently required 12–20% less energy for hydrogen chilling. Additionally the nozzle outlet temperature demonstrated an approximate 8 ◦C improvement within this pressure range. These findings indicate that further improvements can be expected in the high-pressure region specifically above 350 bar. This research suggests the potential for significant improvements in the high-pressure range emphasizing the viability of the cascade refueling process as a promising alternative to the direct compression approach.

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.

The main purpose of this article is to provide a short review of proton exchange membrane electrolyzer (PEMEL) modeling used for power electronics control. So far three types of PEMEL modeling have been adopted in the literature: resistive load static load (including an equivalent resistance series-connected with a DC voltage generator representing the reversible voltage) and dynamic load (taking into consideration the dynamics both at the anode and the cathode). The modeling of the load is crucial for control purposes since it may have an impact on the performance of the system. This article aims at providing essential information and comparing the different load modeling.

Hydrogen due to its high energy density stands out as an energy storage method for the car industry in order to reduce the impact of the automotive sector on air pollution and global warming. The fuel cell electric vehicle (FCEV) emerges as a modification of the electric car by adding a proton exchange membrane fuel cell (PEMFC) to the battery pack and electric motor that is capable of converting hydrogen into electric energy. In order to control the energy flow of so many elements an optimal energy management system (EMS) is needed where rule-based strategies represent the smallest computational burden and are the most widely used in the industry. In this work a rulebased operation mode control strategy for the EMS of an FCEV validated by different driving cycles and several tests at the strategic points of the battery state of charge (SOC) is proposed. The results obtained in the new European driving cycle (NEDC) show the 12 kW battery variation of 2% and a hydrogen consumption of 1.2 kg/100 km compared to the variation of 1.42% and a consumption of 1.08 kg/100 km obtained in the worldwide harmonized light-duty test cycle (WLTC). Moreover battery tests have demonstrated the optimal performance of the proposed EMS strategy

The seal and weight of the Type IV hydrogen storage vessel are the key problems restricting the safety and driving range of fuel cell vehicles. The boss as a metal medium connecting the inner liner of the Type IV hydrogen storage vessel with the external pipeline affects the sealing performance of the Type IV hydrogen storage vessel and there is no academic research on the weight of the boss. Therefore according to the force characteristics of the boss this paper divides the upper and lower areas (valve column and plate). The valve column with seal optimization and light weight is manufactured with a 3D printing additive while the plate bearing and transferring the internal pressure load is manufactured by forging. Firstly a two-dimensional axisymmetric simulation model of the sealing ring was established and the effects of different compression rates on its seal performance were analyzed. Then the size and position of the sealing groove were sampled simulated and optimized based on the Latin Hypercube method and the reliability of the optimal seal structure was verified by experiments. Finally the Solid Isotropic Material with Penalization (SIMP) topology method was used to optimize the weight of the boss with optimal sealing structure and the reconstructed model was checked and analyzed. The results show that the weight of the optimized boss is reduced by 9.6%.

Biogas and hydrogen (H2 ) are breaking through as alternative energy sources in road transport specifically for heavy-duty vehicles. Until a public network of service stations is deployed for such vehicles the owners of large fleets will need to build and manage their own refueling facilities. Fleet refueling management and remote monitoring at these sites will become key business needs. This article describes the construction of a prototype system capable of solving those needs. During the design and development process of the prototype the standard industry protocols involved in these installations have been considered and the latest expertise in information technology systems has been applied. This prototype has been essential to determine the Strengths Challenges Opportunities and Risks (SCOR) of such a system which is the first step of a more ambitious project. A second stage will involve setting up a pilot study and developing a commercial system that can be widely installed to provide a real solution for the industry.

The aim of this work is to evaluate if metal hydride hydrogen storage tanks are a competitive alternative for onboard hydrogen storage in the maritime sector when compared to compressed gas and liquid hydrogen storage. This is done by modelling different hydrogen supply and onboard storage scenarios and evaluating their levelized cost of hydrogen variables. The levelized cost of hydrogen for each case is calculated considering the main components that are required for the refueling infrastructure and adding up the costs of hydrogen production compression transport onshore storage dispensing and the cost of the onboard tanks when known. The results show that the simpler refueling needs of metal hydride-based onboard tanks result in a significant cost reduction of the hydrogen handling equipment. This provides a substantial leeway for the investment costs of metal hydride-based storage which depending on the scenario can be between 3400 - 7300 EUR/kgH2 while remaining competitive with compressed hydrogen storage.

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

Steam methane reforming (SMR) currently supplies 76% of the world’s hydrogen (H2) demand totaling ∼70 million tonnes per year. Developments in H2 production technologies are required to meet the rising demand for cleaner less costly H2. Therefore palladium membrane reactors (Pd-MR) have received significant attention for their ability to increase the efficiency of traditional SMR. This study performs novel economic analyses and constrained nonlinear optimizations on an intensified SMR process with a Pd-MR. The optimization extends beyond the membrane’s operation to present process set points for both the conventional and intensified H2 processes. Despite increased compressor and membrane capital costs along with electric utility costs the SMR-MR design offers reductions in the natural gas usage and annual costs. Economic comparisons between each plant show Pd membrane costs greater than $25 000/m2 are required to break even with the conventional design for membrane lifetimes of 1–3 years. Based on the optimized SMR-MR process this study concludes with sensitivity analyses on the design operational and cost parameters for the intensified SMR-MR process. Overall with further developments of Pd membranes for increased stability and lifetime the proposed SMR-MR design is thus profitable and suitable for intensification of H2 production.

This article proposes a supply chain-based green hydrogen microgrid modelling for a number of remote Australian communities. Green hydrogen can be used as an emissions-free fuel source for electricity generation in places where large-scale renewable energy production is impossible due to land availability population or government regulations. This research focuses on the Torres Strait Island communities in northern Australia where the transition from diesel to renewable electricity generation is difficult due to very limited land availability on most islands. Due to geographical constraints low population and smaller electrical load the green hydrogen needs to be sourced from somewhere else. This research presents a green hydrogen supply chain model that leverages the land availability of one island to produce hydrogen to supply other island communities. In addition this research presents a model of producing and transporting green hydrogen while supplying cheaper electricity to the communities at focus. The study has used a transitional scenario planning approach and the HOMER simulation platform to find the least-cost solution. Based on the results a levelised cost of energy range of AU$0.42 and AU$0.44 was found. With the help of a green hydrogen supply chain CO2 emissions at the selected sites could be cut by 90 %. This study can be used as a guide for small clustered communities that could not support or justify large-scale renewable generation facilities but need more opportunities to install renewable generation.

The Well-to-Tank study describes the process of producing transporting manufacturing and distributing a number of fuels suitable for road transport powertrains. It covers all steps from extracting capturing or growing the primary energy carrier to refuelling the vehicles with the finished fuel.

Hydrogen is considered the primary energy source of the future. The best use of hydrogen is in microgrids that have renewable energy sources (RES). These sources have a small impact on the environment when it comes to carbon dioxide (CO2 ) emissions and a power generation cost close to that of conventional power plants. Therefore it is important to study the impact on the environment and the power cost. The proposed microgrid comprises loads RESs (micro-hydro and photovoltaic power plants) a hydrogen storage tank an electric battery and fuel cell vehicles. The power cost and CO2 emissions are calculated and compared for various scenarios including the four seasons of the year compared with the work of other researchers. The purpose of this paper is to continuously supply the loads and vehicles. The results show that the microgrid sources and hydrogen storage can supply consumers during the spring and summer. For winter and autumn the power grid and steam reforming of natural gas must be used to cover the demand. The highest power costs and CO2 emissions are for winter while the lowest are for spring. The power cost increases during winter between 20:00 and 21:00 by 336%. The CO2 emissions increase during winter by 8020%.

To reduce carbon emissions generation of electricity from combustion systems is being replaced by renewable resources. However the most abundant renewable sources – solar and wind – are not dispatchable vary diurnally and are subject to intermittency and produce electricity at times in excess of demand (excess production). To manage this variability and capture the excess renewable energy energy storage technologies are being developed and deployed such as battery energy storage (BES) hydrogen production with electrolyzers (ELY) paired with hydrogen energy storage (HES) and fuel cells (FCs) and renewable natural gas (RNG) production. While BES may be better suited for short duration storage hydrogen is suited for long duration storage and RNG can decarbonize the natural gas system. California Senate Bill 100 (SB100) sets a goal that all retail electricity sold in the State must be sourced from renewable and zero-carbon resources by 2045 raising the questions of which set of technologies and in what proportion are required to meet the 2045 target in the required timeframe as well as the role of the natural gas infrastructure if any. To address these questions this study combines electric grid dispatch modeling and optimization to identify the energy storage and dispatchable technologies in 5-year increments from 2030 to 2045 required to transition from a 60% renewable electric grid in 2035 to a 100% renewable electric grid in 2045. The results show that by utilizing the established natural gas system to store and transmit hydrogen and RNG the deployment of battery energy storage is dramatically reduced. The required capacity for BES in 2045 for example is 40 times lower by leveraging the natural gas infrastructure with a concomitant reduction in cost and associated challenges to transform the electric grid.

A substantial CO2-emmissions abatement from the steel sector seems to be a challenging task without support of so-called “breakthrough technologies” such as the hydrogen-based direct reduction process. The scope of this work is to evaluate both the potential for the implementation of green hydrogen generated via electrolysis in the direct reduction process as well as the constraints. The results for this process route are compared with both the well-established blast furnace route as well as the natural gas-based direct reduction which is considered as a bridge technology towards decarbonization as it already operates with H2 and CO as main reducing agents. The outcomes obtained from the operation of a 6-MW PEM electrolysis system installed as part of the H2FUTURE project provide a basis for this analysis. The CO2 reduction potential for the various routes together with an economic study are the main results of this analysis. Additionally the corresponding hydrogen- and electricity demands for large-scale adoption across Europe are presented in order to rate possible scenarios for the future of steelmaking towards a carbon-lean industry.

This study proposed a deep reinforcement learning-based energy management strategy (DRL-EMS) that can be applied to a hybrid electric ship propulsion system (HSPS) integrating liquid hydrogen (LH2 ) fuel gas supply system (FGSS) proton-exchange membrane fuel cell (PEMFC) and lithium-ion battery systems. This study analyzed the optimized performance of the DRL-EMS and the operational strategy of the LH2 -HSPS. To train the proposed DRL-EMS a reward function was defined based on fuel consumption and degradation of power sources during operation. Fuel consumption for ship propulsion was estimated with the power for balance of plant (BOP) of the LH2 FGSS and PEMFC system. DRL-EMS demonstrated superior global and real-time optimality compared to benchmark algorithms namely dynamic programming (DP) and sequential quadratic programming (SQP)-based EMS. For various operation cases not used in training DRL-EMS resulted in 0.7% to 9.2% higher operating expenditure compared to DP-EMS. Additionally DRL-EMS was trained to operate 60% of the total operation time in the maximum efficiency range of the PEMFC system. Different hydrogen fuel costs did not affect the optimized operational strategy although the operating expenditure (OPEX) was dependent on the hydrogen fuel cost. Different capacities of the battery system did not considerably change the OPEX.

It is economical and efficient to use existing natural gas pipelines to transport hydrogen. The fast and accurate prediction of mixing uniformity of hydrogen injection in natural gas pipelines is important for the safety of pipeline transportation and downstream end users. In this study the computational fluid dynamics (CFD) method was used to investigate the hydrogen injection process in a T-junction natural gas pipeline. The coefficient of variation (COV) of a hydrogen concentration on a pipeline cross section was used to quantitatively characterize the mixing uniformity of hydrogen and natural gas. To quickly and accurately predict the COV a deep neural network (DNN) model was constructed based on CFD simulation data and the main influencing factors of the COV including flow velocity hydrogen blending ratio gas temperature flow distance and pipeline diameter ratio were taken as input nodes of the DNN model. In the model training process the effects of various parameters on the prediction accuracy of the DNN model were studied and an accurate DNN architecture was constructed with an average error of 4.53% for predicting the COV. The computational efficiency of the established DNN model was also at least two orders of magnitude faster than that of the CFD simulations for predicting the COV.

The Global Hydrogen Review is an annual publication by the International Energy Agency that tracks hydrogen production and demand worldwide as well as progress in critical areas such as infrastructure development trade policy regulation investments and innovation. The report is an output of the Clean Energy Ministerial Hydrogen Initiative and is intended to inform energy sector stakeholders on the status and future prospects of hydrogen while also informing discussions at the Hydrogen Energy Ministerial Meeting organised by Japan. Focusing on hydrogen’s potentially major role in meeting international energy and climate goals the Review aims to help decision makers fine-tune strategies to attract investment and facilitate deployment of hydrogen technologies at the same time as creating demand for hydrogen and hydrogen-based fuels. It compares real-world developments with the stated ambitions of government and industry. This year’s report includes a focus on demand creation for low-emission hydrogen. Global hydrogen use is increasing but demand remains so far concentrated in traditional uses in refining and the chemical industry and mostly met by hydrogen produced from unabated fossil fuels. To meet climate ambitions there is an urgent need to switch hydrogen use in existing applications to low-emission hydrogen and to expand use to new applications in heavy industry or long-distance transport.

Underground hydrogen storage in depleted hydrocarbon reservoirs and aquifers has been proposed as a potential long-term solution to storing intermittently produced renewable electricity as the subsurface formations provide secure and large storage space. Various phenomena can lead to hydrogen loss in subsurface systems with the key cause being the trapping especially during the withdrawal cycle. Capillary trapping in particular is strongly related to the hysteresis phenomena observed in the capillary pressure/saturation and relative-permeability/saturation curves. This paper address two key points: (1) the sole impact of hysteresis in capillary pressure on hydrogen trapping during withdrawal cycles and (2) the dependency of optimal operational parameters (injection/withdrawal flow rate) and the reservoir characteristics such as permeability thickness and wettability of the porous medium on the remaining hydrogen saturation.<br/>Model<br/>To study the capillary hysteresis during underground hydrogen storage Killough [1] model was implemented in the MRST toolbox [2]. A comparative study was performed to quantify the impact of changes in capillary pressure behaviour by including and excluding the hysteresis and scanning curves. Additionally this study investigates the impact of injection/withdrawal rates and the aquifer permeability for various capillary and Bond numbers in a homogeneous system.<br/>Findings<br/>It was found that although the hydrogen storage efficiency is not considerably impacted by the inclusion of the capillary-pressure scanning curves the impact of capillary pressure on the well properties (withdrawal rate and pressure) can become significant. Higher injection and withdrawal rates does not necessarily lead to a better performance in terms of productivity. The productivity enhancement depends on the competition between gravitational capillary and viscous forces. The observed water upconing at relatively high capillary numbers resulted in low hydrogen productivity. highlighting the importance of well design and placement.

There is a pressing need to rapidly and massively scale up negative carbon strategies such as carbon capture and storage (CCS). At the same time large-scale CCS can enable ramp-up of large-scale hydrogen production a key component of decarbonized energy systems. We argue here that the safest and most practical strategy for dramatically increasing CO2 storage in the subsurface is to focus on regions where there are multiple partially depleted oil and gas reservoirs. Many of these reservoirs have adequate storage capacity are geologically and hydrodynamically well understood and are less prone to injection-induced seismicity than saline aquifers. Once a CO2 storage facility is up and running it can be used to store CO2 from multiple sources. Integration of CCS with hydrogen production appears to be an economically viable strategy for dramatically reducing greenhouse gas emissions over the next decade particularly in oil- and gas-producing countries where there are numerous depleted reservoirs that are potentially suitable for large-scale carbon storage.

Proton exchange membrane fuel cells (PEMFCs) are attracting attention for their green energy-saving and high-efficiency advantages becoming one of the future development trends of renewable energy utilization. However there are still deficiencies in the gas supply system control strategy that plays a crucial role in PEMFCs which limits the rapid development and application of PEMFCs. This paper provides a comprehensive and in-depth review of the PEMFC air delivery system (ADS) and hydrogen delivery system (HDS) operations. For the ADS the advantages and disadvantages of the oxygen excess ratio (OER) oxygen pressure and their decoupling control strategies are systematically described by the following three aspects: single control hybrid control and intelligent algorithm control. Additionally the optimization strategies of the flow field or flow channel for oxygen supply speeds and distribution uniformity are compared and analyzed. For the HDS a systematic review of hydrogen recirculation control strategies purge strategies and hydrogen flow control strategies is conducted. These strategies contribute a lot to improving hydrogen utilization rates. Furthermore hydrogen supply pressure is summarized from the aspects of hybrid control and intelligent algorithm control. It is hoped to provide guidance or a reference for research on the HDS as well as the ADS control strategy and optimization strategy

Clean energy technological innovations are widely acknowledged as a prerequisite to achieving ambitious longterm energy and climate targets. However the optimal speed of their adoption has been parsimoniously studied in the literature. This study seeks to identify the optimal intensity of moving to a green hydrogen electricity sector in Greece using the OSeMOSYS energy modeling framework. Green hydrogen policies are evaluated first on the basis of their robustness against uncertainty and afterwards against conflicting performance criteria and for different decision-making profiles towards risk by applying the VIKOR and TOPSIS multi-criteria decision aid methods. Although our analysis focuses exclusively on the power sector and compares different rates of hydrogen penetration compared to a business-as-usual case without considering other game-changing innovations (such as other types of storage or carbon capture and storage) we find that a national transition to a green hydrogen economy can support Greece in potentially cutting at least 16 MtCO2 while stimulating investments of EUR 10–13 bn. over 2030–2050.