Applications & Pathways

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.

In the global content regarding the impact on the environmental of the gases emissions resulted from the fossil fuels combustion aspect discussed on the 2015 Paris Climate Conference contribute to the necessity of searching of alternative energy from durable and renewable resources. The purpose of the paper is the use of hydrogen fuelling at truck diesel engine in order to improves engine efficiency and pollutant performance hydrogen being injected into the inlet manifold. Experimental results show better energetic and pollution performance of the dual fuelled engine due to the improvement of the combustion process and reduction of carbon content.

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.

The use of hydrogen fuel produced from renewable energy sources is an effective way to reduce well-to-wheel CO2 emissions from automobiles. In this study the performance of a hydrogen-powered series hybrid vehicle was compared with that of other powertrains such as gasoline-powered hybrid fuel cell and electric vehicles in a simulation that could estimate CO2 emissions under real-world driving conditions. The average fuel consumption of the hydrogenpowered series hybrid vehicle exceeded that of the gasoline-powered series hybrid vehicle under all conditions and was better than that of the fuel cell vehicle under urban and winding conditions with frequent acceleration and deceleration. The driving range was longer than that of the batterypowered vehicle but approximately 60% of that of the gasoline-powered series hybrid. Regarding the life-cycle assessment of CO2 emissions fuel cell and electric vehicles emitted more CO2 during the manufacturing process. Regarding fuel production CO2 emissions from hydrogen and electric vehicles depend on the energy source. However in the future this problem can be solved by using carbon-free energy sources for fuel production. Therefore hydrogen-powered series hybrid vehicles show a high potential to be environmentally friendly alternative fuel vehicles.

Insular networks constitute ideal fields for investment in renewables and storage due to their excellent wind and solar potential as well the high generation cost of thermal generators in such networks. Nevertheless in order to ensure the stability of insular networks network operators impose strict restrictions on the expansion of renewables. Storage systems render ideal solutions for overcoming the aforementioned restrictions unlocking additional renewable capacity. Among storage technologies hybrid battery-hydrogen demonstrates beneficial characteristics thanks to the complementary features that battery and hydrogen exhibit regarding efficiency self-discharge cost etc. This paper investigates the economic feasibility of a private investment in renewables and hybrid hydrogen-battery storage realized on the interconnected island of Crete Greece. Specifically an optimization formulation is proposed to optimize the capacity of renewables and hybrid batteryhydrogen storage in order to maximize the profit of investment while simultaneously reaching a minimum renewable penetration of 80% in accordance with Greek decarbonization goals. The numerical results presented in this study demonstrate that hybrid hydrogen-battery storage can significantly reduce electricity production costs in Crete potentially reaching as low as 64 EUR/MWh. From an investor’s perspective even with moderate compensation tariffs the energy transition remains profitable due to Crete’s abundant wind and solar resources. For instance with a 40% subsidy and an 80 EUR/MWh compensation tariff the net present value can reach EUR 400 million. Furthermore the projected cost reductions for electrolyzers and fuel cells by 2030 are expected to enhance the profitability of hybrid renewable-battery-hydrogen projects. In summary this research underscores the sustainable and economically favorable prospects of hybrid hydrogen-battery storage systems in facilitating Crete’s energy transition with promising implications for investors and the wider renewable energy sector.

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 paper presents a wind-methanol-fuel cell system with hydrogen storage. It can manage various energy flow to provide stable wind power supply produce constant methanol and reduce CO2 emissions. Firstly this study establishes the theoretical basis and formulation algorithms. And then computational experiments are developed with MATLAB/Simulink (R2016a MathWorks Natick MA USA). Real data are used to fit the developed models in the study. From the test results the developed system can generate maximum electricity whilst maintaining a stable production of methanol with the aid of a hybrid energy storage system (HESS). A sophisticated control scheme is also developed to coordinate these actions to achieve satisfactory system performance.

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.

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

Hydrogen (H2) has rapidly become a topic of great attention when discussing routes to net-zero carbon emissions. About 14% of CO2 emissions globally are directly associated with domestic heating in buildings. Replacing natural gas (NG) with H2 for heating has been highlighted as a rapid alternative for mitigating these emissions. To realise this not only the production challenges but also potential obstacles in the transmission/distribution and combustion of H2 must be technically identified and discussed. This review in addition to delineating the challenges of H2 in NG grid pipelines and H2 combustion also collates the results of the state-of-the-art technologies in H2-based heating systems. We conclude that the sustainability of water and renewable electricity resources strongly depends on sizing siting service life of electrolysis plants and post-electrolysis water disposal plans. 100% H2 in pipelines requires major infrastructure upgrades including production transmission pressurereduction stations distribution and boiler rooms. H2 leakage instigates more environmental risks than economic ones. With optimised boilers burning H2 could reduce GHG emissions and obtain an appropriate heating efficiency; more data from boiler manufacturers must be provided. Overall green H2 is not the only solution to decarbonise heating in buildings and it should be pursued abreast of other heating technologies.

The oil refinery industry is one of the major energy users and responsible for a large proportion of greenhouse gas (GHG) emissions. This sector is facing multiple sustainability-related transformation pressures forcing the industry to adapt to changing market conditions. The transition to a low-carbon economy will require oil refineries to adopt decarbonisation technologies like advanced biofuels green hydrogen and carbon capture and storage (CCS). However the development and implementation of these technologies is not a straightforward process and may be inhibited by lock-in and path dependency. This paper draws on expert interviews and combines the Technological Innovation Systems (TIS) and Multi-level Perspective (MLP) frameworks to examining the niche level development of three emerging technologies in the context of deep decarbonisation of refinery. This research finds that the development of the three decarbonisation technologies shares some of the challenges and opportunities and exhibits technology interdependency to some extent. Among the three TISs advanced biofuel is the most mature in terms of knowledge base actor-network legislation framework and market function. Green hydrogen and CCS encounter stronger momentum than before and can benefit from possible synergies across various sectors. However the analysis also reveals the lack of market formation mainly due to the lack of policy instruments for niche markets. Here policy recommendations for accelerating deep decarbonisation of the oil refinery industry are discussed. Finally we contribute to the sustainability transitions literature by exploring the dynamics of emerging TISs for industrial decarbonisation.

Renewable energy technologies and resources particularly solar photovoltaic systems provide cost-effective and environmentally friendly solutions for meeting the demand for electricity. The design of such systems is a critical task as it has a significant impact on the overall cost of the system. In this paper a mixed-integer linear programming-based model is proposed for designing an integrated photovoltaic-hydrogen renewable energy system to minimize total life costs for one of Saudi Arabia’s most important fields a greenhouse farm. The aim of the proposed system is to determine the number of photovoltaic (PV) modules the amount of hydrogen accumulated over time and the number of hydrogen tanks. In addition binary decision variables are used to describe either-or decisions on hydrogen tank charging and discharging. To solve the developed model an exact approach embedded in the general algebraic modeling System (GAMS) software was utilized. The model was validated using a farm consisting of 20 greenhouses a worker-housing area and a water desalination station with hourly energy demand. The findings revealed that 1094 PV panels and 1554 hydrogen storage tanks are required to meet the farm’s load demand. In addition the results indicated that the annual energy cost is $228234 with a levelized cost of energy (LCOE) of 0.12 $/kWh. On the other hand the proposed model reduced the carbon dioxide emissions to 882 tons per year. These findings demonstrated the viability of integrating an electrolyzer fuel cell and hydrogen tank storage with a renewable energy system; nevertheless the cost of energy produced remains high due to the high capital cost. Moreover the findings indicated that hydrogen technology can be used as an energy storage solution when the production of renewable energy systems is variable as well as in other applications such as the industrial residential and transportation sectors. Furthermore the results revealed the feasibility of employing renewable energy as a source of energy for agricultural operations.

This paper proposes an energy management strategy for a fuel cell (FC) hybrid power system based on dynamic programming and state machine strategy which takes into account the durability of the FC and the hydrogen consumption of the system. The strategy first uses the principle of dynamic programming to solve the optimal power distribution between the FC and supercapacitor (SC) and then uses the optimization results of dynamic programming to update the threshold values in each state of the finite state machine to realize real-time management of the output power of the FC and SC. An FC/SC hybrid tramway simulation platform is established based on RTLAB real-time simulator. The compared results verify that the proposed EMS can improve the durability of the FC increase its working time in the high-efficiency range effectively reduce the hydrogen consumption and keep the state of charge in an ideal range.

The maritime industry is a major source of greenhouse gas (GHG) emissions largely due to ships running on fossil fuels. Transitioning to hydrogen-powered marine transportation in the Mediterranean Sea requires the development of a network of hydrogen refueling stations across the region to ensure a steady supply of green hydrogen. This paper explores the technoeconomic viability of harnessing wave energy from the Mediterranean Sea to produce green hydrogen for hydrogenpowered ships. Four promising island locations—near Sardegna Galite Western Crete and Eastern Crete—were selected based on their favorable wave potential for green hydrogen production. A thorough analysis of the costs associated with wave power facilities and hydrogen production was conducted to accurately model economic viability. The techno-economic results suggest that with anticipated cost reductions in wave energy converters the levelized cost of hydrogen could decrease to as low as 3.6 €/kg 4.3 €/kg 5.5 €/kg and 3.9 €/kg for Sardegna Galite Western Crete and Eastern Crete respectively. Furthermore the study estimates that in order for the hydrogen-fueled ships to compete effectively with their oil-fueled counterparts the levelized cost of hydrogen must drop below 3.5 €/kg. Thus despite the competitive costs further measures are necessary to make hydrogen-fueled ships a viable alternative to conventional diesel-fueled ships.

Hydrogen refueling stations (HRS) can cause a significant fraction of the hydrogen refueling cost. The main cost contributor is the currently used mechanical compressor. Electrochemical hydrogen compression (EHC) has recently been proposed as an alternative. However its optimal integration in an HRS has yet to be investigated. In this study we compare the performance of a gaseous HRS equipped with different compressors. First we develop dynamic models of three process configurations which differ in the compressor technology: mechanical vs. electrochemical vs. combined. Then the design and operation of the compressors are optimized by solving multi-stage dynamic optimization problems. The optimization results show that the three configurations lead to comparable hydrogen dispensing costs because the electrochemical configuration exhibits lower capital cost but higher energy demand and thus operating cost than the mechanical configuration. The combined configuration is a trade-off with intermediate capital and operating cost.

Hydrogen-based Power Systems (H2PSs) are gaining accelerating momentum globally to reduce energy costs and dependency on fossil fuels. A H2PS typically comprises three main parts: hydrogen production storage and power generation called packages. A review of the literature and Original Equipment Manufacturers (OEM) datasheets reveals that no single manufacturer supplies all H2PS components posing significant challenges in system design parts integration and safety assurance. Additionally both the literature and H2PS projects’ database highlight a gap in a systematic hydrogen equipment and auxiliary sub-systems technology selection process and how this selection affects the overall H2PS Balance of Plant (BoP). This study addresses that gap by providing a guideline for available technology options and their impact on the H2PS-BoP. The analysis compares packages and auxiliary sub-system technologies to support informed engineering decisions regarding technology and equipment selection. The study finds that each package’s technology influences the selection criteria of the other packages and the associated BoP requirements. Furthermore the choice of technologies across packages significantly affects overall system integrity and BoP. These interdependencies are illustrated using a cause-and-effect matrix. The study’s significance lies in establishing a structured guideline for engineering design and operations enhancing the accuracy of feasibility studies and accelerating the global implementation of H2PS.

Sustainable aviation fuels (SAFs) represent the short-term solution to reduce fossil carbon emissions from aviation. The Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA) was globally adopted to foster and make SAFs production economically competitive. Fischer-Tropsch synthetic paraffinic kerosene (FTSPK) produced from forest residue is a promising CORSIA-eligible fuel. FT conversion pathway permits the integration of carbon capture and storage (CCS) technology which provides additional carbon offsetting ca pacities. The FT-SPK with CCS process was modelled to conduct a comprehensive analysis of the conversion pathway. Life-cycle assessment (LCA) with a well-to-wake approach was performed to quantify the SAF’s carbon footprint considering both biogenic and fossil carbon dynamics. Results showed that 0.09 kg FT-SPK per kg of dry biomass could be produced together with other hydrocarbon products. Well-to-wake fossil emissions scored 21.6 gCO2e per MJ of FT-SPK utilised. When considering fossil and biogenic carbon dynamics a negative carbon flux (-20.0 gCO2eMJ− 1 ) from the atmosphere to permanent storage was generated. However FT-SPK is limited to a 50 %mass blend with conventional Jet A/A1 fuel. Using the certified blend reduced Jet A/A1 fossil emissions in a 37 % and the net carbon flux resulted positive (30.9 gCO2eMJ− 1 ). Sensitivity to variations in process as sumptions was investigated. The lifecycle fossil-emissions reported in this study resulted 49 % higher than the CORSIA default value for FT-SPK. In a UK framework only 0.7 % of aviation fuel demand could be covered using national resources but the emission reduction goal in aviation targeted for 2037 could be satisfied when considering CCS.

Hydrogen is gaining traction as a key energy carrier due to its clean combustion high energy content and versatility. As the world shifts towards sustainable energy hydrogen demand is rapidly increasing. This paper introduces a novel hybrid time series modeling approach designed and developed to accurately predict hydrogen demand by mixing linear and nonlinear models and accounting for the impact of non-recurring events and dynamic energy market changes over time. The model incorporates key economic variables like hydrogen price oil price natural gas price and gross domestic product (GDP) per capita. To address these challenges we propose a four-part framework comprising the Hodrick–Prescott (HP) filter the autoregressive fractionally integrated moving average (ARFIMA) model the enhanced empirical wavelet transform (EEWT) and high-order fuzzy cognitive maps (HFCM). The HP filter extracts recurring structural patterns around specific data points and resolves challenges in hybridizing linear and nonlinear models. The ARFIMA model equipped with statistical memory captures linear trends in the data. Meanwhile the EEWT handles non-stationary time series by adaptively decomposing data. HFCM integrates the outputs from these components with ridge regression fine-tuning the HFCM to handle complex time series dynamics. Validation using stochastic non-Gaussian synthetic data demonstrates that this model significantly enhances prediction performance. The methodology offers notable improvements in prediction accuracy and stability compared to existing models with implications for optimizing hydrogen production and storage systems. The proposed approach is also a valuable tool for policy formulation in renewable energy and smart energy transitions offering a robust solution for forecasting hydrogen demand

Cement industry due to the decomposition of CaCO3 and the production of clinker emits large amounts of CO2 into the atmosphere. This anthropogenic gas can be captured and through its synthesis with green hydrogen methanol and finally synthetic fuels are achieved. By using e-fuel Europe’s climate neutrality objectives could be achieved. However the energy transition still lacks a clear roadmap and decisions are strongly affected by the geopolitical situation the energy demand and the economy. Therefore different scenarios are analysed to assess the influence of key factors on the overall economic viability of the process: 1) A business-as-usual scenario EU perspectives 2) allowing e-fuels and 3) improving H2 production processes. The technical feasibility of the production of synthetic fuels is verified. The most optimistic projections indicate future production costs of synthetic fuels will be lower than those of fossil fuels. This is directly related to the cost of green hydrogen production.

The present study investigates the design and scale-up of a pure hydrogen oxy-fuel combustion burner for industrial applications. In recent years this technology has garnered attention as an effective approach to the decarbonisation of high-temperature industrial processes. Replacing air with oxygen in combustion processes significantly reduces nitrogen oxides emissions and leads to sustainable energy use. A laboratory-scale burner was designed with inlet nozzle dimensions adapted to the specific properties of hydrogen and oxygen as fuel and oxidant respectively. Implementing oxy-fuel combustion requires addressing several technical issues to prevent the burner wall from overheating and to ensure a stable flame. An infrared camera was used to characterise the performance and operating conditions of the laboratory-scale burner in the range of 2.5–30 kW. The 10 kW baseline case was analysed numerically and validated experimentally using thermocouples. This revealed stable lifted flames with maximum temperatures of 2800 K and a flame length of 0.15 m. A key challenge in engineering is transferring results from laboratory-scale to large-scale industrial applications. Once validated the prototype design was scaled up numerically from 10 kW to 1 MW investigating the feasibility of different scaling criteria. The impact of these criteria on flame characteristics mixing patterns and the volumetric distribution of the reaction zone was then assessed. The constant velocity criterion yielded the lowest pressure drops although it also resulted in longer flame lengths. In contrast the constant residence time criterion generated the highest pressure drops. The increased velocities associated with this criterion enhanced mixing leading to shorter flame lengths as noted in the cases of 200 kW decreasing from 0.98 m under constant velocity criterion to 0.46 m. The intermediate criteria demonstrated a feasible alternative for scaling up the burner by effectively balancing flame length mixing rate and pressure losses. Nevertheless all criteria enabled the burner to sustain high combustion efficiency. Overall this investigation provides valuable insight into the potential of hydrogen oxy-fuel combustion technology to reduce carbon emissions in high-temperature processes.

Hydrogen is a promising energy carrier for decarbonizing maritime and stationary applications. However using 100% hydrogen in large-bore engines introduces combustion challenges such as pre-ignition and backfire. These statistically occurring combustion anomalies particularly their spatial and temporal behavior cannot be fully understood through thermodynamic data alone. This study applies optical diagnostics to a medium-speed single-cylinder research engine (bore: 350 mm stroke: 440 mm displacement: 42.3 dm3 ) operated with 100% hydrogen exceeding 20 bar IMEP. By varying the air–fuel equivalence ratio between 2.3 and 4.0 and comparing active pre-chamber and open combustion chamber ignition systems backfire-induced operating limits are identified. High-speed flame imaging through two endoscopic accesses and up to three cameras captures both visible and UV (308 nm) flame chemiluminescence. An implemented visual vibration compensation method using fiber optics enables tracking of flame origins and propagation. The recordings show that 65% of ignition events initiate near one intake valve suggesting local hydrogen enrichment confirmed via 3D-CFD simulations. This is linked to intake manifold geometry which leads to mixture inhomogeneity up to −260◦ CA BTDC. At loads above 15 bar IMEP the localized enrichment reduces or shifts attributed to increased turbulence and intake mass flow. CFD simulations also reveal that gas temperatures under the intake valves exceeding the ignition temperature of hydrogen as early as 300◦ CA BTDC create the risk of backfire in the early gas phase. Additionally glowing oil droplets and ignition zones near the piston were observed indicating that lube oil ignition may be a cause of later (after −290◦ CA BTDC) backfire events. These findings contribute to the understanding of hydrogen combustion anomalies and support future experimental and modeling-based optimization of large-bore hydrogen engines.

To address the challenges in wind power fluctuation smoothing using electrochemical-hydrogen hybrid energy storage a SOC self-recovery-based capacity optimization is proposed. The key issues include extreme high/low SOC states of electrochemical storage due to large charge-discharge disparities and the degradation of hydrogen storage tank SOH caused by its efficiency characteristics which lead to high configuration costs. First considering grid-connection lag time and algorithm adaptability an adaptive weighted filter is designed to suppress wind power fluctuations to obtain precise active power reference values for hybrid energy storage. The active power is then allocated between electrochemical and hydrogen storage using EMD and HT. Subsequently a complementary operation strategy for electrochemical-hydrogen systems is proposed which incorporates equivalent SOC metrics to assess the overall SOC level of electrochemical storage. By defining trigger thresholds for different operational modes abnormal SOC and SOH states are eliminated. Finally a full lifecycle economic cost assessment model based on the rainflow counting method is established to evaluate the impact of different threshold settings on the operational lifespan of energy storage and the overall configuration cost. The proposed method is validated through real-data simulations demonstrating its effectiveness in optimizing hybrid storage configurations and reducing costs compared to conventional strategies.

Multi-energy systems (MESs) can address issues such as low renewable energy utilization and power imbalances by optimizing the integration of various energy sources. This paper proposes an optimization operation strategy for MES to regulate the hydrogen and battery storage system (HBRS) based on carbon emission factors (CEFs). Insufficient renewable energy utilization caused by reverse peak regulation can be addressed by guiding the optimal output of HBRS through this model thereby achieving multi-energy complementarity. The CEF is used to balance the output of the HBRS to achieve a low-carbon economic operating system. First the fluctuation of renewable energy is decomposed and reconstructed. Subsequently The HBRS system is utilized to smooth out the fluctuations caused by different frequencies of new energy and then the CEF is used to promote the output of the low-carbon subsystem. Finally comparative verification is conducted across validation cases to demonstrate the effectiveness of the proposed model and the optimization strategy.