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1.
The cost of hydrogen in early fuel cell electric vehicle (FCEV) markets is dominated by the cost of refueling stations, mainly due to the high cost of refueling equipment, small station capacities, lack of economies of scale, and low utilization of the installed refueling capacity. Using the hydrogen delivery scenario analysis model (HDSAM), this study estimates the impacts of these factors on the refueling cost for different refueling technologies and configurations, and quantifies the potential reduction in future hydrogen refueling cost compared to today's cost in the United States. The current hydrogen refueling station levelized cost, for a 200 kg/day dispensing capacity, is in the range of $6–$8/kg H2 when supplied with gaseous hydrogen, and $8–$9/kg H2 for stations supplied with liquid hydrogen. After adding the cost of hydrogen production, packaging, and transportation to the station's levelized cost, the current cost of hydrogen at dispensers for FCEVs in California is in the range of $13–$15/kg H2. The refueling station capacity utilization strongly influences the hydrogen refueling cost. The underutilization of station capacity in early FCEV markets, such as in California, results in a levelized station cost that is approximately 40% higher than it would be in a scenario where the station had been fully utilized since it began operating. In future mature hydrogen FCEV markets, with a large demand for hydrogen, the refueling station's levelized cost can be reduced to $2/kg H2 as a result of improved capacity utilization and reduced equipment cost via learning and economies of scale.  相似文献   

2.
Long-distance road-freight transport emits a large share of Germany's greenhouse gas (GHG) emissions. A potential solution for reducing GHG emissions in this sector is to use green hydrogen in fuel cell electric vehicles (FC-HDV) and establish an accompanying hydrogen refueling station (HRS) network. In this paper, we apply an existing refueling network design model to a HDV-HRS network for Germany until 2050 based on German traffic data for heavy-duty trucks and estimate its costs. Comparing different fuel supply scenarios (pipeline vs. on-site), The on-site scenario results show a network consisting of 137 stations at a cost of 8.38 billion € per year in 2050 (0.40 € per vehicle km), while the centralized scenario with the same amount of stations shows a cheaper cost with 7.25 billion euros per year (0.35 € per vehicle km). The hydrogen cost (LCOH) varies from 5.59 €/kg (pipeline) to 6.47 €/kg (on-site) in 2050.  相似文献   

3.
In this study, different hydrogen refueling station (HRS) architectures are analyzed energetically as well as economically for 2015 and 2050. For the energetic evaluation, the model published in Bauer et al. [1] is used and norm-fitting fuelings according to SAE J2601 [2] are applied. This model is extended to include an economic evaluation. The compressor (gaseous hydrogen) resp. pump (liquid hydrogen) throughput and maximum pressures and volumes of the cascaded high-pressure storage system vessels are dimensioned in a way to minimize lifecycle costs, including depreciation, capital commitment and electricity costs. Various station capacity sizes are derived and energy consumption is calculated for different ambient temperatures and different station utilizations. Investment costs and costs per fueling mass are calculated based on different station utilizations and an ambient temperature of +12 °C. In case of gaseous trucked-in hydrogen, a comparison between 5 MPa and 20 MPa low-pressure storage is conducted. For all station configurations and sizes, a medium-voltage grid connection is applied if the power load exceeds a certain limit. For stations with on-site production, the electric power load of the hydrogen production device (electrolyzer or gas reformer) is taken into account in terms of power load. Costs and energy consumption attributed to the production device are not considered in this study due to comparability to other station concepts. Therefore, grid connection costs are allocated to the fueling station part excluding the production device. The operational strategy of the production device is also considered as energy consumption of the subsequent compressor or pump and the required low-pressure storage are affected by it. All station concepts, liquid truck-supplied hydrogen as well as stations with gaseous truck-supplied or on-site produced hydrogen show a considerable cost reduction potential. Long-term specific hydrogen costs of large stations (6 dispensers) are 0.63 €/kg – 0.76 €/kg (dependent on configuration) for stations with gaseous stored hydrogen and 0.18 €/kg for stations with liquid stored hydrogen. The study focuses only on the refueling station and does not allow a statement about the overall cost-effectiveness of different pathways.  相似文献   

4.
Nuclear assisted low carbon hydrogen production by water electrolysis represents a potential application of nuclear cogeneration towards deep decarbonization of several fossil fuel-dependent industrial sectors. This work builds a probabilistic techno-commercial model of a water electrolysis plant coupled to an existing nuclear reactor for base load operations. The objective is to perform discounted cash flow (DCF) calculations for levelized nuclear hydrogen production cost under input parameter uncertainty. The probability distributions of inputs are used with the Monte Carlo-Latin Hypercube (MC-LH) sampling technique to generate 105 input scenarios and corresponding distribution of the levelized or life cycle hydrogen production cost instead of deterministic point values. Based on current techno-economic conditions, the levelized production costs of electrolytic hydrogen using electricity from large water-cooled nuclear reactors are determined to be US $ 12.205 ± 1.342, 8.384 ± 1.148 and 6.385 ± 1.051/kg H2 respectively at rated alkaline water electrolyser capacities of 1.25 MW(e), 2.5 MW(e) and 5 MW(e). The corresponding values for PEM water electrolysers are US $ 13.162 ± 1.356, 8.891 ± 1.141 and 6.663 ± 1.057/kg H2. The potential for flexible nuclear reactor operation and management of power demand uncertainties through nuclear hydrogen cogeneration is also examined through a case study.  相似文献   

5.
Hydrogen refueling infrastructures with on-site production from renewable sources are an interesting solution for assuring green hydrogen with zero CO2 emissions. The main problem of these stations development is the hydrogen cost that depends on both the plant size (hydrogen production capacity) and on the renewable source.In this study, a techno-economic assessment of on-site hydrogen refueling stations (HRS), based on grid-connected PV plants integrated with electrolysis units, has been performed. Different plant configurations, in terms of hydrogen production capacity (50 kg/day, 100 kg/day, 200 kg/day) and the electricity mix (different sharing of electricity supply between the grid and the PV plant), have been analyzed in terms of electric energy demands and costs.The study has been performed by considering the Italian scenario in terms of economic streams (i.e. electricity prices) and solar irradiation conditions.The levelized cost of hydrogen (LCOH), that is the more important indicator among the economic evaluation indexes, has been calculated for all configurations by estimating the investment costs, the operational and maintenance costs and the replacement costs.Results highlighted that the investment costs increase proportionally as the electricity mix changes from Full Grid operation (100% Grid) to Low Grid supply (25% Grid) and as the hydrogen production capacity grows, because of the increasing in the sizes of the PV plant and the HRS units. The operational and maintenance costs are the main contributor to the LCOH due to the annual cost of the electricity purchased from the grid.The calculated LCOH values range from 9.29 €/kg (200 kg/day, 50% Grid) to 12.48 €/kg (50 kg/day, 100% Grid).  相似文献   

6.
This paper deals with the analysis of the economy of scale at on-site hydrogen refueling stations which produce hydrogen through steam methane reforming or water electrolysis, in order to identify the optimum energy mix as well as the total construction cost of hydrogen refueling stations in Korea. To assess the economy of scale at on-site hydrogen stations, the unit hydrogen costs at hydrogen stations with capacities of 30 Nm3/h, 100 Nm3/h, 300 Nm3/h, and 700 Nm3/h were estimated. Due to the relatively high price of natural gas compared to the cost of electricity in Korea, water electrolysis is more economical than steam methane reforming if the hydrogen production capacity is small. It seems to be the best strategy for Korea to construct small water electrolysis hydrogen stations with production capacities of 100 Nm3/h or less until 2020, and to construct steam methane reforming hydrogen stations with production capacities of 300 Nm3/h or more after 2025.  相似文献   

7.
Hydrogen refueling station (HRS) capacity and location depend on the users, which makes it difficult to select the most favorable option before potential users are actually identified. As in Croatia, at least for now, there are no hydrogen users, this study considers a wide range of HRS capacities and their different configurations. These include hydrogen production and charging station within one existing wind farm in Croatia or both nearby the users, the hydrogen production within the wind farm and the charging station nearby the users, while hydrogen is delivered to the station with a tube trailer, and configuration of hydrogen production within the wind farm with a mobile charging station in case of several users in different locations. Each HRS configuration is evaluated by the obtained levelized cost of hydrogen depending on the capital, and operation and maintenance costs within the HRS techno-economic analysis provided.  相似文献   

8.
The present paper analyzes an innovative energy system based on a hydrogen station, as the core of a smart energy production center, where the produced hydrogen is then used in different hydrogen technologies adopted and installed nearby the station. A case study analysis has been proposed and then investigated, with a station capacity of up to 360 kg of hydrogen daily generated, located close to a University Campus. A hydrogen mobility network has been included, composed of a fuel cell hydrogen fleet of 41 vehicles, 43 bicycles, and 28 fuel cell forklifts. The innovative proposed energy system needs to meet also a power and heat demand for a student housing 5400 m2 building of the University Campus. The performance of the system is presented and investigated, including technical and economic analyses, proposing a hydrogen refueling station as an innovative alternative fuel infrastructure, called Multi-modular Hydrogen Energy Station, marking its great potential in future energy scenarios.  相似文献   

9.
The controversial and highly emotional discussion about biofuels in recent years has shown that greenhouse gas2 (GHG) emissions can only be evaluated in an acceptable way by carrying out a full life cycle assessment (LCA) taking the overall life cycle including all necessary pre-chains into consideration. Against this background, the goal of this paper is it to analyse the overall life cycle of a hydrogen production and provision. A state of the art hydrogen refuelling station in Hamburg/Germany opened in February 2012 is therefore taken into consideration. Here at least 50% hydrogen from renewable sources of energy is produced on-site by water electrolysis based on surplus electricity from wind (mainly offshore wind parks) and water. The remaining other 50% of hydrogen to be sold by this station mainly to hydrogen-fuelled buses is provided by trucks from a large-scale production plant where hydrogen is produced from methane or glycerol as a by-product of the biodiesel production. These two pathways are compared within the following explanations with hydrogen production from biomass and from coal. The results show that – with the goal of reducing GHG emissions on a life cycle perspective – hydrogen production based on a water electrolysis fed by electricity from the German electricity mix should be avoided. Steam methane reforming is more promising in terms of GHG reduction but it is still based on a finite fossil fuel. For a climatic sound provision of hydrogen as a fuel electricity from renewable sources of energy like wind or biomass should be used.  相似文献   

10.
The performance of a novel hydrogen production and energy conversion system based on the aluminum-water reaction is addressed by means of a lumped and distributed parameter numerical approach. The interest on this type of technology arises because of the possibility of obtaining at the same time different secondary energy sources, such as hydrogen and heat and mechanical work, with very low pollutant and greenhouse gas emissions.In this paper the numerical models of the main components adopted in the system are developed, including the combustion chamber, the steam/hydrogen turbine and the heat exchangers. The behavior of the whole system is investigated for different configurations and energy conversion cycles, i.e. electric energy production only and combined heat and power production, in order to determine the operating maps in terms of efficiency, power output, pressure and temperature in the main sections, mass flow rates and the hydrogen yield. The numerical analysis of the thermo-dynamic behavior of the power unit is aimed at assessing the guidelines that will lead to the construction of a first prototype of this system.Finally, the use of a cogeneration system based on the aluminum combustion with water system for on-site small scale hydrogen production for feeding a hydrogen refueling station is explored. The proposed system is compared with other technologies as well as the case of large scale hydrogen production and delivery.  相似文献   

11.
Nowadays, the development of hydrogen economy in the transportation sector is hindered by the principal barriers arising from the lack of adequate infrastructure and the small fleet of hydrogen-based road vehicles.This study investigates the potential of small-scale autonomous hydrogen refuelling stations with onsite production via an alkaline electrolysis apparatus powered by a small wind turbine. In this context, an urban area with promising wind resources has been selected. Based on the wind conditions and an indicative hydrogen demand for refuelling light-duty fuel cell electric vehicles such as bicycles, the sizing of the wind turbine and the electrolyser has been theoretically calculated. For supporting the daily hydrogen refuelling demand of the fuel cell electric bicycles, which is estimated at approximately 6 kg, it is calculated that a 50 kW wind turbine should be installed in order to power a 70 kW alkaline electrolyser for producing hydrogen. The capital cost of the hydrogen station is calculated at €248,130, while the retail price of the produced hydrogen is estimated to be more than 50.2 €/kgH2 in order to achieve a positive internal rate of return.Ultimately, the present paper aims at delivering a feasibility study of a small-scale H2 refuelling station for fuel cell bicycles in order to provide investors with initiatives to implement such schemes in urban environments where problems of low air quality and high traffic are intense.  相似文献   

12.
In the mainframe of a research contract, a feasibility pre-design study of a hydrogen-fuelled Laboratory-Village has been carried out: the goals are the design and the simulation of a demonstration plant based on hydrogen as primary fuel. The hydrogen is produced by electrolysis, from electric power produced by a mix of hydroelectric and solar photovoltaic plants. The plant will be located in a small remote village in Valle d’Aosta (Italy). This country has large water availability from glaciers and mountains, so electricity production from fluent water hydroelectric plants is abundant and cheap. Therefore, the production of hydrogen during the night (instead of selling the electricity to the grid at very low prices) could become a good economic choice, and hydrogen could be a competitive local fuel in term of costs, if compared to oil or gas. The H2 will be produced and stored, and used to feed a hydrogen vehicle and for thermal purposes (heating requirement of three buildings), allowing a real field test (Village-Laboratory).  相似文献   

13.
The cost of large scale hydrogen production from electrolysis is dominated by the cost of electricity, representing 77–89% of the total costs. The integration of low-cost renewable energy is thus essential to affordable and clean hydrogen production from electrolysis. Flexible operation of electrolysis and hydro power can facilitate integration of remote energy resources by providing the flexibility that is needed in systems with large amounts of variable renewable energy. The flexibility from hydro power is limited by the physical complexities of the river systems and ecological concerns which makes the flexibility not easily quantifiable. In this work we investigate how different levels of flexibility from hydro power affects the cost of hydrogen production.We develop a two-stage stochastic model in a rolling horizon framework that enables us to consider the uncertainty in wind power production, energy storage and the structure of the energy market when simulating power system operation. This model is used for studying hydrogen production from electrolysis in a future scenario of a remote region in Norway with large wind power potential. A constant demand of hydrogen is assumed and flexibility in the electrolysis operation is enabled by hydrogen storage. Different levels of hydro power flexibility are considered by following a reservoir guiding curve every hour, 6 h or 24 h.Results from the case study show that hydrogen can be produced at a cost of 1.89 €/kg in the future if hydro power production is flexible within a period of 24 h, fulfilling industry targets. Flexible hydrogen production also contributes to significantly reducing wasted energy from spillage from reservoirs or wind power curtailment by up to 56% for 24 h of flexibility. The results also show that less hydro power flexibility results in increased flexible operation of the electrolysis plant where it delivers 39–46% more regulating power, operates more on higher power levels and stores more hydrogen.  相似文献   

14.
This study presents a techno-economic evaluation on hydrogen generation from a small-scale wind-powered electrolysis system in different power matching modes. For the analysis, wind speed data, which measured as hourly time series in Kirklareli, Turkey, were used to predict the electrical energy and hydrogen produced by the wind–hydrogen energy system and their variation according to the height of the wind turbine. The system considered in this study is primarily consisted of a 6 kW wind-energy conversion system and a 2 kW PEM electrolyzer. The calculation of energy production was made by means of the levelized cost method by considering two different systems that are the grid-independent system and the grid-integrated system. Annual production of electrical energy and hydrogen was calculated as 15,148.26 kWh/year and 102.37 kg/year, respectively. The highest hydrogen production is obtained in January. The analyses showed that both electrical energy and hydrogen production depend strongly on the hub height of wind turbine in addition to the economic indicators. In the grid-integrated system, the calculated levelized cost of hydrogen changes in the range of 0.3485–4.4849 US$/kg for 36 m hub height related to the specific turbine cost. The grid-integrated system can be considered as profitable when the excess electrical energy delivered by system sold to the grid.  相似文献   

15.
The uncertainty and cost of changing from a fossil-fuel-based society to a hydrogen-based society are considered to be extensive obstacles to the introduction of fuel cell vehicles (FCVs). The absence of existing profitable refueling stations has been shown to be one of the major barriers. This paper investigates methods for calculating an optimal transition from a gasoline refueling station to future methane and hydrogen combined use with an on site small-scale reformer for methane. In particular, we look into the problem of matching the hydrogen capacity of a single refueling station to an increasing demand. Based on an assumed future development scenario, optimal investment strategies are calculated. First, a constant utilization of the hydrogen reformer is assumed in order to find the minimum hydrogen production cost. Second, when considerations such as periodic maintenance are taken into account, optimal control is used to concurrently find both a short term equipment variable utilization for one week and a long term strategy. The result is a minimum hydrogen production cost of $4–6/kg, depending on the number of reinvestments during a 20 year period. The solution is shown to yield minimum hydrogen production cost for the individual refueling station, but the solution is sensitive to variations in the scenario parameters.  相似文献   

16.
In recent decades, the consequences of climate changes due to greenhouse gas (GHG) emissions have become ever more impactful, forcing international authorities to find green solutions for sustainable economic development. In this regard, one of the global targets is the reduction of fossil fuels utilization in the transport sector to encourage the diffusion of more environmentally friendly alternatives. Among them, hydrogen is emerging as a viable candidate since it is a potentially emission-free fuel when produced by exploiting renewable energy sources (RES). Nevertheless, to allow widespread use of this gas in the transport sector, several technoeconomic barriers, including production cost, and lack of distribution and storage infrastructure, have to be overcome. Distributed hydrogen production via renewable energy-powered electrolysis could be an effective solution to reduce cost and lead to economies of scale. In this study a multi-hub configuration with on-site production from PV-powered electrolysis and centralized production from steam methane reforming (SMR) is proposed. In particular, an infrastructure network for a bus refueling station located in Lazio is considered as a case study. First, each hub, composed of PV panels, an electrolyzer, a compression system, high-pressure and low-pressure storages, and hydrogen dispensers with chiller, is modeled in a Matlab/Simulink environment. Then, a design perturbation analysis is carried out to determine the impact of the configuration on the refueling station performance in terms of carbon emissions levels and the Levelized Cost of hydrogen (LCOH). The results show a significant influence of the station size on the economic performance highlighting significant benefits (reduction up to 40% in the LCOH) for a 80 bus HUB with a saturating trend towards larger sizes. CO2 emissions per unit mass of hydrogen are kept limited for all the stations thanks to the synergistic effects of SMR and Electrolyzer. Interconnecting more than one station each other further benefits can be achieved from the environmental perspective (savings up to 5 tons of CO2 are demonstrated for a typical summer case study).  相似文献   

17.
This paper presents the economic assessment of novel refueling stations, in which through advanced and high efficiency technologies, the polygeneration of more energy services like hydrogen, electricity and heat is carried out on-site.The architecture of these polygeneration plants is realized with a modular structure, organized in more sections.The primary energy source is ammonia that represents an interesting fuel for producing more energy streams. The ammonia feeds directly the SOFC that is able to co-generate simultaneously electricity and hydrogen by coupling a high efficiency energy system with hydrogen chemical storage.Two system configurations have been proposed considering different design concepts: in the first case (Concept_1) the plant is sized for producing 100 kg/day of hydrogen and the power section is sized also for self-sustaining the plant electric power consumption, while in the second one (Concept_2) the plant is sized for producing 100 kg/day of hydrogen and the power section is sized for self-sustaining the plant electric power consumption and for generating 50 kW for the DC fast charging.The economic analysis has been carried out in the current and target scenarios, by evaluating, the levelized cost of hydrogen (LCOH), the levelized cost of electricity (LCOE), the Profitability Index (PI), Internal rate of Return (IRR) and the Discounted Payback Period (DPP).Results have highlighted that the values of the LCOH, for the proposed configurations and economic scenarios, are in the range 6–10 €/kg and the values of the LCOE range from 0.447 €/kWh to 0.242 €/kWh.In terms of PI and IRR, the best performance is achieved in the Concept_1 for the current scenario (1.89 and 8.0%, respectively). On the contrary, in the target scenario, thanks to a drastic costs reduction the co-production of hydrogen and electricity as useful outputs, becomes the best choice from all economic indexes and parameters considered.  相似文献   

18.
In this work, a novel approach related to the production of hydrogen using a polymer electrolyte membrane electrolysis powered by a renewable hybrid system is proposed. The investigation is carried out by establishing energy balances in the different components constituting the combined renewable system. A mathematical model to predict the production of electricity and hydrogen is proposed. The discrepancies between the numerical results and those from the literature review do not exceed 7%. The results show that the overall efficiency and the capacity factor of the combined renewable system without thermal storage are 20 and 34%, respectively. The levelized cost of hydrogen also is 6.86 US$/kg. The effect of certain physical parameters such as optical efficiency, water electrolysis temperature, unit electrolysis capital cost and solar multiple on the performance of the combined system is investigated. The results show that the performance of hydrogen production is optimal when the solar installation is three times oversized. The results also show that the levelized cost of hydrogen for the optimal sized is 4.07 US$/kg. Finally, the proposed combined system can produce low cost hydrogen and compete with hybrid sulfur thermochemical cycles, conventional photovoltaic installations, concentrated photovoltaic thermal systems and wind farms developed in all regions of the world.  相似文献   

19.
Due to the threat of climate change, renewable feedstocks & alternative energy carriers are becoming more necessary than ever. One key vector is hydrogen, which can fulfil these roles and is a renewable resource when split from water using renewable electricity. Electrolyzers are often not designed for variable operation, such as power from sources like wind or solar. This work develops a framework to optimize the design and operation of a large-scale electrolyzer hub under variable power supply. The framework is a two-part optimization, where designs of repeated, modular units are optimized, then the entire system is optimized based on those modular units. The framework is tested using a case study of an electrolyzer hub powered by a Dutch wind farm to minimize the levelized cost of hydrogen. To understand how the optimal design changes, three power profiles are examined, including a steady power supply, a representative wind farm power supply, and the same wind farm power supply compressed in time. The work finds the compressed power profile uses PEM technology which can ramp up and down more quickly. The framework determines for this case study, pressurized alkaline electrolyzers with large stacks are the cheapest modular unit, and while a steady power profile resulted in the cheapest hydrogen, costing 4.73 €/kg, the typical wind power profile only raised the levelized cost by 2%–4.82 €/kg. This framework is useful for designing large-scale electrolysis plants and understanding the impact of specific design choices on the performance of a plant.  相似文献   

20.
We have examined the technical feasibility and economics of developing a hydrogen vehicle refueling infrastructure for a specific area where zero emission vehicles are being considered, Southern California. Potential hydrogen demands for zero emission vehicles are estimated. We then assess in detail several near term possibilities for producing and delivering gaseous hydrogen transportation fuel including: (1) hydrogen produced from natural gas in a large, centralized steam reforming plant, and truck delivered as a liquid to refueling stations; (2) hydrogen produced in a large, centralized steam reforming plant, and delivered via small scale hydrogen gas pipeline to refueling stations; (3) by-product hydrogen from chemical industry sources; (4) hydrogen produced at the refueling station via small scale steam reforming of natural gas; and (5) hydrogen produced via small scale electrolysis at the refueling station. The capital cost of infrastructure and the delivered cost of hydrogen are estimated for each hydrogen supply option. Hydrogen is compared to other fuels for fuel cell vehicles (methanol, gasoline) in terms of vehicle cost, infrastructure cost and lifecycle cost of transportation. Finally, we discuss possible scenarios for introducing hydrogen as a fuel for fuel cell vehicles.  相似文献   

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