A geospatial method for estimating the levelised cost of hydrogen production from offshore wind

This paper describes the development of a general-purpose geospatial model for assessing the economic viability of hydrogen production from offshore wind power. A key feature of the model is that it uses the offshore project's location characteristics (distance to port, water depth, distance to gas grid injection point). Learning rates are used to predict the cost of the wind farm's components and electrolyser stack replacement. The notional wind farm used in the paper has a capacity of 510 MW. The model is implemented in a geographic information system which is used to create maps of levelised cost of hydrogen from offshore wind in Irish waters. LCOH values in 2030 spatially vary by over 50% depending on location. The geographically distributed LCOH results are summarised in a multivariate production function which is a simple and rapid tool for generating preliminary LCOH estimates based on simple site input variables.     

Development of a viability assessment model for hydrogen production from dedicated offshore wind farms

Dedicated offshore wind farms for hydrogen production are a promising option to unlock the full potential of offshore wind energy, attain decarbonisation and energy security targets in electricity and other sectors, and cope with grid expansion constraints. Current knowledge on these systems is limited, particularly the economic aspects. Therefore, a new, integrated and analytical model for viability assessment of hydrogen production from dedicated offshore wind farms is developed in this paper. This includes the formulae for calculating wind power output, electrolysis plant size, and hydrogen production from time-varying wind speed. All the costs are projected to a specified time using both Discounted Payback (DPB) and Net Present Value (NPV) to consider the value of capital over time. A case study considers a hypothetical wind farm of 101.3 MW situated in a potential offshore wind development pipeline off the East Coast of Ireland. All the costs of the wind farm and the electrolysis plant are for 2030, based on reference costs in the literature. Proton exchange membrane electrolysers and underground storage of hydrogen are used. The analysis shows that the DPB and NPV flows for several scenarios of storage are in good agreement and that the viability model performs well. The offshore wind farm – hydrogen production system is found to be profitable in 2030 at a hydrogen price of €5/kg and underground storage capacities ranging from 2 days to 45 days of hydrogen production. The model is helpful for rapid assessment or optimisation of both economics and feasibility of dedicated offshore wind farm – hydrogen production systems.     

Cost of a potential hydrogen-refueling network for heavy-duty vehicles with long-haul application in Germany 2050

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.     

Analyzing the levelized cost of hydrogen in refueling stations with on-site hydrogen production via water electrolysis in the Italian scenario

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).     

Techno-economic feasibility of fleets of far offshore hydrogen-producing wind energy converters

Innovative solutions need to be developed for harvesting wind energy far offshore. They necessarily involve on-board energy storage because grid-connection would be prohibitively expensive. Hydrogen is one of the most promising solutions. However, it is well-known that it is challenging to store and transport hydrogen which may have a critical impact on the delivered hydrogen cost.In this paper, it is shown that there are vast areas far offshore where wind power is both characterized by high winds and limited seasonal variations. Capturing a fraction of this energy could provide enough energy to cover the forecast global energy demand for 2050. Thus, scenarios are proposed for the exploitation of this resource by fleets of hydrogen-producing wind energy converters sailing autonomously. The scenarios include transportation and distribution of the produced hydrogen.The delivered hydrogen cost is estimated for the various scenarios in the short term and in the longer term. Cost estimates are derived using technical and economic data available in the literature and assumptions for the cost of electricity available on-board the wind energy converters. In the shorter term, delivered cost estimates are in the range 7.1–9.4 €/kg depending on the scenario and the delivery distance. They are based on the assumption of on-board electricity cost at 0.08€/kWh. In the longer term, assuming an on-board electricity cost at 0.04€.kWh, the cost estimates could reduce to 3.5 to 5.7 €/kg which would make the hydrogen competitive on several hydrogen markets without any support mechanism. For the hydrogen to be competitive on all hydrogen markets including the ones with the highest GHG emissions, a carbon tax of approximately 200 €/kg would be required.     

Decarbonising city bus networks in Ireland with renewable hydrogen

This paper presents techno-economic modelling results of a nationwide hydrogen fuel supply chain (HFSC) that includes renewable hydrogen production, transportation, and dispensing systems for fuel cell electric buses (FCEBs) in Ireland. Hydrogen is generated by electrolysers located at each existing Irish wind farm using curtailed or available wind electricity. Additional electricity is supplied by on-site photovoltaic (PV) arrays and stored using lithium-ion batteries. At each wind farm, sizing of the electrolyser, PV array and battery is optimised system design to obtain the minimum levelised cost of hydrogen (LCOH). Results show the average electrolyser capacity factor is 64% after the integration of wind farm-based electrolysers with PV arrays and batteries. A location-allocation algorithm in a geographic information system (GIS) environment optimises the distributed hydrogen supply chain from each wind farm to a hypothetical hydrogen refuelling station in the nearest city. Results show that hydrogen produced, transported, and dispensed using this system can meet the entire current bus fuel demand for all the studied cities, at a potential LCOH of 5–10 €/kg by using available wind electricity. At this LCOH, the future operational cost of FCEBs in Belfast, Cork and Dublin can be competitive with public buses fuelled by diesel, especially under carbon taxes more reflective of the environmental impact of fossil fuels.     

Simulating offshore hydrogen production via PEM electrolysis using real power production data from a 2.3 MW floating offshore wind turbine

This work presents simulation results from a system where offshore wind power is used to produce hydrogen via electrolysis. Real-world data from a 2.3 MW floating offshore wind turbine and electricity price data from Nord Pool were used as input to a novel electrolyzer model. Data from five 31-day periods were combined with six system designs, and hydrogen production, system efficiency, and production cost were estimated. A comparison of the overall system performance shows that the hydrogen production and cost can vary by up to a factor of three between the cases. This illustrates the uncertainty related to the hydrogen production and profitability of these systems. The highest hydrogen production achieved in a 31-day period was 17 242 kg using a 1.852 MW electrolyzer (i.e., utilization factor of approximately 68%), the lowest hydrogen production cost was 4.53 $/kg H₂, and the system efficiency was in the range 56.1–56.9% in all cases.     

Low-carbon hydrogen production via electron beam plasma methane pyrolysis: Techno-economic analysis and carbon footprint assessment

Electron beam plasma methane pyrolysis is a hydrogen production pathway from natural gas without direct CO₂ emissions. In this work, two concepts for a technical implementation of the electron beam plasma pyrolysis in a large-scale hydrogen production plant are presented and evaluated in regards of efficiency, economics and carbon footprint. The potential of this technology is identified by an assessment of the results with the benchmark technologies steam methane reforming, steam methane reforming with carbon capture and storage as well as water electrolysis. The techno-economic analysis shows levelized costs of hydrogen for the plasma pyrolysis between 2.55 €/kg H₂ and 5.00 €/kg H₂ under the current economic framework. Projections for future price developments reveal a significant reduction potential for the hydrogen production costs, which support the profitability of plasma pyrolysis under certain scenarios. In particular, water electrolysis as direct competitor with renewable electricity as energy supply shows a considerably higher specific energy consumption leading to economic advantages of plasma pyrolysis for cost-intensive energy sources and a high degree of utilization. Finally, the carbon footprint assessment indicates the high potential for a reduction of life cycle emissions by electron beam plasma methane pyrolysis (1.9 kg CO₂ eq./kg H₂ – 6.4 kg CO₂ eq./kg H₂, depending on the electricity source) compared to state-of-the-art hydrogen production technology (10.8 kg CO₂ eq./kg H₂).     

Value of green hydrogen when curtailed to provide grid balancing services

This paper evaluates the potential of grid services in France, Italy, Norway and Spain to provide an alternative income for electrolysers producing hydrogen from wind power. Grid services are simulated with each country's data for 2017 for energy prices, grid services and wind power profiles from relevant wind parks. A novel metric is presented, the value of curtailed hydrogen, which is independent from several highly uncertain parameters such as electrolyser cost or hydrogen market price. Results indicate that grid services can monetise the unused spare capacity of electrolyser plants, improving their economy in the critical deployment phase. For most countries, up-regulation yields a value of curtailed hydrogen above 6 €/kg, over 3 times higher than the EU's 2030 price target (without incentives). However, countries with large hydro power resources such as Norway yield far lower results, below 2 €/kg. The value of curtailed hydrogen also decreases with hydrogen production, corresponding to the cases of symmetric and down-regulation.     

Techno-economic calculation of green hydrogen production and export from Colombia

In the present paper a techno-economic hydrogen production and transportation costs to export from Colombia to Europe and Asia were determined using the open-source Python tools, such as WindPowerLIB, PVLIB, ERA5 weather data, and the Hydrogen-2-Central (H2C) model. Calculations were performed as well for Chile, for comparison as a regional competitor. In addition, a detailed overview of Colombia's energy system and national efforts for a market ramp-up of renewable energy and hydrogen is provided. The application of the model in different scenarios shows Colombia's potential to produce green hydrogen using renewable energies. The prices estimated are 1.5 and 1.02 USD/kgH₂ for 2030 and 2050 with wind power, and 3.24 and 1.65 USD/kgH₂ for 2030 and 2050 using solar energy. Colombia can become one of the most promising hydrogen suppliers to Asian and European countries with one of the lowest prices in the production and transportation of green hydrogen.     

Techno-economics of novel refueling stations based on ammonia-to-hydrogen route and SOFC technology

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.     

A novel hybrid energy system for hydrogen production and storage in a depleted oil reservoir

Renewable and carbon free energy relates to the sustainable development of human beings while hydrogen production by renewables and hydrogen underground storage ensure the stable and economic renewable energy supply. A hybrid energy system combining hydrogen production by offshore wind power with hydrogen storage in depleted oil reservoirs was constructed along with a mathematical model where the Weibull distribution, Wind turbine power function, Faraday's law, continuity equation, Darcy's law, state equation of real gas, Net Present Value (NPV) and the concept of leveling were adopted to clarify the system characteristics. For the case of a depleted oil field in the Bohai Bay, China, the annual hydrogen production, annual levelized cost of hydrogen and payback period are 2.62 × 10⁶ m³, CNY 34.6/kgH₂ and 7 years, respectively. Sensitivity analysis found that the wind speed impacted significantly on system NPV and LCOH, followed by hydrogen price and stratum pressure.     

Assessment of offshore liquid hydrogen production from wind power for ship refueling

Green hydrogen from electrolysis has become the most attractive energy carrier for making the transition from fossil fuels to carbon-free energy sources possible. Especially in the naval sector, hydrogen has the potential to address environmental targets due to the lack of low-carbon fuel options. This study aims at investigating an offshore liquefied green hydrogen production plant for ship refueling. The plant comprises a wind farm for renewable electricity generation, an electrolyzer stack for hydrogen production, a water treatment unit for demineralized water production, and a hydrogen liquefaction plant for hydrogen storage and distribution to ships. A pre-feasibility study is addressed to find the optimal capacities of the plant that minimize the payback time. The model results show that the electrolyzer capacity shall be set equal to a value between 80% and 90% of the wind farm capacity to achieve the minimum payback times. Additionally, the wind farm capacity shall be higher than about 150 MW to limit the payback time to values lower than 11 years for a fixed hydrogen price of 6 €/kg. The Levelized Cost of Hydrogen results to be below 4 €/kg for a wide range of plant capacities for a lifetime of the plant of 25 years. Thus, the model shows that this plant is economically feasible and can be reproduced similarly for different locations by rescaling the different selected technologies. In this way, the naval sector can be decarbonized thanks to a new infrastructure for the production and refueling of liquified green hydrogen directly provided on the sea.     

Techno-economic assessment of renewable hydrogen production and the influence of grid participation

Large-scale hydrogen production facilities will be required to supply the chemical energy demand of certain industries in the future. The case for such production plants based on individual adapted PV and wind farms has been addressed in several studies. However, most studies focus on an island solution of the evaluated plant and therefore, do not allow grid assistance which significantly reduce the installed capacity of the corresponding units. To address this issue, we developed a tool with a linear programming approach to evaluate any location around the world for its renewable hydrogen production costs and the influence on the plant layout depending on its interaction with the grid. A detailed techno-economic evaluation has been performed for five locations where hydrogen production costs in the range of 4–6 €₂₀₂₀/kg have been retrieved. Furthermore, it is shown that with perspective cost data the costs can further be reduced to 2.50 €₂₀₂₀/kg.     

Techno-economic analysis of e-waste based chemical looping reformer as hydrogen generator with co-generation of metals,electricity and syngas

Chemical looping reforming (CLR) is an efficient technology to convert hydrocarbon fuels into CO₂ and H₂ using metal oxide based oxygen carriers. The novelty of the present study is to utilize electronic waste such as printed circuit board (PCB) to generate high quality syngas and metallic components for the CLR process. A portion of the syngas generated during e-waste pyrolysis is used with coal and polypropylene for effective combustion. A techno-economic analysis is performed for the production of hydrogen and electricity in the CLR method. The levelized costs for electricity (LCOE), hydrogen (LCOH), syngas (LCOS), and metal (LCOM) production using e-wastes are estimated as 92.28 $/MWh, 3.67 $/kg, 0.0034 $/kWh, and 24.32 $/ton, respectively. The LCOH is found to be the least of 2.90 $/kg under the co-feed conditions of PCB syngas-PP. The integration of the e-waste based CLR with a steam turbine system achieved a net efficiency of 50%.     

A Techno-Economic Analysis of solar hydrogen production by electrolysis in the north of Chile and the case of exportation from Atacama Desert to Japan

H₂ production from solar electricity in the region of the Atacama Desert – Chile – has been identified as strategical for global hydrogen exportation. In this study the full supply chain of solar hydrogen has been investigated for 2018 and projected to scenarios for 2025-2030. Multi-year hourly electrical profiles data have been used from real operating PV plants and simulated Concentrated Solar Power “CSP” plants with Thermal Energy Storage “TES” as well as commercial electricity Power Purchase Agreement “PPA” prices reported in the Chilean electricity market were considered. The Levelized Cost of Hydrogen “LCOH” of each production pathway is calculated by a case-sensitive techno-economic MATLAB/Simulink model for utility scale (multi-MW) alkaline and PEM electrolyser technologies. Successively, different distribution, storage and transportation configurations are evaluated based on the 2025 Japanese case study according to the declared H₂ demand. Transport in the form of liquefied hydrogen (LH₂) and via ammonia (NH₃) carrier is compared from the port of Antofagasta, CL to the port of Osaka, JP.     

Supporting green Urban mobility – The case of a small-scale autonomous hydrogen refuelling station

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 €/kg_H2 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.     

Large-scale decomposition of green ammonia for pure hydrogen production

It is acknowledged that Hydrogen has a decisive role to play in insuring a reliable and efficient penetration of renewable electricity in the energy mix. Nonetheless, building a sustainable Hydrogen Economy is faced with numerous challenges across the value chain. Namely, large-scale production and storage are still open issues that need to be addressed. A promising solution is to store renewable H₂ in the form of green ammonia often referred to as Power-to-Ammonia. Thus unlocking all available infrastructure for ammonia to effectively store and export hydrogen in bulk. In this value chain, the missing link is ammonia cracking to recover back hydrogen at high purities. The present work explores a technical solution to recover hydrogen from ammonia at large-scale. Through an exhaustive technoeconomic analysis, we have demonstrated the feasibility of large-scale production of pure H₂ from ammonia. The designed Ammonia-to-H₂ plant operates at a thermal efficiency of 68.5% to produce 200 MTPD of pure hydrogen at 250 bar. Furthermore, this study has established a final estimation of the Levelized Cost of Hydrogen (LCOH) from green ammonia. It was revealed that LCOH is mostly dependent on green ammonia cost, which in turn varies with renewable electricity cost.     

Techno-economic assessment of green hydrogen valley providing multiple end-users

A techno-economic analysis of a hydrogen valley is carried out in this paper. A hydrogen generator fed by a wind farm (WF) and/or a photovoltaic (PV) plant supplies four end-users: a stationary fuel cell, a hydrogen refuelling station, the injection in the natural gas pipeline and, in case of sufficient hydrogen surplus, a biological hydrogen methanation (BHM) process.The results demonstrated that an efficiency improvement and a reduction in hydrogen production costs arise from a balanced supply from wind and solar energy. Without the inclusion of a BHM process, hydrogen production costs lower than 7 €/kg were achieved by a hydrogen generator using 10–12% of the PV + WF annual energy with a PV share of 20%–50%. The hydrogen production costs were further reduced to 5 €/kg by introducing a BHM process and increasing the percentage of electrical energy supplied by the PV + WF system to 25% of its overall production.     

Renewable hydrogen production: A techno-economic comparison of photoelectrochemical cells and photovoltaic-electrolysis

The present paper reports a techno-economic analysis of two solar assisted hydrogen production technologies: a photoelectrochemical (PEC) system and its major competitor, a photovoltaic system connected to a conventional water electrolyzer (PV-E system). A comparison between these two types was performed to identify the more promising technology based on the levelized cost of hydrogen (LCOH). The technical evaluation was carried out by considering proven designs and materials for the PV-E system, and a conceptually design for the PEC system extrapolated to future, commercial scale.The LCOH for the off-grid PV-E system was found to be 6.22 $/kg_H2, with a solar to hydrogen efficiency of 10.9%. For the PEC system, with a similar efficiency of 10%, the LCOH was calculated to be much higher, namely 8.43 $/kg_H2. A sensitivity analysis reveals a great uncertainty in the LCOH of the prospective PEC system. This implies that much effort would be needed for this technology to become competitive on the market.Therefore we conclude that the potential techno-economic benefits that PEC systems offer over PV-E are uncertain, and even in the best case, limited. While research into photoelectrochemical cells remains of interest, it presents a poor case for dedicated investment in the technology's development and scale-up.