Electrolyser Capacity Research Articles

Sustainability of hydrogen refuelling stations for trains using electrolysers

Hydrogen has the potential to become a powerful energy vector with different applications in many sectors (industrial, residential, transportation and other applications) as it offers a clean, sustainable, and flexible alternative. Hydrogen trains use compressed hydrogen as fuel to generate electricity using a hybrid system (combining fuel cell and batteries) to power traction motors and auxiliaries. This hydrogen trains are fuelled with hydrogen at the central train depot, like diesel locomotives. The main goal of this paper is to perform a techno-economic analysis for a hydrogen refuelling stations using on-site production, based on PEM electrolyser technology in order to supply hydrogen to a 20 hydrogen-powered trains captive fleet. A sensitivity analysis on the main parameters will be performed as well, in order to acquire the knowledge required to take any decisions on implementation regarding electricity cost, hydrogen selling price, number of operation hours and number of trains for the captive fleet.The main methodology considers the evaluation of the project based on the Net Present Value calculation and the sensitivity analysis through standard method using Oracle Crystal Ball. The main result shows that the use of hydrogen as an alternative fuel for trains is a sustainable and profitable solution from the economic, environmental and safety points of view.The economic analysis concludes with the need to negotiate an electricity cost lower than 50 €/MWh, in order to be able to establish the hydrogen selling price at a rate higher than 4.5€/kg. The number of operating hours should be higher than 4800 h per year, and the electrolyser system capacity (or hydrogen refuelling station capacity) should be greater than 3.5 MW in order to reach a Net Present Value of 7,115,391 € with a Return of Investment set to 9 years. The result of the multiparametric sensitivity analysis for the Net Present Value (NPV) shows an 85.6% certainty that the project will have a positive result (i.e. profitability) (NPV> 0). The two main variables with the largest impact on Net Present Value are the electrolyser capacity (or hydrogen refuelling station capacity) and the hydrogen selling price. Moreover, a margin of improvement (higher NPV) could be reached with the monetization of the heat, oxygen by-product and CO2 emission reduction.

On capital utilization in the hydrogen economy: The quest to minimize idle capacity in renewables-rich energy systems

The hydrogen economy is currently experiencing a surge in attention, partly due to the possibility of absorbing variable renewable energy (VRE) production peaks through electrolysis. A fundamental challenge with this approach is low utilization rates of various parts of the integrated electricity-hydrogen system. To assess the importance of capacity utilization, this paper introduces a novel stylized numerical energy system model incorporating the major elements of electricity and hydrogen generation, transmission and storage, including both “green” hydrogen from electrolysis and “blue” hydrogen from natural gas reforming with CO2 capture and storage (CCS). Concurrent optimization of all major system elements revealed that balancing VRE with electrolysis involves substantial additional costs beyond reduced electrolyzer capacity factors. Depending on the location of electrolyzers, greater capital expenditures are also required for hydrogen pipelines and storage infrastructure (to handle intermittent hydrogen production) or electricity transmission networks (to transmit VRE peaks to electrolyzers). Blue hydrogen scenarios face similar constraints. High VRE shares impose low utilization rates of CO2 capture, transport and storage infrastructure for conventional CCS, and of hydrogen transmission and storage infrastructure for a novel process (gas switching reforming) that enables flexible power and hydrogen production. In conclusion, all major system elements must be considered to accurately reflect the costs of using hydrogen to integrate higher VRE shares.

Is the coherence of coal phase-out and electrolytic hydrogen production the golden path to effective decarbonisation?

We analyse whether Germany will fall short of the country’s decarbonisation targets. Bearing this potential failure in mind, the present study investigates technological options and their effectiveness for decarbonising the energy system from a systemic perspective. We consider the country’s coal phase-out, the increasing amounts of electricity from renewable energy sources, more efficient heating concepts as well as the evolving of smart charging infrastructures and large-scale storage options. Based on the declared plans of the federal authorities and alternative proposals of environmental associations, ten distinct decarbonisation scenarios for the period from 2020 to 2030 form the basis of our models. Using the Energy PLAN simulation tool, annual and hourly performance indicators were computed in order to evaluate the effectiveness of decarbonisation measures. In particular, we examine the increasing usage of electrolysers for both the absorption of excess electricity and the production of hydrogen as a substitute for fossil fuels in relation to the timing of the coal phase-out. Pursuing this approach, we demonstrate the coherence between coal phase-out policies and low carbon technology diffusion. Our findings reveal that implementing the coal phase-out earlier than has been scheduled by the country’s Commission on Growth, Structural Change and Employment mitigates the non-achievement of the decarbonisation targets. Moreover, our results suggest the upscaling of domestic electrolyser capacity to up to 9554 MW by 2030.

At What Cost Can Renewable Hydrogen Offset Fossil Fuel Use in Ireland’s Gas Network?

The results of a techno-economic model of distributed wind-hydrogen systems (WHS) located at each existing wind farm on the island of Ireland are presented in this paper. Hydrogen is produced by water electrolysis from wind energy and backed up by grid electricity, compressed before temporarily stored, then transported to the nearest injection location on the natural gas network. The model employs a novel correlation-based approach to select an optimum electrolyser capacity that generates a minimum levelised cost of hydrogen production (LCOH) for each WHS. Three scenarios of electrolyser operation are studied: (1) curtailed wind, (2) available wind, and (3) full capacity operations. Additionally, two sets of input parameters are used: (1) current and (2) future techno-economic parameters. Additionally, two electricity prices are considered: (1) low and (2) high prices. A closest facility algorithm in a geographic information system (GIS) package identifies the shortest routes from each WHS to its nearest injection point. By using current parameters, results show that small wind farms are not suitable to run electrolysers under available wind operation. They must be run at full capacity to achieve sufficiently low LCOH. At full capacity, the future average LCOH is 6–8 €/kg with total hydrogen production capacity of 49 kilotonnes per year, or equivalent to nearly 3% of Irish natural gas consumption. This potential will increase significantly due to the projected expansion of installed wind capacity in Ireland from 5 GW in 2020 to 10 GW in 2030.

The Impacts of High V2G Participation in a 100% Renewable Åland Energy System

A 100% renewable energy (RE) scenario featuring high participation in vehicle-to-grid (V2G) services was developed for the Åland islands for 2030 using the EnergyPLAN modelling tool. Hourly data was analysed to determine the roles of various energy storage solutions, notably V2G connections that extended into electric boat batteries. Two weeks of interest (max/min RE) generation were studied in detail to determine the roles of energy storage solutions. Participation in V2G connections facilitated high shares of variable RE on a daily and weekly basis. In a Sustainable Mobility scenario, high participation in V2G (2750 MWhe) resulted in less gas storage (1200 MWhth), electrolyser capacity (6.1 MWe), methanation capacity (3.9 MWhgas), and offshore wind power capacity (55 MWe) than other scenarios that featured lower V2G participation. Consequently, total annualised costs were lower (225 M€/a). The influence of V2G connections on seasonal storage is an interesting result for a relatively cold, northern geographic area. A key point is that stored electricity need not only be considered as storage for future use by the grid, but V2G batteries can provide a buffer between generation of intermittent RE and its end-use. Direct consumption of intermittent RE further reduces the need for storage and generation capacities.

Dutch hydrogen coalition aims to boost electrolyser capacity

Greenpeace Netherlands has spearheaded a new Dutch Hydrogen Coalition, comprising the main power and electricity and gas network operators as well as the chemical, electrolyser and steel industries, with the aim of operating 3–4 GW in electrolyser capacity by 2030.

System-level power-to-gas energy storage for high penetrations of variable renewables

According to outlooks by the IEA and the U.S. EIA, renewables will become the largest source of electricity by 2050 if global temperature rise is to be limited to 2 °C. However, at penetrations greater than 30%, curtailment of wind and solar can be significant in even the most flexible systems. Energy storage can reduce curtailment and increase utilisation of variable renewables. Power-to-gas is a form of long-term storage based on electrolytic production of hydrogen. This research models the co-sizing of wind and solar PV capacity and electrolyser capacity in a jurisdiction targeting 80% penetration of variable renewable electricity. Results indicate that power-to-gas can reduce required wind and solar capacity by as much as 23% and curtailment by as much as 87%. While the majority of charging events last less than 12 h, the majority of the total annual stored energy comes from longer-term events. Additional scenarios reveal that geographic diversity of wind farms reduces capacity requirements, but the same benefit is not found for distributing solar PV.

Feasibility of renewable hydrogen based energy supply for a district

Renewable generation technologies (e.g. photovoltaic panels (PV)) are often installed in buildings and districts with an aim to decrease their carbon emissions and consumption of non-renewable energy. However, due to a mismatch between supply and demand at an hourly but also on a seasonal timescale; a large amount of electricity is exported to the grid rather than used to offset local demand. A solution to this is local storage of electricity for subsequent self-consumption. This could additionally provide districts with new business opportunities, financial stability, flexibility and reliability.In this paper the feasibility of hydrogen based electricity storage for a district is evaluated. The district energy system (DES) includes PV and hybrid photovoltaic panels (PVT). The proposed storage system consists of production of hydrogen using the renewable electricity generated within the district, hydrogen storage, and subsequent use in a fuel cell. Combination of battery storage along with hydrogen conversion and storage is also evaluated. A multi-energy optimization approach is used to model the DES. Results of the model are optimal battery capacity, electrolyzer capacity, hydrogen storage capacity, fuel cell capacity and energy flows through the system. The model is also used to compare different system design configurations. The results of this analysis show that both battery capacity and conversion of electricity to hydrogen enable the district to decrease its carbon emissions by approximately 22% when compared to the reference case with no energy storage.

Hybridization strategies of power-to-gas systems and battery storage using renewable energy

In this paper, the hybrid concept to use renewable electricity to produce hydrogen with an electrolyser in combination with a battery is introduced and analysed. This hybrid system opens the possibility to optimise operation and to increase operation times of the system and thus to improve the techno-economic performance. To analyse the performance, a model has been developed, which designs and operates a single or hybrid power-to-gas system in a cost optimal manner. The underlying method is a mixed integer linear programming (MILP) approach, which minimises total system costs. The cost optimisation modelling is performed by a case study for a hybrid electrolyser/battery system directly coupled with a large PV power plant without grid connection. The results show, that batteries can support electrolyser operation in a reasonable way. This is however associated with higher hydrogen production costs and not competitive compared to the installation of additional electrolyser capacity or curtailment of electricity.

Power-to-gas systems for absorbing excess solar power in electricity distribution networks

The feasibility of implementing power-to-gas systems, to absorb surplus solar power from electricity distribution networks and carbon dioxide from biomass anaerobic digestion (AD) plant, in order to produce synthetic methane was investigated for a region of Southern Germany that has a high solar power penetration. The analysis was based on time series electricity data for 2012 from which future load profiles were computed in accordance with the expected installed capacities of solar power across the period 2015–2025. The electrolyser capacity required to absorb 20% of excess solar energy occurring within the region's low voltage network in 2025 was estimated to be 370 MWe. First order considerations of the region's gas grid, electricity network and existing AD sites suggest that such a deployment could be achieved by installing sub-MW (and some multi-MW) power-to-gas plant at several hundred AD sites.

Using surplus nuclear power for hydrogen mobility and power-to-gas in France

Opportunities exist to utilise excess electricity from renewable and nuclear power generation for producing hydrogen. France in particular has a very high penetration of nuclear power plant, some of which is regularly turned down to follow the electricity demand profile. This excess nuclear electricity could be utilised via the electrolysis of water to satisfy the emerging French market for low-carbon hydrogen (principally for mobility applications and the injection of synthetic gas into the natural gas grid). The described analysis examines the use of electrolysers to progressively ‘valley fill’ nuclear load profiles and so limit the need for turning down nuclear plant in France. If an electrolyser capacity of approximately 20 GW is installed, there is already sufficient excess nuclear electricity available now to meet the predicted hydrogen mobility fuel demand for 2050, plus achieve a 5% concentration (by volume) of hydrogen in the gas grid, plus produce approximately 33 TWh p.a. of synthetic methane (via the methanation of hydrogen with carbon dioxide). The pattern of electrolyser utilisation requires operation mostly at a variable part load condition, necessitating the adoption of flexible, efficient, rapid response electrolysers. The proposed approach more fully utilises the substantial existing nuclear power assets of France and provides an additional pathway to renewables for reducing the CO2 emissions of hydrogen production.

Life Time Performance Characterization of Solid Oxide Electrolysis Cells for Hydrogen Production

Globally the amount of electricity generated from renewable energy sources such as wind or solar energy is increasing. To integrate high amount of fluctuating renewable energy into the existing energy grid, efficient and cost competitive conversion of electricity into other kinds of energy carriers is needed. Solid oxide electrolysis cells (SOECs) offer a promising technological solution for efficient energy conversion and production of hydrogen or syngas (mixture of H2 and CO) using excess electricity from renewable energy sources. For SOECs to become commercially interesting, performance, durability, and cost are among the most critical issues. Long-term stable performance over 5-10 years of operation is generally required. The commercialization of the SOEC technology can be further promoted if SOECs can be operated at high current density, as it helps reducing electrolyser capacity cost significantly. In this work, long-term durability of Ni/yttria stabilized zirconia (YSZ) supported planar SOECs were investigated at 800 oC for electrolysis of steam. The cells, which represent the state-of-the-art SOEC technology at Technical University of Denmark (DTU), have a Ni/YSZ support and active fuel electrode, a YSZ electrolyte, a gadolinia doped ceria (CGO) barrier layer and a LSCF/CGO (LSCF: strontium and cobalt co-doped lanthanum ferrite) composite oxygen electrode. The cells were exposed to long-term galvanostatic electrolysis tests at different current densities from 0 (i.e. under open circuit voltage, OCV) to -1.25 A/cm2. Detailed electrochemical and post-mortem characterizations were further conducted in order to clarify the cell or electrode degradation mechanisms. The cells show stable performance, with a steady-state degradation rate of up to 2 %/1000 h for electrolysis tests with current densities up to -1 A/cm2. The long-term degradation is dominated by increase in serial resistance, which can be associated to a great extent with microstructure changes in the active Ni/YSZ electrode, namely Ni loss (directly reflected by an increase in the porosity) and Ni re-distribution. Operating the cells at -1.25 A/cm2 causes severe and accelerated degradation, which is associated with both the Ni/YSZ fuel electrode and the LSCF/CGO oxygen electrode. Assuming an end-of-life cell voltage of 1.5 V, the cell life time is then predicted as a function of electrolysis current density. The current generation SOEC cells produced at DTU are able to be operated at current density up to ~-0.9 A/cm2, in order to achieve a commercialization target of 5 years lifetime (for continuous electrolysis operation of hydrogen production). The cells can be operated at even higher current density, if the hydrogen production is intermittent. The results of the current work provide valuable technological inputs to future design of electrolysis plants for hydrogen production.

Optimization of Stand-alone PV-FC Hybrid System under Thailand Climate

The linear programing optimization technique is used for system optimal design. The objective function was set to minimize the system cost. Cost of energy (COE) was also considered. The average solar irradiance and average ambient temperature of Thailand are 800 W/m2 and 30°C, respectively. The electrical load profile varies with time of the day that is dependent on the activity patterns and the type of appliances used. The optimization results shows that the optimal size of PV array, fuel cell (FC) and electrolyzer (ELE) capacity were 5.50 kW, 1.80 kW, and 2.44 kW, respectively. Whereas the minimum system cost was 516,800 Baht. The long-term performance analysis of a standalone PV-FC hybrid system under Thailand climate is showed with normalized yearly analysis as follows; the monthly final yield Yf is 3.55 h/d. The corresponding performance ratio PR ranges from 40 to 53%. The capture loss (LC) and system loss (LS) range from 0.46 h/d to 0.80 h/d and 1.73 h/d to 3.01 h/d, respectively.

Implementation and control of electrolysers to achieve high penetrations of renewable power

The mass deployment of electrolysers, within a power system serving a region of high wind resource, as the enabling mechanism for achieving five key objectives is assessed (that is: a very high installed capacity of wind power plant (WPP); zero wind curtailment during times of low demand; a very high load factor for thermal power plant; an electricity supply of low-carbon intensity; and a hydrogen supply of low-carbon intensity). Three electrolyser implementation cases were simulated for three days characterised mainly by wind availability and emphasis was placed on maximizing the smoothness of the load profile (LF) applied to thermal power plant. If zero-carbon hydrogen is to be produced a daily load factor for thermal power plant of 90% is the upper limit, but load factors of up to 100% are achievable if a carbon intensity of 3 kgCO 2 / kgH 2 is permitted. For wind penetrations exceeding approximately 30% of system maximum demand, the electrolyser stock must include implementations close to WPP if curtailment is to be avoided. To achieve very high wind penetrations and very high load factors for thermal power plant requires a large stock of electrolysers—for the system investigated approximately 1.1 MW of electrolyser capacity is required per installed MW of wind power.

The market potential for electrolytic hydrogen

By the year 2000, the potential market for advanced technology electrolytic hydrogen among specialty users is projected to be about half of what the merchant hydrogen market would be in the absence of electrolytic hydrogen. This potential market, representing an annual demand of about 16 billion SCF of hydrogen (approx. 200 MW of installed electrolyzer capacity), will develop from market penetrations of electrolyzers assumed to begin in the early 1980s.

Oral Diagnosis

The linear programing optimization technique is used for system optimal design. The objective function was set to minimize the system cost. Cost of energy (COE) was also considered. The average solar irradiance and average ambient temperature of Thailand are 800 W/m2 and 30°C, respectively. The electrical load profile varies with time of the day that is dependent on the activity patterns and the type of appliances used. The optimization results shows that the optimal size of PV array, fuel cell (FC) and electrolyzer (ELE) capacity were 5.50 kW, 1.80 kW, and 2.44 kW, respectively. Whereas the minimum system cost was 516,800 Baht. The long-term performance analysis of a standalone PV-FC hybrid system under Thailand climate is showed with normalized yearly analysis as follows; the monthly final yield Yf is 3.55 h/d. The corresponding performance ratio PR ranges from 40 to 53%. The capture loss (LC) and system loss (LS) range from 0.46 h/d to 0.80 h/d and 1.73 h/d to 3.01 h/d, respectively.