Towards net-zero compatible hydrogen from steam reformation – Techno-economic analysis of process design options

Increased consumption of low-carbon hydrogen is prominent in the decarbonisation strategies of many jurisdictions. Yet prior studies assessing the current most prevalent production method, steam reformation of natural gas (SRNG), have not sufficiently evaluated how process design decisions affect life cycle greenhouse gas (GHG) emissions. This techno-economic case study assesses cradle-to-gate emissions of hydrogen produced from SRNG with CO₂ capture and storage (CCS) in British Columbia, Canada. Four process configurations with amine-based CCS using existing technology and novel process designs are evaluated. We find that cradle-to-gate GHG emission intensity ranges from 0.7 to 2.7 kgCO₂e/kgH₂ – significantly lower than previous studies of SRNG with CCS and similar to the range of published estimates for hydrogen produced from renewable-powered electrolysis. The levelized cost of hydrogen (LCOH) in this study (US$1.1–1.3/kgH₂) is significantly lower than published estimates for renewable-powered electrolysis.     

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.     

Hydrogen as a long-term,large-scale energy storage solution when coupled with renewable energy sources or grids with dynamic electricity pricing schemes

One of the key challenges that still facing the adoption of renewable energy systems is having a powerful energy storage system (ESS) that can store energy at peak production periods and return it back when the demand exceeds the supply. In this paper, we discuss the costs associated with storing excess energy from power grids in the form of hydrogen using proton exchange membrane (PEM) reversible fuel cells (RFC). The PEM-RFC system is designed to have dual functions: (1) to use electricity from the wholesale electricity market when the wholesale price reaches low competitive values, use it to produce hydrogen and then convert it back to electricity when the prices are competitive, and (2) to produce hydrogen at low costs to be used in other applications such as a fuel for fuel cell electric vehicles. The main goal of the model is to minimize the levelized cost of energy storage (LCOS), thus the LCOS is used as the key measure for evaluating this economic point. LCOS in many regions in United States can reach competitive costs, for example lowest LCOS can reach 16.4¢/kWh in Illinois (MISO trading hub) when the threshold wholesale electricity price is set at $25/MWh, and 19.9¢/kWh in Texas (ERCOT trading hub) at threshold price of $20/MWh. Similarly, the levelized cost of hydrogen production shows that hydrogen can be produced at very competitive costs, for example the levelized cost of hydrogen production can reach $2.54/kg-H₂ when using electricity from MISO hub. This value is close to the target set by the U.S. Department of Energy.     

Techno-economic evaluation of a grid-connected PV-trigeneration-hydrogen production hybrid system on a university campus

Many universities have plans to reduce campus energy consumption with developed energy efficiency strategies, supply the energy needs of the university campus with renewable energy and create a green campus. In order to serve this purpose, this study focuses on the simulation of the installation of an on-grid photovoltaic (PV) power system at the Vocational Colleges Campus, Hitit University. On the other hand, the integration of the simulated PV system with a gas fired-trigeneration system is discussed. Moreover, the study explores opportunities for solar hydrogen generation without energy storage on campus. For the PV system simulation, three different scenarios were created by using web-based PV system design software (HelioScope). Installed powers in the simulation were found as 94.2 kWe, 123.9 kWe, and 157.5 kWe for the low scenario (on the rooftop), high scenario (on the rooftop), and the high + PV canopy arrays scenario (on the rooftop and an outdoor parking area), respectively. The levelized cost of electricity (LCOE) values were 0.061 $/kWh, 0.065 $/kWh, and 0.063 $/kWh for the low scenario, high scenario, and the scenario including PV canopy, respectively. The energy payback time is found to be 6.47–6.94 years for the 20–25 years lifetime of the PV plant. The simulation results showed that the PV system could support it by generating additional electrical energy up to 25% of the existing system. The campus can reduce GHG emissions of 1546–2272 tonnes-CO₂eq, which is equivalent to 142–209 ha of forest-absorbing carbon unused during the life of the PV system. Depending on the production and consumption methods utilized on campus, which is a location with relatively large solar potential, the levelized cost of hydrogen (LCOH) of hydrogen generation ranged from 0.054 $/kWhH₂ (1.78 $/kgH₂) to 0.103 $/kWhH₂ (3.4 $/kgH₂). Consequently, with proper planning and design, a grid-connected PV-trigeneration-hydrogen generation hybrid system on a university campus may operate successfully.     

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 flexible decarbonized hydrogen and power co-production based on natural gas dry reforming

The need for flexible power plants could increase in the future as variable renewable energy (VRE) share will increase in the power grid. These power plants could balance the increasing strain on electricity grids by renewables. The proposed plant in this paper can adapt to these ramps in electricity demand of the power grid by maintaining a constant feed and producing also high purity hydrogen. Dry methane reforming (DMR) is incorporated into a flexible power plant model and the key performance indicators are calculated from a techno-economic perspective. The net output of the plant is 450 MW with the possibility to lower power production and produce hydrogen, maintaining a high CO₂ capture rate (72%). Two cases are compared to the base case to quantify: (i) energy and cost penalties for CO₂ capture and (ii) advantages of flexible power plant operation. The levelized cost of electricity (LCOE) for the base case is 67 Euro/MWh, the addition of a carbon capture unit increases it to 82 Euro/MWh. In the case of flexible operation, both the LCOE and levelized cost of hydrogen (LCOH) are calculated and the two depend on the cost allocation factor. The LCOE ranges from 65 to 85 Euro/MWh while the LCOH from 0.15 to 0.073 Euro/Nm³. The DMR power plant presented in Cases 1 and 2 present little advantages in today's market conditions however, the flexible plant (Case 3) can be viable option in balancing VRE.     

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%.     

Centralized and decentralized electrolysis-based hydrogen supply systems for road transportation – A modeling study of current and future costs

This work compares the costs of three electrolysis-based hydrogen supply systems for heavy road transportation: a decentralized, off-grid system for hydrogen production from wind and solar power (Dec-Sa); a decentralized system connected to the electricity grid (Dec-Gc); and a centralized grid-connected electrolyzer with hydrogen transported to refueling stations (Cen-Gc). A cost-minimizing optimization model was developed in which the hydrogen production is designed to meet the demand at refueling stations at the lowest total cost for two timeframes: one with current electricity prices and one with estimated future prices. The results show that: For most of the studied geographical regions, Dec-Gc gives the lowest costs of hydrogen delivery (2.2–3.3€/kgH₂), while Dec-Sa entails higher hydrogen production costs (2.5–6.7€/kgH₂). In addition, the centralized system (Cen-Gc) involves lower costs for production and storage than the grid-connected decentralized system (Dec-Gc), although the additional costs for hydrogen transport increase the total cost (3.5–4.8€/kgH₂).     

Life cycle cost analysis of electricity storage facilities in flexible power systems

Global efforts towards de-carbonization have opened the pathway for a test environment of electrical energy storage (EES) topology. In this work, the feasibility of 17 EES facilities applied to 24 individual applications of flexible power networks has been investigated in terms of levelized cost of storage (LCOS) in $/kW. Electricity storage facilities were modelled and evaluated via a life-cycle cost analysis, based on the most realistic EES characteristics and practical applications’ requirements. The results showed that pumped-hydro constitutes the least-cost and most reliable system for large-scale/long-duration applications. Zn-air and vanadium redox (VRB) offer great potential in demand-shifting and reactive support but, due to their wide LCOS range, considerable risk is added in such an investment. Electrochemical double-layer capacitor (EDLC) holds almost the exclusivity in fast-response/frequently-cycled applications, while for medium-term/medium-scale applications and where the large footprint is a prohibitive factor, valve-regulated Pb-acid (VRLA) and hydrogen fuel cells (H₂-FC) are more favourable options. However, efficient tools still lack the ability of quantifying all benefits derived from electricity storage, maintaining stakeholders’ concerns for investment. It is apparent that, further research and development implies the decrease of the uncertainty governing the majority of EES technologies, increasing EES implementations and vice versa.     

Assessing sizing optimality of OFF-GRID AC-linked solar PV-PEM systems for hydrogen production

Herein, a novel methodology to perform optimal sizing of AC-linked solar PV-PEM systems is proposed. The novelty of this work is the proposition of the solar plant to electrolyzer capacity ratio (AC/AC ratio) as optimization variable. The impact of this AC/AC ratio on the Levelized Cost of Hydrogen (LCOH) and the deviation of the solar DC/AC ratio when optimized specifically for hydrogen production are quantified. Case studies covering a Global Horizontal Irradiation (GHI) range of 1400–2600 kWh/m²-year are assessed. The obtained LCOHs range between 5.9 and 11.3 USD/kgH₂ depending on sizing and location. The AC/AC ratio is found to strongly affect cost, production and LCOH optimality while the optimal solar DC/AC ratio varies up to 54% when optimized to minimize the cost of hydrogen instead of the cost of energy only. Larger oversizing is required for low GHI locations; however, H₂ production is more sensitive to sizing ratios for high GHI locations.     

A flexible techno-economic analysis tool for regional hydrogen hubs – A case study for Ireland

The increasing urgency with which climate change must be addressed has led to an unprecedented level of interest in hydrogen as a clean energy carrier. Much of the analysis of hydrogen until this point has focused predominantly on hydrogen production. This paper aims to address this by developing a flexible techno-economic analysis (TEA) tool that can be used to evaluate the potential of future scenarios where hydrogen is produced, stored, and distributed within a region. The tool takes a full year of hourly data for renewables availability and dispatch down (the sum of curtailment and constraint), wholesale electricity market prices, and hydrogen demand, as well as other user-defined inputs, and sizes electrolyser capacity in order to minimise cost. The model is applied to a number of case studies on the island of Ireland, which includes Ireland and Northern Ireland. For the scenarios analysed, the overall LCOH ranges from €2.75–3.95/kgH₂. Higher costs for scenarios without access to geological storage indicate the importance of cost-effective storage to allow flexible hydrogen production to reduce electricity costs whilst consistently meeting a set demand.     

Renewable-powered hydrogen economy from Australia's perspective

This article broadly reviews the state-of-the-art technologies for hydrogen production routes, and methods of renewable integration. It outlines the main techno-economic enabler factors for Australia to transform and lead the regional energy market. Two main categories for competitive and commercial-scale hydrogen production routes in Australia are identified: 1) electrolysis powered by renewable, and 2) fossil fuel cracking via steam methane reforming (SMR) or coal gasification which must be coupled with carbon capture and sequestration (CCS). It is reported that Australia is able to competitively lower the levelized cost of hydrogen (LCOH) to a record $(1.88–2.30)/kg_H2 for SMR technologies, and $(2.02–2.47)/kg_H2 for black-coal gasification technologies. Comparatively, the LCOH via electrolysis technologies is in the range of $(4.78–5.84)/kg_H2 for the alkaline electrolysis (AE) and $(6.08–7.43)/kg_H2 for the proton exchange membrane (PEM) counterparts. Nevertheless, hydrogen production must be linked to the right infrastructure in transport-storage-conversion to demonstrate appealing business models.     

H2NG environmental-energy-economic effects in hybrid energy systems for building refurbishment in future National Power to Gas scenarios

In order to comply to the ambitious targets of European Hydrogen Strategy, Member States will strongly encourage the deployment of Power-to-Gas (PtG) technologies. A significant fraction of produced green hydrogen will be injected into the existing natural gas networks, and the end-users will be served by Hydrogen enriched Natural Gas blends (H₂NG). The aim of this paper is to analyse the H₂NG effects on technical, economic and environmental parameters of hybrid energy systems for building refurbishment. Three hybrid energy systems for the existing plants replacement have been proposed, dynamically simulated and compared with the separate generation. Fuel supply has been simulated by varying the H₂ volumetric fraction in a range between 0 and 20%vol. The H₂NG blend employment will allow greater primary energy savings and avoided emissions. However, if the levelized cost of hydrogen (LCOH) due to electrolysis does not decrease, those benefits will be offset by a lower economic competitiveness.     

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.     

A GIS-based assessment of coal-based hydrogen infrastructure deployment in the state of Ohio

Hydrogen infrastructure costs will vary by region as geographic characteristics and feedstocks differ. This paper proposes a method for optimizing regional hydrogen infrastructure deployment by combining detailed spatial data in a geographic information system (GIS) with a technoeconomic model of hydrogen infrastructure components. The method is applied to a case study in Ohio in which coal-based hydrogen infrastructure with carbon capture and storage (CCS) is modeled for two distribution modes at several steady-state hydrogen vehicle market penetration levels. The paper identifies the optimal infrastructure design at each market penetration as well as the costs, CO₂ emissions, and energy use associated with each infrastructure pathway. The results indicate that aggregating infrastructure at the regional-scale yields lower levelized costs of hydrogen than at the city-level at a given market penetration level, and centralized production with pipeline distribution is the favored pathway even at low market penetration. Based upon the hydrogen infrastructure designs evaluated in this paper, coal-based hydrogen production with CCS can significantly reduce transportation-related CO₂ emissions at a relatively low infrastructure cost and levelized fuel cost.     

Solar hydrogen production in urban areas of Mexico: towards hydrogen cities

Many efforts have been made to assess the potential of green hydrogen production at global, regional, and national levels using Geographic Information Systems (GIS); however, many dismiss the possibility of producing hydrogen in urban settlements. In order to reveal the true potential of these areas, it is essential to provide arguments that allow evaluation of the feasibility of promoting and impulsing the concept of hydrogen cities. Based on this idea, this work assesses the monthly and annual potential of solar hydrogen in urban areas of Mexico using actual measurements of sunshine duration as electrolyzer production times. Moreover, as light transportation is crucial for cities, we examine the substitution of gasoline with hydrogen and its cost throughout the year. These constitute the main contribution of the present work.This study departs from the geographical and technical potential of solar energy, and by using GIS, the amount of hydrogen production per unit of area (Ton/(km² year)) was computed. The levelized cost of hydrogen production (LCOH) is also evaluated, using two of the most popular and commercial electrolysis technologies: PEM and Alkaline.Our results revealed that Mexican urban areas have a high potential to produce solar hydrogen, having an average annual production that varies from 1991.8 Ton/km² to 4338.3 Ton/km² according to the region. The total solar hydrogen potential of all Mexican urban places is 9.39 MTon/year, which could satisfy up to 42.6 times the 2020 hydrogen demand of Mexico. We found that the national gasoline consumption could be replaced by H₂, requiring between 42% and 52% of the total urban production.Additionally, the national average of LCOH was found to be about 6.25 USD/kg for alkaline electrolyzer and 9.50 USD/kg for PEM technology, considering the yearly average sunshine duration of 3237 h/year, which means that Mexico could be competitive at large-scale hydrogen production by using Alkaline technology. Our findings have the potential to impact positively on the country since they provide information to facilitate the derivation of public policies from a rigorous and technical perspective.     

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).     

Cost assessment and evaluation of various hydrogen delivery scenarios

In this paper, performance and cost assessment studies, including the stages of hydrogen storage, transmission and distribution of three different hydrogen delivery pathways are undertaken comparatively. The produced hydrogen is stored under different temperatures and pressures and then transported to the nearby cities for distribution. In addition, three different methods for the transportation of the produced hydrogen to the distribution centers are studied, which are as transportation for hydrogen by the pressurized tanks, cryogenic liquid hydrogen tanker and the gas pipelines. Moreover, the transmission options from the distribution center to the target consumer are also examined for three different conditions. As a result, the hydrogen production capacity, the levelized cost of energy distribution (in $/kg), the infrastructure costs (truck, tanker number, gas line costs, etc.) for the selected transmission scenario are calculated. Furthermore, the environmental impact (greenhouse gas (GHG) emissions) and some application parameters of the proposed system (e.g., number of hydrogen fuel stations and the distance between the stations, length of the distribution lines, etc.) are also determined. The highest levelized cost of delivery is obtained as 8.02 $/kg H₂ for the first scenario whereas the lowest cost is obtained as 2.73 $/kg H₂ for the third scenario.     

Techno-economic analysis of hydrogen transportation infrastructure using ammonia and methanol

The transformation from a fossil fuels economy to a low carbon economy reshapes how energy is transmitted. Since most renewable energy is harvested in the form of electricity, hydrogen obtained from water electrolysis using green electricity is considered a promising energy vector. However, the storage and transportation of hydrogen at large scales pose challenges to the existing energy infrastructures, both regarding technological and economic aspects. To facilitate the distribution of renewable energy, a set of candidate hydrogen transportation infrastructures using methanol and ammonia as hydrogen carriers were proposed. A systematical analysis reveals that the levelized costs of transporting hydrogen using methanol and ammonia in the best cases are $1879/t-H₂ and $1479/t-H₂, respectively. The levelized cost of energy transportation using proposed infrastructures in the best case is $10.09/GJ. A benchmark for hydrogen transportation infrastructure design is provided in this study.     

Cost analysis of wind-electrolyzer-fuel cell system for energy demand in Pınarbaşı-Kayseri

In this study, the hydrogen production potential and costs by using wind/electrolysis system in P?narba??-Kayseri were considered. In order to evaluate costs and quantities of produced hydrogen, for three different hub heights (50 m, 80 m and 100 m) and two different electrolyzer cases, such as one electrolyzer with rated power of 120 kW (Case-I) and three electrolyzers with rated power of 40 kW (Case-II) were investigated. Levelised cost of electricity method was used in order to determine the cost analysis of wind energy and hydrogen production. The results of calculations brought out that the electricity costs of the wind turbines and hydrogen production costs of the electrolyzers are decreased with the increase of turbine hub height. The maximum hydrogen production quantity was obtained 14192 kgH₂/year and minimum hydrogen cost was obtained 8.5 $/kgH₂ at 100 m hub height in the Case-II.