Hydrogen production from wind energy in Western Canada for upgrading bitumen from oil sands

Hydrogen is produced via steam methane reforming (SMR) for bitumen upgrading which results in significant greenhouse gas (GHG) emissions. Wind energy based hydrogen can reduce the GHG footprint of the bitumen upgrading industry. This paper is aimed at developing a detailed data-intensive techno-economic model for assessment of hydrogen production from wind energy via the electrolysis of water. The proposed wind/hydrogen plant is based on an expansion of an existing wind farm with unit wind turbine size of 1.8 MW and with a dual functionality of hydrogen production and electricity generation. An electrolyser size of 240 kW (50 Nm³ H₂/h) and 360 kW (90 Nm³ H₂/h) proved to be the optimal sizes for constant and variable flow rate electrolysers, respectively. The electrolyser sizes aforementioned yielded a minimum hydrogen production price at base case conditions of $10.15/kg H₂ and $7.55/kg H₂. The inclusion of a Feed-in-Tariff (FIT) of $0.13/kWh renders the production price of hydrogen equal to SMR i.e. $0.96/kg H_2, with an internal rate of return (IRR) of 24%. The minimum hydrogen delivery cost was $4.96/kg H₂ at base case conditions. The life cycle CO₂ emissions is 6.35 kg CO₂/kg H₂ including hydrogen delivery to the upgrader via compressed gas trucks.     

Vehicle refueling with liquid hydrogen thermal compression

We have modeled an approach for dispensing pressurized hydrogen to 350 and/or 700 bar vehicle vessels. Instead of relying on compressors, this concept stores liquid hydrogen in cryogenic pressure vessels where pressurization occurs through heat transfer, reducing the station energy footprint from 12 kW h/kgH₂ of energy from the US grid mix to 1.5–2 kW h/kgH₂ of heating. This thermal compression station presents capital cost and reliability advantages by avoiding the expense and maintenance of high-pressure hydrogen compressors, at the detriment of some evaporative losses. The total installed capital cost for a 475 kg/day thermal compression hydrogen refueling station is estimated at about $611,500, an almost 60% cost reduction over today's refueling station cost. The cost for 700 bar dispensing is $5.23/kg H₂ for a conventional station vs. $5.45/kg H₂ for a thermal compression station. If there is a demand for 350 bar H₂ in addition to 700 bar dispensing, the cost of dispensing from a thermal compression station drops to $4.81/kg H₂, which is similar to the cost of a conventional station that dispenses 350 bar H₂ only. Thermal compression also offers capacity flexibility (wide range of pressure, temperature, and station demand) that makes it appealing for early market applications.     

Economic analysis of hydrogen production through a bio-ethanol steam reforming process: Sensitivity analyses and cost estimations

In this study, the hydrogen selling price from ethanol steam reforming has been estimated for two different production scenarios in the United States, i.e. central production (150,000 kg H₂/day) and distributed (forecourt) production (1500 kg H₂/day), based on a process flowchart generated by Aspen Plus^® including downstream purification steps and economic analysis model template published by the U.S Department of Energy (DOE) [1]. The effect of several processing parameters as well as catalyst properties on the hydrogen selling price has been evaluated. $2.69/kg is estimated as the selling price for a central production process of 150,000 kg H₂/day and $4.27/kg for a distributed hydrogen production process at a scale of 1500 kg H₂/day. Among the parameters investigated through sensitivity analyses, ethanol feedstock cost, catalyst cost, and catalytic performance are found to play a significant role on determining the final hydrogen selling price.     

Techno-economic analysis of thermochemical water-splitting system for Co-production of hydrogen and electricity

The two-step thermochemical metal oxide water-splitting cycle with the state-of-the-art material ceria inevitably produces unutilized high-quality heat, in addition to hydrogen (H₂). This study explores whether the ceria cycle can be of greater value by using the excess heat for co-production of electricity. Specially, this technoeconomic study estimates the H₂ production cost in a hybrid ceria cycle, in which excess heat produces electricity in an organic Rankine cycle, to increase revenue and decrease H₂ cost. The estimated H₂ cost from such a co-generation multi-tower plant is still relatively high at $4.55/kg, with an average H₂ production of 1431 kg/day per 27.74 MW_th tower. Sensitivity analyses show opportunities and challenges to achieving $2/kg H₂ through improvements such as increased solar field efficiency, increased revenue from electricity sales, and a decreased capital recovery factor from baseline assumptions. While co-production improves overall system efficiency and economics, achieving $2/kg H₂ remains challenging with ceria as the active material and likely will require a new material.     

Economics of hydrogen production and liquefaction by geothermal energy

Seven models are considered for the production and liquefaction of hydrogen by geothermal energy. In these models, we use electrolysis and high-temperature steam electrolysis processes for hydrogen production, a binary power plant for geothermal power production, and a pre-cooled Linde–Hampson cycle for hydrogen liquefaction. Also, an absorption cooling system is used for the pre-cooling of hydrogen before the liquefaction process. A methodology is developed for the economic analysis of the models. It is estimated that the cost of hydrogen production and liquefaction ranges between 0.979 $/kg H₂ and 2.615 $/kg H₂ depending on the model. The effect of geothermal water temperature on the cost of hydrogen production and liquefaction is investigated. The results show that the cost of hydrogen production and liquefaction decreases as the geothermal water temperature increases. Also, capital costs for the models involving hydrogen liquefaction are greater than those for the models involving hydrogen production only.     

Technoeconomic analysis for hydrogen and carbon Co-Production via catalytic pyrolysis of methane

Catalytic Methane Pyrolysis (CMP) is an innovative method to convert gaseous methane into valuable H₂ and carbon products. The catalytic approach to methane pyrolysis has the potential to decrease the required operating temperature for methane decomposition from >1000 °C to under 700 °C. In this work, a novel inexpensive catalyst is discussed that displays low operating temperatures, while still maintaining high reactivity and long proven lifetimes. The kinetics associated with the catalyst's performance are modeled and a correlation was developed for use with practical simulation tools. A techno-economic assessment was conducted applying experimentally determined kinetics for the CMP reaction with the specific catalyst. Two process concepts that utilize CMP using the novel catalyst are presented in this work. Optimizations were considered in these processes and the CO₂ emissions and cost of hydrogen production of the two optimized cases, CMP with H₂ combustion (CMP-H₂) and CMP with CH₄ Combustion (CMP-CH₄), are compared to that of the current industrial standard for hydrogen production, Steam Methane Reforming with carbon capture and sequestration (SMR-CCS). Both of the proposed concepts convert methane into gaseous hydrogen and valuable carbon products, graphitic carbon to carbon Nano fibers. The carbon price was treated as a variable to determine the sensitivity of hydrogen production cost to the carbon price. The analysis indicates that cost of hydrogen production is highly dependent on the recovery and sale of carbon byproducts. Based on Aspen modeling of these two concepts for large scale hydrogen production (216 tons/day), the cost of hydrogen production, without considering carbon sales, was estimated to be $<3.25/kg, assuming a natural gas price of $7/MMBTU and conservative catalyst cost of $8/kg. Assuming 100% recovery of carbon, the price can be reduced to $0/kg by selling the carbon at <$1/kg. A market assessment suggests that values of graphitic carbon and carbon fibers range from ~$10/kg and ~$25–113/kg, respectively. The cost of H₂ production via conventional SMR is ~$2.2/kg when accounting for the cost of CO₂ sequestration. The proposed processes produce a maximum of 0–2 kg CO₂/kg H₂ in contrast to the 10 kg CO₂/kg H₂ produced via conventional SMR-CCS. The process displays an enormous potential for competitive economics accompanied by reduced greenhouse gas emissions.     

Economic and environmental competitiveness of high temperature electrolysis for hydrogen production

Alternative hydrogen production technologies are sought in part to reduce the greenhouse gas (GHG) emissions intensity compared with Steam Methane Reforming (SMR), currently the most commonly employed hydrogen production technology globally. This study investigates hydrogen production via High Temperature Steam Electrolysis (HTSE) in terms of GHG emissions and cost of hydrogen production using a combination of Aspen HYSYS® modelling and life cycle assessment. Results show that HTSE yields life cycle GHG emissions from 3 to 20 kg CO_2e/kg H₂ and costs from $2.5 to 5/kg H₂, depending on the system parameters (e.g., energy source). A carbon price of $360/tonne CO_2e is estimated to be required to make HTSE economically competitive with SMR. This is estimated to potentially decrease to $50/tonne CO_2e with future technology advancements (e.g., fuel cell lifetime). The study offers insights for technology developers seeking to improve HTSE, and policy makers for decisions such as considering support for development of hydrogen production technologies.     

Techno-economic optimization of PV system for hydrogen production and electric vehicle charging stations under five different climatic conditions in India

India is one of the most populous countries in the world, and this has implications for its energy consumption. The country's electricity generation and road transport are mostly dominated by fossil fuels. As such, this study assessed the techno-economics and environmental impact of a solar photovoltaic power plant for both electricity and hydrogen production at five different locations in India (i.e., Chennai, Indore, Kolkata, Ludhiana, and Mumbai). The hydrogen load represents a refueling station for 20 hydrogen fuel cell vehicles with a tank capacity of 5 kg for each location. According to the results, the highest hydrogen production occurred at Kolkata with 82,054 kg/year, followed by Chennai with 79,030 kg/year. Ludhiana, Indore, and Mumbai followed with 78,524 kg/year, 76,935 kg/year and 74,510 kg/year, respectively. The levelized cost of energy (LCOE) for all locations ranges between 0.41 and 0.48 $/kWh. Mumbai recorded the least LCOH of 3.00 $/kg. The total electricity that could be generated from all five cities combined was found to be about 25 GWh per annum, which translates to an avoidable emission of 20,744.07 metric tons of CO₂e. Replacing the gasoline that could be used to fuel the vehicles with hydrogen will result in a CO₂ reduction potential of 2452.969 tons per annum in India. The findings indicate that the various optimized configurations at the various locations could be economically viable to be developed.     

The cold high-pressure approach to hydrogen delivery

In view of the very expensive and wasteful nature of today's approaches to H₂ delivery, we explore the possibility of transporting cold (200 K) high pressure (875 bar) H₂ in thermally insulated trailers and dispensing H₂ directly from the trailer, with the potential to eliminate station compressor, cascade, and refrigerator, leading to major reductions in station complexity, maintenance, electricity consumption, and cost, while improving functionality by enabling essentially unlimited back to back refuels, and improving safety due to reduced H₂ expansion energy at low temperature.Detailed techno-economic analysis shows promise for substantial delivery cost reductions through cold high pressure H₂ dispensed directly from the trailer. Results indicate that: (1) Terminal operations for cold high pressure H₂ delivery are $0.32/kg H₂ more expensive than for 350 bar compressed gas delivery (today's lowest cost H₂ delivery technology) due to higher level of pressurization (to 1000 bar) and chilling needs (to 165 K). (2) Trailer cost drops slightly ($0.73 vs. $0.81/kg H₂ for a 350 bar trailer) due to increased capacity (1035 kg H₂ delivered vs. 700 kg) compensating for increased capital cost ($906,900 for cold high pressure H₂ vs. $634,000 for 350 bar trailer). (3) Cold hydrogen delivery presents major advantages in fueling station cost, reduced from $1.27 to $0.46/kg H₂ due to elimination of major system components: compressor, cascade, and chiller. (4) Total compression cost (terminal + station) drops from $0.92/kg H₂ ($0.32 terminal and $0.60 station) for 350 bar trailers to $0.55/kg H₂ (all at the terminal) for cold high pressure H2. (5) Elimination of small-scale station compressors is the main contributor to reduced delivery cost due to their inefficiency, capital expense, and maintenance needs. In summary, total delivery cost reduction vs. 350 bar trailer equals $0.58/kg H₂ (from $2.96 to 2.38/kg H₂), equivalent to 24% of the total delivery cost. This large cost advantage will improve the economics of H₂ vehicles facilitating the transition to a future of zero emission transportation.     

A critical review on integrated system design of solar thermochemical water-splitting cycle for hydrogen production

The development of clean hydrogen production methods is important for large-scale hydrogen production applications. The solar thermochemical water-splitting cycle is a promising method that uses the heat provided by solar collectors for clean, efficient, and large-scale hydrogen production. This review summarizes state-of-the-art concentrated solar thermal, thermal storage, and thermochemical water-splitting cycle technologies that can be used for system integration from the perspective of integrated design. Possible schemes for combining these three technologies are also presented. The key issues of the solar copper-chlorine (Cu–Cl) and sulfur-iodine (S–I) cycles, which are the most-studied cycles, have been summarized from system composition, operation strategy, thermal and economic performance, and multi-scenario applications. Moreover, existing design ideas, schemes, and performances of solar thermochemical water-splitting cycles are summarized. The energy efficiency of the solar thermochemical water-splitting cycle is 15–30%. The costs of the solar Cu–Cl and S–I hydrogen production systems are 1.63–9.47 $/kg H₂ and 5.41–10.40 $/kg H₂, respectively. This work also discusses the future challenges for system integration and offers an essential reference and guidance for building a clean, efficient, and large-scale hydrogen production system.     

Assessing techno-economic uncertainties in nuclear power-to-X processes: The case of nuclear hydrogen production via water electrolysis

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.     

Impact of hydrogen refueling configurations and market parameters on the refueling cost of hydrogen

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.     

Efficient STEP (solar thermal electrochemical photo) production of hydrogen – an economic assessment

A consideration of the economic viability of hydrogen fuel production is important in the STEP (Solar Thermal Electrochemical Photo) production of hydrogen fuel. STEP is an innovative way to decrease costs and increase the efficiency of hydrogen fuel production, which is a synergistic process that can use concentrating photovoltaics (CPV) and solar thermal energy to drive a high temperature, low voltage, electrolysis (water-splitting), resulting in H₂ at decreased energy and higher solar efficiency. This study provides evidence that the STEP system is an economically viable solution for the production of hydrogen. STEP occurs at both higher electrolysis and solar conversion efficiencies than conventional room temperature photovoltaic (PV) generation of hydrogen. This paper probes the economic viability of this process, by comparing four different systems: (1) 10% or (2) 14% flat plate PV driven aqueous alkaline electrolysis H₂ production, (3) 25% CPV driven molten electrolysis H₂ production, and (4) 35% CPV driven solid oxide electrolysis H₂ production. The molten and solid oxide electrolysers are high temperature systems that can make use of light, normally discarded, for heating. This significantly increases system efficiency. Using levelized cost analysis, this study shows significant cost reduction using the STEP system. The total price per kg of hydrogen is shown to decrease from $5.74 to $4.96 to $3.01 to $2.61 with the four alternative systems. The advanced STEP plant requires less than one seventh of the land area of the 10% flat cell plant. To generate the 216 million kg H₂/year required by 1 million fuel cell vehicles, the 35% CPV driven solid oxide electrolysis requires a plant only 9.6 mi² in area. While PV and electrolysis components dominate the cost of conventional PV generated hydrogen, they do not dominate the cost of the STEP-generated hydrogen. The lower cost of STEP hydrogen is driven by residual distribution and gate costs.     

Catching the hydrogen train: economics-driven green hydrogen adoption potential in the United Arab Emirates

The establishment of a hydrogen economy for domestic use and energy exports is increasingly attractive to fossil fuel exporting countries. This paper quantifies the potential of green hydrogen in the United Arab Emirates, using an integrated adoption model based on global technoeconomic trends and local costs. We consider the impact of varying hydrogen, oil, natural gas, and carbon prices on the economics of green H₂ adoption. In our Business-As-Usual (BAU) scenario, we observe economic viability in UAE industries between 2032 and 2038 at H₂ prices between $0.95/kg and $1.35/kg based on electrolyzer cost assumptions, solar forecasts and learning rates. We also note rapid scale-up to large export-oriented production capacities across our scenarios. However, if cost reductions slow or gas prices return to historical lows, additional interventions such as carbon pricing would be required to fully decarbonize in alignment with the 2050 net-zero target.     

A well to pump life cycle environmental impact assessment of some hydrogen production routes

In the present study, a comparative well to pump life cycle assessment is conducted on the hydrogen production routes of water electrolysis, biomass gasification, coal gasification, steam methane reforming, hydrogen production from ethanol and methanol. The CML 2001 impact assessment methodology is employed for assessment and comparison. Comparatively higher life cycle Carbon dioxide and Sulphur oxide emissions of 27.3 kg/kg H₂ and 50.0 g/kg H₂ respectively are determined for the water electrolysis hydrogen production route via U.S. electricity mix. In addition, the life cycle global warming potential of this route (28.6 kg CO_2eq/kg H₂) is found to be comparatively higher than other routes followed by coal gasification (23.7 kg CO_2eq/kg H₂)_. However, the ethanol based hydrogen production route is estimated to have comparatively higher life cycle emissions of nitrogen dioxide (19.6 g/kg H₂) and volatile organic compounds (10.3 g/kg H₂). Moreover, this route is determined to have a comparatively higher photochemical ozone creation potential of 0.0045 kg-ethene_eq/kg H₂ as well as eutrophication potential of 0.0043 kg PO_4eq/kg H_2. The results of this study are comparatively discussed to signify the importance of life cycle assessment in comparing the environmental sustainability of hydrogen production routes.     

Preliminary investigation on hydrogen-rich gas production by co-steam-reforming of biomass and crude glycerin

Hydrogen production from renewable biomass is of great interests. Co-steam-reforming of biomass and crude glycerin with the ratio of 1:1(w/w) was investigated in a fixed-bed gasifier aiming at improving biomass to hydrogen conversion, focusing on the effects of temperature, pressure, H₂O/C ratio and Ca/C ratio on producing gas composition. The results show that high temperature and low pressure favors hydrogen production. With temperature increasing from 650 to 825 °C, H₂ yield shows a linear increase from 0.053 mol/kg to 0.059 mol/kg. Both H₂ yield and its mole fraction increase obviously with the increasing H₂O/C ratio. No influence on gas production is found for Ca/C ratio > 1. The study reveals the optimum condition for producing hydrogen is: temperature of 700-750 °C, pressure of 0.1 MPa, H₂O/C ratio of 1.7-2.25 and Ca/C ratio of 1. Our experimental analysis shows co-steam-reforming of biomass and crude glycerin for hydrogen production is feasible and promising.     

Investigation of green hydrogen production and development of waste heat recovery system in biogas power plant for sustainable energy applications

In this study, biogas power production and green hydrogen potential as an energy carrier are evaluated from biomass. Integrating an Organic Rankine Cycle (ORC) to benefit from the waste exhaust gases is considered. The power obtained from the ORC is used to produce hydrogen by water electrolysis, eliminate the H₂S generated during the biogas production process and store the excess electricity. Thermodynamic and thermoeconomic analyses and optimization of the designed Combined Heat and Power (CHP) system for this purpose have been performed. The proposed study contains originality about the sustainability and efficiency of renewable energy resources. System design and analysis are performed with Engineering Equation Solver (EES) and Aspen Plus software. According to the results of thermodynamic analysis, the energy and exergy efficiency of the existing power plant is 28.69% and 25.15%. The new integrated system's energy, exergy efficiencies, and power capacity are calculated as 41.55%, 36.42%, and 5792 kW. The total hydrogen production from the system is 0.12412 kg/s. According to the results of the thermoeconomic analysis, the unit cost of the electricity produced in the existing power plant is 0.04323 $/kWh. The cost of electricity and hydrogen produced in the new proposed system is determined as 0.03922 $/kWh and 0.181 $/kg H₂, respectively.     

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).     

A study on the economic efficiency of hydrogen production from biomass residues in China

As part of Pilot Project of KIP of CAS, a feasibility study of hydrogen production system using biomass residues is conducted. This study is based on a process of oxygen-rich air gasification of biomass in a downdraft gasifier plus CO-shift. The capacity of this system is 6.4 t biomass/d. Applying this system, it is expected that an annual production of 480 billion N m³ H₂ will be generated for domestic supply in China. The capital cost of the plant used in this study is 1328$/(N m³/h) H₂ out, and product supply cost is 0.15$/N m³ H₂. The cost sensitivity analysis on this system tells that electricity and catalyst cost are the two most important factors to influence hydrogen production cost.