Hydrogen Price Research Articles

Optimization of an energy district for fuel cell electric vehicles: Cost scenarios of a real case study on a waste and recycling fleet

This paper analyses the planning and operation of an energy district that aims to integrate a hydrogen supply chain for feeding vehicles based on fuel cell technology. A model of an energy district and an optimization algorithm based on the economic parameters are presented and validated leveraging an existing energy district, simulating several scenarios depending on different economic conditions and technical parameters. The model of the energy district evaluates energy balances, distinguishing hydrogen and electrical energy flows; the districts can include an FCEV fleet, electrical loads, energy generators, storage system and an electrolyser for producing hydrogen from the green energy surplus produced in the district as well as drawing energy from the power distribution network. The algorithm, based on MILP, is used for optimizing the flows in the district; indeed, it evaluates all the technical and economic constraints at a certain timestamp and provides optimal scheduling of the energy units. Model and algorithm have been used to evaluate different scenarios that were identified by varying the economic parameters (i.e., prices of electrical energy and hydrogen) as well as district design (i.e., upgrading sizes of the generators and electrolysers). Energy district parameters have been identified exploiting real data collected in an existing district located in Terni (Italy) owned by the local multi-utility ASM Terni S.p.A. It already includes a fleet for waste management, PV plants, office buildings and warehouses. Through parameters combination, 1125 OPEX and 729 CAPEX simulated scenarios have been evaluated and reported; each scenario assesses the daily variation of variables' economic trends covering the timeframe from 2030 to 2050. Results of simulations highlight the most convenient economic contexts as well as the envisioned amount of expenditures for adopting FCEV in the presented district or similar ones. For the case study, the forecasted cost of the hydrogen district, including FCEVs, is fully comparable to current costs, resulting in some cases even cheaper.

The role of hydrogen in German residential buildings

Fossil-fueled heating in the building sector is responsible for 16 % of Germany's total CO2 emissions. Options for the climate-neutral heating of buildings include renewable electricity or renewable hydrogen. In this paper, we conduct a bottom-up study to investigate the role of hydrogen in the climate-neutral energy supply of ten selected residential buildings in comparison to electricity-based systems. Based on a demand simulation and linear optimization of the supply system, sensitivity analyses identify the threshold values of the hydrogen price for the use of hydrogen technologies (hydrogen boilers or fuel cells) in building energy systems and make the quantities of hydrogen consumed visible.The results specify the first installations of hydrogen-operated fuel cells in multi-family houses if the hydrogen price reaches 0.17€/kWhH2 in 2050 at an electricity price of 0.31 €/kWhel. Generally, for different building types and electricity supply prices, it indicates that the use of hydrogen becomes economically-viable if the price of hydrogen supply is in the range of 34–61 % of the price of the electricity supply per kWh and below.For the case of green hydrogen obtained using renewable electricity, it is highly questionable whether hydrogen supply will be that much cheaper than direct electricity supply, making its economical use in buildings uncertain.

Integrated Process for Producing Glycolic Acid from Carbon Dioxide Capture Coupling Green Hydrogen

A novel process path is proposed to produce glycolic acid (GA) from CO2 as the feedstock, including CO2 capture, power-to-hydrogen, CO2 hydrogenation to methanol, methanol oxidation to formaldehyde, and formaldehyde carbonylation units. The bottlenecks are discussed from the perspectives of carbon utilization, CO2 emissions, total site energy integration, and techno-economic analysis. The carbon utilization ratio of the process is 82.5%, and the CO2 capture unit has the largest percentage of discharge in carbon utilization. Among the indirect emissions of each unit, the CO2 hydrogenation to methanol has the largest proportion of indirect carbon emissions, followed by the formaldehyde carbonylation to glycolic acid and the CO2 capture. After total site energy integration, the utility consumption is 1102.89 MW for cold utility, 409.67 MW for heat utility, and 45.98 MW for power. The CO2 hydrogenation to methanol makes the largest contribution to utility consumption due to the multi-stage compression of raw hydrogen and the distillation of crude methanol. The unit production cost is 834.75 $/t-GA; CO2 hydrogenation to methanol accounts for the largest proportion, at 70.8% of the total production cost. The total production cost of the unit depends on the price of hydrogen due to the currently high renewable energy cost. This study focuses on the capture and conversion of CO2 emitted from coal-fired power plants, which provides a path to a feasible low-carbon and clean use of CO2 resources.

Techno-economic evaluation of solar-driven ceria thermochemical water-splitting for hydrogen production in a fluidized bed reactor

Thermochemical water splitting (TCWS) is an attractive and promising approach for hydrogen fuel production to replace fossil fuels and address climate change. The novel approach used in this study is the indirect irradiation of the ceria particle with solar-heated nitrogen in a fluidized bed reactor which improved the ceria thermo-reduction and increased hydrogen yield. The TCWS plant featured additional units for oxygen co-production, and excess heat recovery to generate electricity and reduce the saleable hydrogen price. Two fluidized bed reactors for ceria thermo-reduction and oxidation using steam were modelled in Aspen Plus for hydrogen production at a 70% capacity factor. A photovoltaic (PV)-battery module in addition to the solar parabolic dish collector (PDC) was then used to deliver operation-round electricity supply and drive mechanical and control systems, reducing overall plant energy cost. Three minimum selling prices of hydrogen were considered based on the achievable products of the TCWS plant: (i) pricing based on no co-products, (ii) pricing including oxygen revenue, and (iii) pricing including oxygen and electricity revenue. The TCWS plant achieved a minimum selling price (MSP) of 3.92 USD/kg H2 (including oxygen and electricity revenue) at a 10% discount rate which is the lowest for solar-driven TCWS hydrogen compared with other similar studies. Sensitivity analyses showed that discount rate, steam Rankine cycle, power block, cost of ceria and hydrogen storage, and price of oxygen, respectively, had the highest impact on the MSP of the TCWS hydrogen plant. The switch value analysis (SVA) was used to determine the potential of achieving the global target hydrogen price of 2 USD/kg based on a single parameter assessment. The TCWS plant proposed in this work provides a promising approach toward achieving future hydrogen prices below 2 USD/kg when a lower discount rate of 5% is utilised. It was established that the choice and size of concentrated solar power (CSP) technology integration, co-generation, and heat recovery are critical to the system efficiency and economic viability of a solar-driven TCWS hydrogen production. This work demonstrated the use of ceria as a metal oxide feed suitable for solar TCWS hydrogen production with a promising economic potential for a global target price of less than 2 USD/kg H2 based on the choice of process-CSP configuration.

Economic competitiveness of compact steam methane reforming technology for on-site hydrogen supply: A Foshan case study

On-site hydrogen production through steam-methane reforming (SMR) from city gas or natural gas is believed to be a cost-effective way for hydrogen-based infrastructure due to high cost of hydrogen transportation. In recent years, there have been a lot of on-site hydrogen fueling stations under design or construction in China. This study introduces current developments and technology prospects of skid-mounted SMR hydrogen generator. Also, technical solutions and economic analysis are discussed based on China's first on-site hydrogen fueling station project in Foshan. The cost of hydrogen product from skid-mounted SMR hydrogen generator is about 23 CNY/kg with 3.24 CNY/Nm3 natural gas. If hydrogen price is 60 CNY/kg, IRR of on-site hydrogen fueling station project reaches to 10.8%. While natural gas price fall to 2.3 CNY/Nm3, the hydrogen cost can be reduced to 18 CNY/kg, and IRR can be raised to 13.1%. The conclusion is that skid-mounted SMR technology has matured and is developing towards more compact and intelligent design, and will be a promising way for hydrogen fueling infrastructures in near future.

System-friendly process design: Optimizing blue hydrogen production for future energy systems

While the effects of ongoing cost reductions in renewables, batteries, and electrolyzers on future energy systems have been extensively investigated, the effects of significant advances in CO2 capture and storage (CCS) technologies have received much less attention. This research gap is addressed via a long-term (2050) energy system model loosely based on Germany, yielding four main findings. First, CCS-enabled pathways offer the greatest benefits in the hydrogen sector, where hydrogen prices can be reduced by two-thirds relative to a scenario without CCS. Second, advanced blue hydrogen technologies can reduce total system costs by 12% and enable negative CO2 emissions due to higher efficiencies and CO2 capture ratios. Third, co-gasification of coal and biomass emerged as an important enabler of these promising results, allowing efficient exploitation of limited biomass resources to achieve negative emissions and limit the dependence on imported natural gas. Finally, CCS decarbonization pathways can practically and economically incorporate substantial shares of renewable energy to reduce fossil fuel dependence. Such diversification of primary energy inputs increases system resilience to the broad range of socio-techno-economic challenges facing the energy transition. In conclusion, balanced blue-green pathways offer many benefits and deserve serious consideration in the global decarbonization effort.

Time-Decoupling Layered Optimization for Energy and Transportation Systems under Dynamic Hydrogen Pricing

The growing popularity of renewable energy and hydrogen-powered vehicles (HVs) will facilitate the coordinated optimization of energy and transportation systems for economic and environmental benefits. However, little research attention has been paid to dynamic hydrogen pricing and its impact on the optimal performance of energy and transportation systems. To reduce the dependency on centralized controllers and protect information privacy, a time-decoupling layered optimization strategy is put forward to realize the low-carbon and economic operation of energy and transportation systems under dynamic hydrogen pricing. First, a dynamic hydrogen pricing mechanism was formulated on the basis of the share of renewable power in the energy supply and introduced into the optimization of distributed energy stations (DESs), which will promote hydrogen production using renewable power and minimize the DES construction and operation cost. On the basis of the dynamic hydrogen price optimized by DESs and the traffic conditions on roads, the raised user-centric routing optimization method can select a minimum cost route for HVs to purchase fuels from a DES with low-cost and/or low-carbon hydrogen. Finally, the effectiveness of the proposed optimization strategy was verified by simulations.

Capturing CO2 from the atmosphere: Design and analysis of a large-scale DAC facility

Direct air carbon capture (DAC) technologies can substantially lower the CO2 concentrations in the atmosphere by enabling negative emissions. This study shows in detail the design of the DAC plant at industrial scale and provides insights on its performance in terms of process economic and CO2 emissions count. The proposed DAC plant is optimized to capture CO2 directly from the atmospheric air, employing a sensitivity analysis to find the influence of operation and design parameters on the total cost. Absorption using sodium hydroxide as chemisorbent is utilized with a capture rate of 0.7. Industrially mature common process units are considered to achieve a design that is relevant in the near future. An initial base case design indicates a carbon cost of 244 $/ton-CO2 with the operating expenses comprising 84% of the total cost. Then, two scenarios are proposed to enhance the process performance: heat integration and use of renewable energy. Through the heat integration, the carbon ratio (CO2 captured / CO2 emitted) improves from a value of 2.7 for the base case to 3.73, meaning less CO2 is emitted per captured amount due to lower fuel consumption. The resulting cost goes down to 125 $/ton-CO2, with two additional heat exchangers added to the network. Furthermore, renewable scenario is considered where a parallel electrolysis stage feeds the process hydrogen fuel and oxygen required for combustion in the calciner. This scenario indicates that higher operating costs are incurred due to the expensive green fuel. Finally, a profitability analysis is performed to establish the feasibility for further processing to methanol in a Power-to-X facility. The estimations indicate that the hydrogen price has to go down by 46.3% in order to break-even.

Net Energy Balance Assessment for a Coupled Photoelectrochemical Water Splitting Device

Photoelectrochemical (PEC) water splitting is a promising renewable energy technology to produce green hydrogen for the future fossil-fuel-free society. Over the past decade, research on PEC water splitting devices has achieved significant improvements in the demonstrated solar-to-hydrogen (STH) efficiencies. The improved efficiencies have led to the development of large-scale devices [1,2] and the coupling of hydrogen production with the synthesis of valuable chemicals [3,4]. The co-generation approach offers a potential route towards achieving a levelized cost of hydrogen (LCOH) that is competitive with the current market price of hydrogen and increases the overall economic feasibility of the PEC technology.This study evaluates the potential of co-producing hydrogen and methyl succinic acid (MSA) by coupling the hydrogenation of itaconic acid (IA) into MSA inside a PEC water splitting reactor. We used a PEC device that uses BiVO4 as the top absorber and a silicon solar cell as the bottom absorber, as reported previously [1,5]. To address the feasibility of this approach, a net energy balance assessment is conducted, and the results are compared with the benchmark values for conventional MSA production. We follow the Techno-Economic Assessment & Life Cycle Assessment Guidelines for CO2 Utilization (Version 1.1) which provides a specific protocol for multi-functional PEC devices [6]. Life cycle inventory (LCI) values from the literature and Ecoinvent database [7] are used to construct the target scenarios in Simapro v9.2.0.Our results show that the energy demand of our PEC device is ca. 3800 MJ/m2, and the most energy intensive components are the photoelectrode (~70%) and the Nafion membrane (8%). Under the base case condition (i.e., STH = 5%, device longevity = 10 years) and when H2 is the only product, a negative net energy balance of ca. -160 MJ/m2/year is obtained. However, with a coupled hydrogenation reaction, a zero net energy balance (i.e., energy breakeven) can already be achieved when only 2% of the produced H2 molecules are converted into MSA (see red circle in Fig. 1a). Figure 1b shows the cumulative energy demand to produce one kg of MSA under a more optimistic scenario, in which the H2-to-MSA conversion efficiency is 0.4. Under this condition, the net energy production is ca. 3500 MJ/m2/year, which translates to a cumulative energy demand of ca. 13 MJ/kg of MSA (see red circle in Fig. 1b). This is much lower compared to MSA produced using conventional hydrogenation methods (i.e., ~90 MJ/kg MSA), which underlines the attractiveness of the coupled PEC approach.Finally, we analyze the potential for further improvement of the net energy balance. We explore possibilities of replacing device components (e.g., photoelectrode, membrane) and assess the impact to the net energy balance of the device. The result of this optimization study will be presented, and the most effective strategy will be outlined. Keywords : water splitting, (photo)electrochemistry, net energy assessment, coupled catalysis, hydrogenation References [1] Ahmet IY, Ma Y, Jang JW, Henschel T, Stannowski B, Lopes T, Vilanova A, Mendes A, Abdi FF, van De Krol R. Demonstration of a 50 cm2 BiVO4 tandem photoelectrochemical-photovoltaic water splitting device. Sustain Energy Fuels. 2019;3(9):2366–79.[2] Tolod KR, Hernández S, Russo N. Recent advances in the BiVO4 photocatalyst for sun-driven water oxidation: Top-performing photoanodes and scale-up challenges. Catalysts. 2017;7(1).[3] Mei B, Mul G, Seger B. Beyond Water Splitting: Efficiencies of Photo-Electrochemical Devices Producing Hydrogen and Valuable Oxidation Products. Adv Sustain Syst. 2017;1(1–2).[4] Luo H, Barrio J, Sunny N, Li A, Steier L, Shah N, Stephens IEL, Titirici MM. Progress and Perspectives in Photo- and Electrochemical-Oxidation of Biomass for Sustainable Chemicals and Hydrogen Production. Adv Energy Mater. 2021;11(43).[5] Abdi FF, Han L, Smets AHM, Zeman M, Dam B, van De Krol R. Efficient solar water splitting by enhanced charge separation in a bismuth vanadate-silicon tandem photoelectrode. Nat Commun. 2013;4:1–7. Available from: http://dx.doi.org/10.1038/ncomms3195[6] Zimmermann AW, Wang Y, Wunderlich J, Buchner GA, Schomäcker R, Müller LJ, Langhorst T, Kätelhön A, Bachmann M, Sternberg A, Bardow A, Armstrong K, Michailos S, McCord S, Zaragoza AV, Styring P, Marxen A, Naims H, Cremonese L, Strunge T, Olfe-Kräutlein B, Faber G, Mangin C, Mason F, Stokes G, Williams E, Sick V. Techno-Economic Assessment & Life Cycle Assessment Guidelines for CO2 Utilization (Version 1.1). 2020;(September).[7] Jungbluth N, Stucki M FR. Photovoltaics. In Sachbilanzen von Energiesystemen: Grundlagen für den ökologischen Vergleich von Energiesystemen und den Einbezug von Energiesystemen in Ökobilanzen für die Schweiz. ecoinvent report No. 6-XII. Swiss Cent Life Cycle Invent Dübendorf, CH. 2009;16–69(6–XII). Figure 1

A framework for the replacement analysis of a hydrogen-based polymer electrolyte membrane fuel cell technology on board ships: A step towards decarbonization in the maritime sector

Maritime transport is one of the largest greenhouse gas emitting sectors of the global economy, responsible for around 1 GtCO2eq every year. To comply with the reduction of carbon dioxide emissions, the research is devoted introducing low and zero-carbon fuels and innovative propulsion technologies. In this context, hydrogen fuel cell powertrains can play a crucial role due to their high energy and environmental performances. In this paper, a techno-economic feasibility analysis for replacing an 8.3 MW diesel engine with a polymer electrolyte membrane fuel cell system is performed for a chemical tanker ship. For this purpose, a detailed method, that aims to estimate the volume and mass of the fuel cell system as well as of the hydrogen storage technologies, is developed. Three on board hydrogen storage technologies are considered: i) compressed hydrogen, ii) liquid hydrogen, iii) metal hydrides. Results highlight that the fuel cell-based powertrain is characterized by 60% less volume and 56% less mass compared to the diesel engine. As far as the hydrogen storage technologies are concerned, all solutions present significantly lower volumetric and gravimetric energy densities and therefore, additional volume and mass are required in comparison with diesel fuel configuration. These results involve a reduction of the total cargo capacity to comply with tanker ship physical constraints. The cargo should be reduced by 1.3%-1.1% for compressed hydrogen (at 350 bar and 700 bar, respectively), 0.1% for liquid hydrogen, and 9% for metal hydrides. Finally, the economic assessment in terms of Operational Expenditures, based upon the predicted hydrogen price reduction as well as the diesel price increase, in different cost scenarios (2020–2050), are evaluated. Results show that the competitiveness of the hydrogen solution with a retail price of 4 $/kg can be achieved by considering an incentive for the avoided CO2 equal to 112 $/tons.

Technical, economic and environmental issues related to electrolysers capacity targets according to the Italian Hydrogen Strategy: A critical analysis

The European Hydrogen Strategy set an electrolysers' capacity target of 40 GW by 2030. This will lead to a sudden expansion of the electrolyser industry across Europe and the unit cost of electrolyser production will steeply decrease. The purpose of the present work is to integrate the learning curve approach with the national energy and economic planning, taking the Italian Hydrogen Strategy as a case study. Different learning curves and different roadmaps for the electrolysers' installation have been combined in order to model scenarios for predicting progressive fall in the electrolysers’ CAPEX. The investment needed to implement the strategy ranges between 1.5 and 3.3 G€ and depends mainly on the learning curve scenario. The Levelized Cost of Hydrogen has been calculated by changing different boundary conditions. Moreover, an incentive scheme has been proposed by comparing the green hydrogen cost to the blue and grey ones. Under the hypothesis of a fully-blended hydrogen use in the gas grid, a potential CO2 reduction up to 8.4 MtonCO2 over the decade can be accomplished. The main barrier to the economic competitiveness of Power to Gas systems is the still too high price of renewable electricity. It will be optimistic to obtain hydrogen prices lower than 2.44 €/kgH2 in Italy by 2030. Nevertheless, the deployment of the Hydrogen Valleys, where both production and consumption coexist, can reduce the carbon avoidance cost. Finally, it has been demonstrated that the failure to achieve the European targets is associated with higher hydrogen production costs and higher decarbonisation costs.

Cost of green hydrogen: Limitations of production from a stand-alone photovoltaic system

The aim of this work is to analyse the price of renewable hydrogen production in a stand-alone photovoltaic plant. The energy studied herein is generated in a photovoltaic plant. Two dependent parameters that directly affect the price of hydrogen are analysed in detail: the price of the electricity needed to carry out its production process, and the utilisation rate of the connected electrolyser. To this end, a photovoltaic plant is dimensioned with the help of the PVsyst simulator, by means of which the hourly generation curves are obtained. A variable power electrolyser is employed to study its performance according to these photovoltaic production curves. Furthermore, the system is studied by introducing batteries capable of storing the energy left over during the day and of supplying the electrolyser when the photovoltaic power is insufficient. The selling prices calculated in the various scenarios in terms of efficiency and electricity cost are calculated. The significance of a combined analysis of these two parameters and their real impact on the final price of hydrogen is also analysed. This article aims to analyse the price of green hydrogen produced through an isolated photovoltaic system. When the hourly production is evaluated, differences are found with respect to global production that justify the importance of the variables analysed herein, which could not be determined in any other way. The behaviour of isolated production and its effects are discussed.

Concurrent 20. Presentation for: Collocated offshore wind-hydrogen

Presented on Wednesday 18 May: Session 20 The hydrogen industry in Australia is in its infancy with most projects at this stage supported either by State Governments or through the funding arms of the Federal Government. The market is rapidly developing and interest in hydrogen has grown exponentially over the past few years. Governments in Australia and many countries around the world have set decarbonisation targets and it is expected that Hydrogen will play a major role in fulfilling these commitments. Largely driven by policy announcements and commitments, several hydrogen projects are currently in development in Australia and globally. Current forecast data indicates over 200 GW of electrolyser capacity are either planned for deployment or under construction. While industry moves forward with deployment-scale projects, incumbent fuels occupy a healthy competitive position. For example, in Western Australia natural gas prices are around $6/GJ and are set to remain stable into the foreseeable future, largely due to Western Australia’s domestic gas reservation policy. However, the impact of volatile oil prices on domestic natural gas remains to be seen. Although potential green hydrogen projects are mostly in early stages, increased opportunities for partnerships on the supply side or joint venture arrangements with energy producers and demand side off-takers, will accelerate these projects achieving feasibility. However, in achieving target hydrogen prices, the barriers remain significant. One such barrier, is the cost of renewable electricity and one such solution could be collocated offshore wind-hydrogen systems. By nature, offshore wind is an intermittent energy source. Hydrogen could be used as a means of storing renewable energy for electricity balancing, and as a dedicated source for large-scale hydrogen production. Hard-to-abate sectors remain a significant challenge as we transition to net-zero. Hydrogen may be used to de-carbonise hard-to-abate sectors as many stakeholders see offshore wind as the primary partner for hydrogen production. This paper discusses collocated wind-hydrogen systems as a potential pathway for offshore wind deployment and commercial hydrogen production. To access the presentation click the link on the right. To read the full paper click here

Evaluating the current perceived cost of ownership for buses and trucks in China

Decarbonizing commercial vehicles, including buses, trucks, and special purpose vehicles, is essential for China to achieve its carbon neutrality target by 2060. However, understanding the adoption barriers of alternative fuel technologies for commercial vehicles has largely been limited to the total cost of ownership approach that mainly considers tangible costs. This study proposes a perceived cost of ownership (PCO) model, which monetizes both tangible and implicit costs, including charging annoyance for buses and trucks by size and classification under different use scenarios. In the case study for China's current bus and truck market, the PCO of alternative fuel technologies, such as battery electric vehicles (BEVs) and fuel cell electric vehicles (FCEVs) are 27%–129% and 31%–86% higher than the most economically competitive powertrains – the compressed natural/liquefied petroleum gas technology and hybrid electric technology. BEVs could be cost-effective in the mini/midsize bus segment or in the daily short-distance driving scenario, and FCEVs could firstly be deployed in cities with a low hydrogen price. Though the implicit costs caused by range anxiety and charging annoyance account for at least 27% of BEV's PCO, making BEV uncompetitive, the battery swapping technique could reduce the implicit cost and overall cash outflow for BEV owners.

Technical and Economic Analysis of Fuel Cells for Forklift Applications.

This study compared the life cycle cost (LCC) of LiFePO4 battery, proton exchange membrane fuel cell (PEMFC), and direct methanol fuel cell (DMFC) as the main power source of electric forklifts. The battery showed the lowest LCC over 10 years ($14,935) among the three power sources, thanks to the significant price reduction in recent years. The fuel cost accounted for more than 70% of the total LCC of PEMFC ($36,682) when the hydrogen price was $8/kg. The LCC of DMFC ($41,819) with the current performance and catalyst loading (0.2 W/cm2, 6 mgPGM/cm2) was 12% higher than the LCC of PEMFC ($36,682). The LCC of DMFC ($25,050) will be 28.9% lower than that of PEMFC if both PEMFC and DMFC reach the target performance and catalyst loading set by the U.S. Department of Energy (1 W/cm2, 0.125 mgPGM/cm2 for PEMFC and 0.3 W/cm2, 3 mgPGM/cm2 for DMFC). The smaller fleet size will significantly increase the LCC of PEMFC due to the high cost of hydrogen fueling and storage infrastructure. For forklift users with less than 50 units, which account for 80% of forklift users, DMFC will be even more cost-effective due to the significantly lower cost of methanol infrastructure.

Hydrogen production from landfill biogas: Profitability analysis of a real case study

Hydrogen is not only considered as a cornerstone within renewable energy portfolio but it is also a key enabler for CO2 valorisation being a central resource for industrial decarbonization. This work evaluates the profitability of hydrogen production via combined biogas reforming and water–gas shift reaction, based on a real case scenario for landfill biogas plant in Seville (Spain). A techno-economic model was developed based on a process model and the discounted cash-flow method. A biogas flow of 700 m3/h (input given by the landfill biogas plant) was used as plant size and the analysis was carried out for two different cases: (1) use of already available energy sources at the industrial plant, and (2) solar energy generation to power the process. The economic outputs obtained showed that under the current circumstances, this hydrogen production route is not profitable. The main reason is the relatively low current hydrogen prices which comes from fossil fuels. A revenues analysis indicates that hydrogen from biogas selling prices between 2.9 and 5.7 €/kg would be needed to reach profitability, which are considerably higher than the current hydrogen cost (1.7 €/kg). A subsidy scheme is suggested to improve the competitiveness of this hydrogen production process in the short-medium term. A cost analysis is also performed, revealing that electricity prices and investment costs have a high impact on the total share (23–40% and 8–22%, respectively). Other potential costs reduction such as catalyst, labour and manteinance & overhead are also evaluated, showing that cutting-down production costs is mandatory to unlock the potential of hydrogen generation from biogas. Our work showcases the techno-economic challenge that green energy policies face in the path toward sustainable societies.

Collocated offshore wind-hydrogen

The hydrogen industry in Australia is in its infancy with most projects at this stage supported either by State Governments or through the funding arms of the Federal Government. The market is rapidly developing and interest in hydrogen has grown exponentially over the past few years. Governments in Australia and many countries around the world have set decarbonisation targets and it is expected that Hydrogen will play a major role in fulfilling these commitments. Largely driven by policy announcements and commitments, several hydrogen projects are currently in development in Australia and globally. Current forecast data indicates over 200 GW of electrolyser capacity are either planned for deployment or under construction. While industry moves forward with deployment-scale projects, incumbent fuels occupy a healthy competitive position. For example, in Western Australia natural gas prices are around $6/GJ and are set to remain stable into the foreseeable future, largely due to Western Australia’s domestic gas reservation policy. However, the impact of volatile oil prices on domestic natural gas remains to be seen. Although potential green hydrogen projects are mostly in early stages, increased opportunities for partnerships on the supply side or joint venture arrangements with energy producers and demand side off-takers, will accelerate these projects achieving feasibility. However, in achieving target hydrogen prices, the barriers remain significant. One such barrier, is the cost of renewable electricity and one such solution could be collocated offshore wind-hydrogen systems. By nature, offshore wind is an intermittent energy source. Hydrogen could be used as a means of storing renewable energy for electricity balancing, and as a dedicated source for large-scale hydrogen production. Hard-to-abate sectors remain a significant challenge as we transition to net-zero. Hydrogen may be used to de-carbonise hard-to-abate sectors as many stakeholders see offshore wind as the primary partner for hydrogen production. This paper discusses collocated wind-hydrogen systems as a potential pathway for offshore wind deployment and commercial hydrogen production.

Optimal scheduling strategy of electricity‐heat‐hydrogen integrated energy system under different operating modes

With the increasing penetration level of renewable energy in the integrated energy system (IES), water electrolysis for hydrogen production (WEHP) technology has become an effective solution to increase the capacity of renewable energy utilization. Therefore, this paper proposes to take WEHP and hydrogen fuel cell (HFC) as flexible resources to participate in the optimal scheduling of IES under grid-connected/off-grid operation mode. Firstly, focusing on the production, storage and utilization of hydrogen energy, a unified operation model of WEHP module is built by analyzing the differences of the three WEHP technologies. And then, “co-generation” model of HFC, the residual capacity and transportation cost model of hydrogen storage device (HSD) are built. Second, by analyzing the uncertainty of light intensity and wind speed, a prediction error correction method is proposed to improve the prediction data accuracy of renewable energy power generation. Third, taking the lowest daily operation cost as the objective function, the optimal scheduling model of electricity-heat-hydrogen integrated energy system under grid-connected/off-grid operation mode is constructed. On this basis, the operation scheduling model of electricity-heat-hydrogen integrated energy system is transformed into a mixed integer linear model by piecewise linearization method, and the model is solved by CPLEX solver. Finally, an example is given to verify the rationality of the proposed scheduling model in the grid-connected/off-grid operation mode. On one hand, reasonable optimal scheduling of multiple WEHP combination is helpful to reduce the daily operation cost of IES. On the other hand, by correcting the prediction data deviation of renewable energy power generation, the equipment output of electricity-heat-hydrogen integrated energy system can be more reasonable, which is helpful to reduce the daily operation cost and improve the operation reliability. The effects of sensitive factors such as the penetration level of renewable energy, the relative fluctuation of electricity price and hydrogen price on the operation cost of optimal scheduling scheme are further analyzed, which provides a theoretical reference for the optimal scheduling of IES.

Reversible Power-to-Gas systems for energy conversion and storage

In the transition to decarbonized energy systems, Power-to-Gas (PtG) processes have the potential to connect the existing markets for electricity and hydrogen. Specifically, reversible PtG systems can convert electricity to hydrogen at times of ample power supply, yet they can also operate in the reverse direction to deliver electricity during times when power is relatively scarce. Here we develop a model for determining when reversible PtG systems are economically viable. We apply the model to the current market environment in both Germany and Texas and find that the reversibility feature of unitized regenerative fuel cells (solid oxide) makes them already cost-competitive at current hydrogen prices, provided the fluctuations in electricity prices are as pronounced as currently observed in Texas. We further project that, due to their inherent flexibility, reversible PtG systems would remain economically viable at substantially lower hydrogen prices in the future, provided recent technological trends continue over the coming decade.

To Adopt CCU Technology or Not? An Evolutionary Game between Local Governments and Coal-Fired Power Plants

Carbon dioxide capture and utilization (CCU) technology is a significant means by which China can achieve its ambitious carbon neutrality goal. It is necessary to explore the behavioral strategies of relevant companies in adopting CCU technology. In this paper, an evolutionary game model is established in order to analyze the interaction process and evolution direction of local governments and coal-fired power plants. We develop a replicator dynamic system and analyze the stability of the system under different conditions. Based on numerical simulation, we analyze the impact of key parameters on the strategies of stakeholders. The simulation results show that the unit prices of hydrogen and carbon dioxide derivatives have the most significant impact: when the unit price of hydrogen decreases to 15.9 RMB/kg or the unit price of carbon dioxide derivatives increases to 3.4 RMB/kg, the evolutionary stabilization strategy of the system changes and power plants shift to adopt CCU technology. The results of this paper suggest that local governments should provide relevant support policies and incentives for CCU technology deployment, as well as focusing on the synergistic development of CCU technology and renewable energy hydrogen production technology.