Finland

The capacity of each component in an off-grid water electrolyzer hydrogen production plant integrated with solar photovoltaics and a battery energy storage system represents a significant factor affecting the viability and reliability of the system. This paper describes a novel method that optimizes simultaneously the component capacities and finite-state machine based control of the system to minimize the cost of green hydrogen production. The components and control in the system are referenced to a proton exchange membrane water electrolyzer stack with a fixed nominal power of 4.5 kW. The end results are thus scalable by changing the nominal power of the electrolyzer. Simulations are carried out based on data collected from a residential solar photovoltaic installation with 300 s time resolution. Optimization of the system is performed with particle swarm optimization algorithm. A sensitivity analysis performed over the prices of the different components reveals that the price of the water electrolyzer has the greatest impact on the green hydrogen production cost. It is found that the price of the battery has to be below 0.3 e/Wh to become a feasible solution as overnight energy storage.

The competitiveness of biofuels may be increased by integrating biomass gasification plants with electrolysis units which generate hydrogen to be combined with carbon-rich syngas. This option allows increasing the yield of the final product by retaining a higher amount of biogenic carbon and improving the resilience of the energy sector by favoring electric grid services and sector coupling. This article illustrates a techno-economic comparative analysis of three flexible power and biomass to methanol plants based on different gasification technologies: direct gasification indirect gasification and sorptionenhanced gasification. The design and operational criteria of each plant are conceived to operate both without green hydrogen addition (baseline mode) and with hydrogen addition (enhanced mode) following an intermittent use of the electrolysis system which is turned on when the electricity price allows an economically viable hydrogen production. The methanol production plants include a gasification section syngas cleaning conditioning and compression section methanol synthesis and purification and heat recovery steam cycle to be flexibly operated. Due to the high oxygen demand in the gasifier the direct gasification-based plant obtains a great advantage to be operated between a minimum load to satisfy the oxygen demand at high electricity prices and a maximum load to maximize methanol production at low electricity prices. This allows avoiding large oxygen storages with significant benefits for Capex and safety issues. The analysis reports specific fixed-capital investments between 1823 and 2048 €/kW of methanol output in the enhanced operation and LCOFs between 29.7 and 31.7 €/GJLHV. Economic advantages may be derived from a decrease in the electrolysis capital investment especially for the direct gasification-based plants which employ the greatest sized electrolyzer. Methanol breakeven selling prices range between 545 and 582 €/t with the 2019 reference Denmark electricity price curve and between 484 and 535 €/t with an assumed modified electricity price curve of a future energy mix with increased penetration of intermittent renewables.

Interest in more sustainable energy sources has increased rapidly in the maritime industry and ambitious goals have been set for decreasing ship emissions. All industry stakeholders have reacted to this with different approaches including the optimisation of ship power plants the development of new energy-improving sub-systems for existing solutions or the design of entirely novel power plant concepts employing alternative fuels. This paper assesses the feasibility of different ship energy sources for an icebreaking Arctic research ship. To that end possible energy sources are assessed based on fuel infrastructure availability and operational endurance criteria in the operational area of interest. Promising alternatives are analysed further using the evidence-based Strengths Weaknesses Opportunities and Threats (SWOT) method. Then a more thorough investigation with respect to the required fuel tank space life cycle cost and CO2 emissions is implemented. The results demonstrate that marine diesel oil (MDO) is currently still the most convenient solution due to the space operational range and endurance limitations although it is possible to use liquefied natural gas (LNG) and methanol if the ship’s arrangement is radically redesigned which will also lead to reduced emissions and life cycle costs. The use of liquefied hydrogen as the only energy solution for the considered vessel was excluded from the potential options due to low volumetric energy density and high life cycle and capital costs. Even if it is used with MDO for the investigated ship the reduction in CO2 emissions will not be as significant as for LNG and methanol at a much higher capital and lifecycle cost. The advantage of the proposed approach is that unrealistic alternatives are eliminated in a systematic manner before proceeding to detailed techno-economic analysis facilitating the decision-making and investigation of various options in a more holistic manner.

The road transport sector is one of the major contributors to greenhouse gas emissions as it still largely relies on traditional powertrain solutions. While some progress has been made in the passenger car sector with the diffusion of battery electric vehicles heavy-duty transport remains predominantly dependent on diesel internal combustion engines. This research aims to evaluate and compare three potential solutions for the decarbonisation of heavy-duty freight transport from an economic perspective: Battery Electric Trucks (BETs) Fuel Cell Electric Trucks (FCETs) and Hydrogen-fuelled Internal Combustion Engine Trucks (H2ICETs). The study focuses on the Finnish market and road network where affordable and low-carbon electricity creates an ideal environment for the development of alternative powertrain vehicles. The analysis employs the Total Cost of Ownership (TCO) method which allows for a comprehensive assessment of all cost components associated with the vehicles throughout their entire lifecycle encompassing both initial expenses and operational costs. Among the several factors affecting the results the impact of the three powertrain technologies on the admissible payloads has been taken into account. The study specifically focuses on the costs directly incurred by the truck owner. Additionally to evaluate the cost effectiveness of the proposed powertrain technologies under different scenarios a sensitivity analysis on electricity and hydrogen prices is conducted. The outcomes of this study reveal that no single powertrain solution emerges as universally optimal as the most cost-effective choice depends strongly on the truck type and its use (i.e. daily mileage). For relatively small trucks (18 t) covering short driving distances (approximately 100 to 200 km/day) BETs prove to be the best solution due to their higher efficiency and lower vehicle costs compared to FCETs. Conversely for larger trucks (42 and 76 t) engaged in longer hauls (>300 km/day) H2ICETs exhibit larger cost benefits due to their lower vehicle costs among the three options under investigation. Finally for small trucks (18 t) travelling long distances (200 km/day or more) FCETs represent a competitive choice due to their high efficiency and costeffective energy storage system. Considering future advancements in FCETs and BETs in terms of improved performance and reduced investment cost the fuel cell-based solution is expected to emerge as the best option across various combinations of truck sizes and daily mileages.

Electrofuels including hydrogen methane and ammonia have been suggested as one pathway in achieving net-zero greenhouse gas energy systems. They can play a role in providing an energy storage and fuel or feedstock to hard-to-abate sectors. In future energy systems their role is often studied in case studies adhering to specific region. In this study we study their role by defining multiple archetypal energy systems which represent approximations of real systems in different regions. Comparing the role of electrofuels across the cost-optimized systems relying only on renewable energy in power generation we found that hydrogen was a significant energy vector in all systems with its annual quantity approaching the classic electricity demand. The role of renewable methane was very limited. Electrofuel storages were needed in all systems and their capacity was the highest in the northern Hemiboreal system. Absence of cavern storage potential did not hamper the significance of electrofuels but increased the role of ammonia and led to average 5.5 % systemic cost increase. Systems where reservoir hydropower was scarce or level of electricity consumption was high needed more fuel storages. The findings of this study can help for better understanding of what kind of storage and generation technologies will be most useful in future carbon-neutral systems in different types of regions.

Seasonal underground hydrogen storage (UHS) in porous media provides an as yet untested method for storing surplus renewable energy and balancing our energy demands. This study investigates the technical suitability for UHS in depleted hydrocarbon fields and one deep aquifer site in Taranaki Basin Aotearoa New Zealand. Prospective sites are assessed using a decision tree approach providing a “fast-track” method for identifying potential sites and a decision matrix approach for ranking optimal sites. Based on expert elicitation the most important factors to consider are storage capacity reservoir depth and parameters that affect hydrogen injectivity/withdrawal and containment. Results from both approaches suggest that Paleogene reservoirs from gas (or gas cap) fields provide the best option for demonstrating UHS in Aotearoa New Zealand and that the country’s projected 2050 hydrogen storage demand could be exceeded by developing one or two high ranking sites. Lower priority is assigned to heterolithic and typically finer grained labile and clay-rich Miocene oil reservoirs and to deep aquifers that have no proven hydrocarbon containment.

Defossilisation of the current fossil fuels dominated global energy system is one of the key goals in the upcoming decades to mitigate climate change. Sharp reduction in the costs of solar photovoltaics wind power and battery technologies enables a rapid transition of the power and some segments of the transport sectors to sustainable energy resources. However renewable electricity-based fuels and chemicals are required for the defossilisation of hard-to-abate segments of transport and industry. The global demand for carbon dioxide as raw material for the production of e-fuels and e-chemicals during a global energy transition to 100% renewable energy is analysed in this research. Carbon dioxide capture and utilisation potentials from key industrial point sources including cement mills pulp and paper mills and waste incinerators are evaluated. According to this study’s estimates the demand for carbon dioxide increases from 0.6 in 2030 to 6.1 gigatonnes in 2050. Key industrial point sources can potentially supply 2.1 gigatonnes of carbon dioxide and thus meet the majority of the demand in the 2030s. By 2050 however direct air capture is expected to supply the majority of the demand contributing 3.8 gigatonnes of carbon dioxide annually. Sustainable and unavoidable industrial point sources and direct air capture are vital technologies which may help the world to achieve ambitious climate goals.

Cruise ship decarbonisation was studied on a Mediterranean cruise profile. The analysis focused on ship energy flows fuel consumption carbon emissions ship CII and EEDI. A combination of technologies for reducing ship fuel consumption was simulated before introducing hydrogen fueled machinery for the ship. The studied technologies included ultrasound antifouling shore power battery hybrid machinery waste heat recovery and air lubrication. Their application on the selected operational profile led to combined fuel savings of 187%. When the same technologies were combined to a hydrogen machinery the ship total energy consumption compared to baseline was reduced by 25%. The cause of this was the synergies in the ship energy system such as ship auxiliary powers heat consumption and machinery efficiency. The proposed methodology of ship energy analysis is important step in starting to evaluate new fuels for ships and in preliminary technology screening prior to integrating them in the ship design.

Many industrial processes such as ammonia fuel or steel production require considerable amounts of fossil feedstocks contributing significantly to global greenhouse gas emissions. Some of these fossil feedstocks and processes can be decarbonised via Power-to-X (P2X) production concepts based on hydrogen (H2) requiring considerable amounts of renewable electricity. Creating hydrogen valleys (HV) may facilitate a cost-efficient H2 production feeding H2 to multiple customers and purposes. At a large scale these HVs will shift from price takers to price makers in the local electricity market strongly affecting investments in renewable electricity. This paper analysed the dynamic evolution of a HV up to GW-scale by adopting a stepwise approach to HV development in North Ostrobothnia Finland considering multiple H₂ end uses such as P2X fuel manufacturing including ammonia methanol liquefied methane and H2 for mobility. The analysis was conducted by employing a dynamic linear optimization model “SmartP2X” to minimize LCOH within the HV boundaries. The analysis predicts that with ex-factory sales prices that are equal to or higher than marginal costs for P2X fuels production a LCOH of 3.4–3.9 EUR/kgH2 could be reached. The LCOH slightly increased with the size of the HV due to a H2 transmission pipeline investment; omitting the pipeline cost the LCOH exhibited a decreasing trend. The produced H2 will generally meet the EU definitions for clean Renewable Fuel of Non-Biological Origin (RFNBO). The additional wind power required for the HV scenarios was up to 2.1–3.0 GW depending on the RFNBO-fuel sales price. This represents a fraction of the current investment plans in the North Ostrobothnia region. The results of this paper contribute to the discussion on the interplay between hydrogen ecosystems and the power market particularly in relation to power-intensive P2X processes.

The applications and need for large-scale long-duration electrical energy storage are growing as both the share of renewable energy in energy systems and the demand for flexibility increase. One potential application is the renewable hydrogen industry where temporal matching of renewable electricity generation and hydrogen production will be required in the future according to the new European Union regulations. In this paper a case study of electrical energy storage utilization in hydrogen production is conducted in the Nordic context with a high share of wind production. The storage is used in the hydrogen production process for temporal matching. The levelized cost of storage of three medium- to long-term storage technologies is assessed using an Excel-based model with four case approaches. In the first case approach the electrolyzer load is inflexible while the other approaches explore how the flexibility of the electrolyzer and the increase in renewable production capacity affect the size and cost of the storage. Electro-thermal energy storage based on sand as storage material presented the lowest levelized cost of storage (114-198 €/MWh) due to its low energy-related investment cost. However the results show that additional usage purposes for all examined storage technologies are required to avoid high investment costs. Additionally flexibility from the electrolyzer load and over-investing in renewable capacity is required. In conclusion storage should not be the only component providing flexibility in the studied system and it should be used to integrate multiple assets in the wider energy system to reach cost-effectiveness. This paper brings novelty by expanding on the storage technology options considered in previous literature and deepening the perspective of storage as a component in renewable hydrogen production. Future research should assess the effect of electricity prices and emissions allowance prices from the regulatory perspective which could further reduce the storage investment.