Finland

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.

Hydrogen has the potential to revolutionize how we power our lives from transportation to energy production. This study aims to compare the climate change impacts and the main factors affecting them for different categories of hydrogen production including grey hydrogen (SMR) blue hydrogen (SMR-CCS) turquoise hydrogen (TDM) and green hydrogen (PEM electrolysis). Grey hydrogen blue hydrogen and turquoise hydrogen which are derived from fossil sources are produced using natural gas and green hydrogen is produced from water and renewable electricity sources. When considering natural gas as a feedstock it is sourced from the pipeline route connected to Russia and through the liquefied natural gas (LNG) route from the USA. The life cycle assessment (LCA) result showed that grey hydrogen had the highest emissions with the LNG route showing higher emissions 13.9 kg CO2 eq. per kg H2 compared to the pipeline route 12.3 kg CO2 eq. per kg H2. Blue hydrogen had lower emissions due to the implementation of carbon capture technology (7.6 kg CO2 eq. per kg H2 for the pipeline route and 9.3 kg CO2 eq. per kg H2 for the LNG route) while turquoise hydrogen had the lowest emissions (6.1 kg CO2 eq. per kg H2 for the pipeline route and 8.3 kg CO2 eq. per kg H2 for the LNG route). The climate change impact showed a 12–25% increase for GWP20 compared to GWP100 for grey blue and turquoise hydrogen. The production of green hydrogen using wind energy resulted in the lowest emissions (0.6 kg CO2 eq. per kg H2) while solar energy resulted in higher emissions (2.5 kg CO2 eq. per kg H2). This article emphasizes the need to consider upstream emissions associated with natural gas and LNG extraction compression liquefaction transmission and regasification in assessing the sustainability of blue and turquoise hydrogen compared to green hydrogen.

To reduce carbon dioxide emissions from the steel industry efforts are made to introduce a steelmaking route based on hydrogen reduction of iron ore instead of the commonly used cokebased reduction in a blast furnace. Changing fundamental pieces of steelworks affects the functions of most every system unit involved and thus warrants the question of how such a transition could optimally take place over time and no rigorous attempts have until now been made to tackle this problem mathematically. This article presents a steel plant optimization model written as a mixed-integer non-linear programming problem where aging blast furnaces and basic oxygen furnaces could potentially be replaced with shaft furnaces and electric arc furnaces minimizing costs or emissions over a long-term time horizon to identify possible transition pathways. Example cases show how various parameters affect optimal investment pathways stressing the necessity of appropriate planning tools for analyzing diverse cases.

Nowadays integrating renewable energy sources (RESs) poses significant challenges due to the deterioration of performance indices especially in cold-climate unbalanced microgrids. Beyond network unbalance harsh conditions with low irradiance weak wind speeds and low temperatures necessitate hydrogen storage systems (HSSs) to address seasonal mismatches between RES generation and demand. This paper proposes a two-stage multi-timescale planning framework that integrates RESs plug-in electric vehicles (PEVs) battery energy storage systems (BESSs) seasonal HSSs and a dynamic demand response (DDR) program. In the short term BESSs are coordinated under slow and fast charging/discharging modes for responding to daily load shifting and peak shaving or sudden demand fluctuations. Smart converters with active/reactive power control are equipped with RES and BESS for local voltage regulation. Furthermore the proposed DDR program which combines load reduction and valley filling strategies enables consumer flexibility based on real-time market signals across seasonal variations. Seasonal HSSs are designed to store excess hydrogen produced from RESs for long-term use across different seasons. The proposed strategy is validated in two stages. The first stage guarantees multitimescale coordination of BESSs seasonal HSSs and the DDR. In turn the second stage optimally plans RESs BESSs and HSSs in a unified manner to reduce voltage unbalance and line congestion while maximizing microgrid RES hosting capacity. Simulation results for six interconnected microgrids demonstrate a 12.5% reduction in voltage unbalance 21% alleviation of line congestion and a 108% increase in hosting capacity highlighting the effectiveness of the proposed planning approach for unbalanced RES-rich microgrids.

Hydrogen jet fire occurs with high probability when hydrogen leaks from high-pressure equipment. The hydrogen jet fire is characterized by its high velocity and energy. Computational Fluid Dynamics (CFD) numerical analysis is a prominent way to predict the potential hazards associated with hydrogen jet fire. Validation of the CFD model is essential to ensure and quantify the accuracy of numerical results. This study focuses on the validation of the hydrogen jet fire model using Fire Dynamic Simulation (FDS). Hydrogen release is modeled using high-speed Lagrangian particles released from a virtual nozzle thus avoiding the modeling of the actual nozzle. The mesh size sensitivity analysis of the model is carried out in a container-size domain with 0.04m – 0.08m resolution of the jet. The model is validated by comparing gas temperatures and heat fluxes with test data. The promising results demonstrated that the model could predict the hazardous influence of the jet fire.

This study addresses challenges associated with hydrogen’s physio-chemical characteristics and the need for safety and public acceptance as a precursor to the emerging hydrogen economy. It highlights the gap in existing literature regarding lessons learned from events in the green hydrogen production value chain. The study aims to use the documented lessons learned from previous hydrogen-related events to assist in enhancing safety measures and to guide stakeholders on how to avoid and mitigate future hydrogen-related events. Given the potential catastrophic consequences robust safety systems are essential for hydrogen economy development. The work underscores the importance of human and operational factors as root causes of these events. The paper recommends establishing a specialized hydrogen-related event database to support risk assessment and risk mitigation thus catering to the growing hydrogen industry’s needs and facilitating quick access to critical information for stakeholders in the private and public sectors.

This paper introduces a value chain design for transportation fuels and a respective business case taking into account hybrid PV-Wind power plants electrolysis and hydrogen-to-liquids (H2tL) based on hourly resolved full load hours (FLh). The value chain is based on renewable electricity (RE) converted by power-to-liquids (PtL) facilities into synthetic fuels mainly diesel. Results show that the proposed RE-diesel value chains are competitive for crude oil prices within a minimum price range of about 79 - 135 USD/barrel (0.44 – 0.75 €/l of diesel production cost) depending on the chosen specific value chain and assumptions for cost of capital available oxygen sales and CO2 emission costs. A sensitivity analysis indicates that the RE-PtL value chain needs to be located at the best complementing solar and wind sites in the world combined with a de-risking strategy and a special focus on mid to long-term electrolyser and H2tL efficiency improvements. The substitution of fossil fuels by hybrid PV-Wind power plants could create a PV-wind market potential in the order of terawatts.

Multi-energy microgrids (MEMGs) with green hydrogen have attracted significant research attention for their benefits such as energy efficiency improvement carbon emission reduction as well as line congestion alleviation. However the complexities of multi-energy networks coupled with diverse uncertainties may threaten MEMG’s operation. In this paper a data-driven methodology is proposed to achieve effective MEMG operation considering the green hydrogen technique and congestion management. First a detailed MEMG modelling approach is developed coupling with electricity green hydrogen natural gas and thermal flows. Different from conventional MEMG models hydrogen-enriched compressed natural gas (HCNG) models and weatherdependent power flow are thoroughly considered in the modelling. Meanwhile the power flow congestion problem is also formulated in the MEMG operation which could be mitigated through HCNG integration. Based on the proposed MEMG model a reinforcement learning-based method is designed to obtain the optimal solution of MEMG operation. To ensure the solution’s safety a soft actor-critic (SAC) algorithm is applied and modified by leveraging the Lagrangian relaxation and safety layer scheme. In the end case studies are conducted and presented to validate the effectiveness of the proposed method.

Green hydrogen will play a key role in the transition to a carbon-neutral energy system. This study addresses the challenge of supplying baseload green hydrogen through an integrated off-grid alkaline water electrolyzer (AWE) plant wind and solar photovoltaic (PV) power a battery energy storage system (BESS) and a hydrogen storage system based on salt and rock cavern geologies. The capacities of the components and the hydrogen storage size are optimized simultaneously with the control of the AWE plant to minimize the levelized cost of hydrogen (LCOH2) of the gas supplied. The operation of the system is simulated over 30 years with a 15 min time resolution considering degradation operating expenses and component replacements. Power generation data collected from a wind farm and a solar PV installation both located in southeastern Finland are used for system simulation. A sensitivity analysis exploring different hydrogen demand rates discount rates and installation years is conducted for both systems considering rock and salt caverns providing the optimal configuration for each case. It is found that for the price scenario of the year 2025 for a combined 100 MW AWE and compressor the optimal hydrogen demand rate is 12 kg/min with an LCOH2 of 3.14 e/kg and 2.77 e/kg in systems including rock and salt caverns respectively.

To inject green hydrogen (H2) into the existing natural gas (NG) infrastructure is one way to decarbonize the European energy system. However asset readiness is necessary to be successful. Preliminary analysis and experimental results about the compatibility of hydrogen and natural gas mixtures (H2NG) with the actual gas grids make the scientific community confident about the feasibility. Nevertheless specific technical questions need more research. A significant topic of debate is the impact of H2NG mixtures on the performance of state-ofthe-art fiscal measuring devices which are essential for accurate billing. Identifying and addressing any potential degradation in their metrological performance due to H2NG is critical for decision-making. However the literature lacks data about the gas meters’ technologies currently installed in the NG grids such as a comprehensive overview of their readiness at different concentrations while data are fragmented among different sources. This paper addresses these gaps by analyzing the main characteristics and categorizing more than 20000 gas meters installed in THOTH2 project partners’ grids and by summarizing the performance of traditional technologies with H2NG mixtures and pure H2 based on literature review operators experience and manufacturers knowledge. Based on these insights recommendations are given to stakeholders on overcoming the identified barriers to facilitate a smooth transition.

The decarbonization of the maritime sector represents a priority in the energy policy agendas of the majority of Countries worldwide and the International Maritime Organization (IMO) has recently revised its strategy aiming for an ambitious zero-emissions scenario by 2050. In these regards there is a broad consensus on hydrogen as one of the most promising clean energy vectors for maritime transport and a key towards that goal. However to date an international regulatory framework for the use of hydrogen on-board of ships is absent this posing a severe limitation to the adoption of hydrogen technologies in this sector. To cope with this issue this paper presents a preliminary gap assessment analysis for the International Code of Safety for Ship Using Gases or other Low-flashpoint Fuels (IGF Code) with relation to hydrogen as a fuel. The analysis is structured according to the IGF Code chapters and a bottom-up approach is followed to review the code content and assess its relevance to hydrogen. The risks related to hydrogen are accounted for in assessing the gaps and providing a first level set of recommendations for IGF Code updates. By this means this work settles the basis for further research over the identified gaps towards the identification of a final set of recommendations for the IGF Code update.

To address the global climate crisis maritime logistics are undergoing a transition away from fossil-based energy sources. The transition is envisaged to be both green (involving renewables) and digital (involving various kinds of digitalization). Much of the hope rests on the new hydrogen economy involving the build-up of infrastructure for hydrogen-derived alternative fuels such as methanol and ammonia. Indeed the new hydrogen economy is often portrayed as set to revolutionize maritime transport. The hope behind the hype reflects a belief in the performativity of hypes: some technological phenomenon will eventually materialise in innovation and business practices. In this paper we critically analyse the current hydrogen hype in the field of Finnish maritime logistics as a paradigmatic case of performative techno-optimism. Based on causal network analysis and thematic analysis of expert interviews and workshop data we argue that the phenomenon of performative techno-optimism is more nuanced than hitherto presented in the related literature. We showcase a variety of stances along a spectrum ranging from radical optimism to radical pessimism. Furthermore our causal network analysis indicates that the current green and digital transition of maritime transport is caught in a systemic catch-22: transitioning to alternative fuels in maritime logistics faces a lock-in of between overly cautious demand for alternative fuels leading to overly cautious investment in supply which only secures the modest demand. Finally our thematic analysis of techno-optimist stances suggests the following two major ways out of the systemic dilemma: large-scale technological innovations and global regulatory solutions.