Publications

The rapidly increasing production volume of clean hydrogen creates challenges for transport infrastructure. This study improves understanding of hydrogen transport options in Europe and provides more detailed analysis on the prospects for hydrogen transport in Finland. Previous studies and ongoing pipeline projects were reviewed to identify potential and barriers to hydrogen transport. A fatigue life assessment tool was built because material challenges have been one of the main concerns of hydrogen transportation. Many European countries aim at utilizing existing gas infrastructure for hydrogen. Conducted studies and pilot facilities have provided promising results. Hydrogen reduces the fatigue life of the pipeline but existing pipelines can be used for hydrogen if pressure variation is maintained at a reasonable level and the maximum operation pressure is limited. Moreover the use of existing pipelines can reduce hydrogen transport costs but the suitability of every pipeline for hydrogen must be analyzed and several issues such as leakage leakage detection effects of hydrogen on pipeline assets and end users corrosion maintenance and metering of gas flow must be considered. The development of hydrogen transport will vary within countries depending on the structure of the existing gas infrastructure and on the future hydrogen use profile.

Hydrogen is becoming increasingly popular as a clean secure and affordable energy source for the future. This study develops an approach for designing a PV–battery–electrolyzer–fuel cell energy system that utilizes hydrogen as a long-term storage medium and battery as a short-term storage medium. The system is designed to supply load demand primarily through direct electricity generation in the summer and indirect electricity generation through hydrogen in the winter. The sizing of system components is based on the direct electricity and indirect hydrogen demand with a key input parameter being the load sizing factor which determines the extent to which hydrogen is used to meet seasonal imbalance. Technical and financial indicators are used to assess the performance of the designed system. Simulation results indicate that the energy system can effectively balance the seasonal variation of renewable generation and load demand with the use of hydrogen. Additionally guidelines for achieving self-sufficiency and system sustainability for providing enough power in the following years are provided to determine the appropriate component size. The sensitivity analysis indicates that the energy system can achieve self-sufficiency and system sustainability with a proper load sizing factor from a technical perspective. From an economic perspective the levelized cost of energy is relatively high because of the high costs of hydrogen-related components at this moment. However it has great economic potential for future self-sufficient energy systems with the maturity of hydrogen technologies.

This paper studies fast fueling of gaseous hydrogen into large hydrogen (H2) tanks suitable for maritime applications. Three modeling methods have been developed and evaluated: (1) Two-dimensional computational fluid dynamic (CFD) modeling (2) One-dimensional wall discretized modeling and (3) Zero-dimensional modeling. A detailed 2D CFD simulation of a small H2-tank was performed and validated with data from literature and then used to simulate a large H2-tank. Results from the 2D-model show non-uniform temperature distribution inside the large tank but not in the small H2-tank. The 1D-model can predict the mean temperature in small H2-tanks but not the inhomogeneous temperature field in large H2-tanks. The 0D-model is suitable as a screening tool to obtain rough estimates. Results from the modeling of the large H2-tank show that the heat transfer to the wall during fast filling is inhibited by heat conduction in the wall which leads to an unacceptably high mean hydrogen temperature.

Land-based gas turbines (GTs) are continuous-flow engines that run with permanent flames once started and at stationary pressure temperature and flows at stabilized load. Combustors operate without any moving parts and their substantial air excess enables complete combustion. These features provide significant space for designing efficient and versatile combustion systems. In particular as heavy-duty gas turbines have moderate compression ratios and ample stall margins they can burn not only high- and medium-BTU fuels but also low-BTU ones. As a result these machines have gained remarkable fuel flexibility. Dry Low Emissions combustors which were initially confined to burning standard natural gas have been gradually adapted to an increasing number of alternative gaseous fuels. The paper first delivers essential technical considerations that underlie this important fuel portfolio. It then reviews the spectrum of alternative GT fuels which currently extends from lean gases (coal bed coke oven blast furnace gases . . . ) to rich refinery streams (LPG olefins) and from volatile liquids (naphtha) to heavy hydrocarbons. This “fuel diet” also includes biogenic products (biogas biodiesel and ethanol) and especially blended and pure hydrogen the fuel of the future. The paper also outlines how historically land-based GTs have gradually gained new fuel territories thanks to continuous engineering work lab testing experience extrapolation and validation on the field.

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.

In view of the European Union’s strategy on hydrogen for decarbonization and buildings’ decarbonization targets the use of hydrogen in buildings is expected in the future. Backup power in buildings is usually provided with diesel generators (DGs). In this study the use of a hydrogen fuel cell (HFC) power supply backup system is studied. Its operation is compared to a DG and a techno-economic analysis of the latter’s replacement with an HFC is conducted by calculating relevant key performance indicators (KPIs). The developed approach is presented in a case study on a school building in Greece. Based on the school’s electricity loads which are calculated with a dynamic energy simulation and power shortages scenarios the backup system’s characteristics are defined and the relevant KPIs are calculated. It was found that the HFC system can reduce the annual CO2 emissions by up to 400 kg and has a lower annual operation cost than a DG. However due to its high investment cost its levelized cost of electricity is higher and the replacement of an existing DG is unviable in the current market situation. The techno-economic study reveals that subsidies of around 58–89% are required to foster the deployment of HFC backup systems in buildings.

Alkaline electrolysis is already a proven technology on land with a high maturity level and good economic performance. However at sea little is known about its economic performance toward hydrogen production. Alkaline electrolysis units operate with purified water to split its molecules into hydrogen and oxygen. Purified water and especially that sourced from the sea has a variable cost that ultimately depends on its quality. However the impurities present in that purified water have a deleterious effect on the electrolyte of alkaline electrolysis units that cause them to drop their energy efficiency. This in turn implies a source of economic losses resulting from the cost of electricity. In addition at sea there are various options regarding the electrolyte management of which the cost depends on various factors. All these factors ultimately impact on the levelized cost of the produced hydrogen. This article aims to shed some light on the economic performance of alkaline electrolysis units operating under sea conditions highlighting the knowledge gaps in the literature and initiating a debate in the field.

With the increasing concern about global energy crisis and environmental pollution the integrated renewable energy system has gradually become one of the most important ways to achieve energy transition. In the context of the rapid development of hydrogen energy industry the proportion of hydrogen energy in the energy system has gradually increased. The conversion between various energy sources has also become more complicated which poses challenges to the planning and construction of park-level integrated energy systems (PIES). To solve this problem we propose a bi-level planning model for an integrated energy system with hydrogen energy considering multi-stage investment and carbon trading mechanism. First the mathematical models of each energy source and energy storage in the park are established respectively and the independent operation of the equipment is analyzed. Second considering the operation state of multi-energy coordination a bi-level planning optimization model is established. The upper level is the capacity configuration model considering the variable installation time of energy facilities while the lower level is the operation optimization model considering several typical daily operations. Third considering the coupling relationship between upper and lower models the bi-level model is transformed into a solvable single-level mixed integer linear programming (MILP) model by using Karush–Kuhn–Tucker (KKT) condition and big-M method. Finally the proposed model and solution methods are verified by comprehensive case studies. Simulation results show that the proposed model can reduce the operational cost and carbon emission of PIES in the planning horizon and provide insights for the multi-stage investment of PIES.

This paper presents a study that focuses on alleviating the impacts of grid outages in Ethiopia. To deal with grid outages most industrial customers utilize backup diesel generators (DG) which are environmentally unfriendly and economically not viable. Grid integration of hybrid renewable energy systems (HRES) might be a possible solution to enhance grid reliability and reduce environmental and economic impacts of utilizing DG. In this study an optimization of grid integrated HRES is carried out for different dispatch and control strategies. The optimal power supply option is determined by performing comparative analysis of the different configurations of grid integrated HRES. The result of the study shows that grid integrated HRES consisting of photovoltaic and wind turbine as renewable energy sources and battery and hydrogen as hybrid energy storage systems is found to be the optimal system to supply the load demand. From the hydrogen produced on-site the FC generator and FCEVs consume 143 620 kg/yr of hydrogen which is equivalent to 394 955 kg/yr gasoline fuel consumption. This corresponds to saving 1 184 865 kg/yr of CO2 emissions and 605 703 $/yr revenue. Besides this system yields 547 035.4 $/yr revenue by injecting excess electricity to the grid. The study clearly shows the economic and environmental viability of this new technology for implementation.

Islands face limitations in producing and transporting energy due to their geographical constraints. To address this issue the ROBINSON project funded by the EU aims to create a flexible self-sufficient and environmentally friendly energy system that can be used on isolated islands. The feasibility of renewable electrification and heating system decarbonization of Eigerøy in Norway is described in this article. A mixed-integer linear programming framework was used for modelling. The optimization method is designed to be versatile and adaptable to suit individual scenarios with a flexible and modular formulation that can accommodate boundary conditions specific to each case. Onshore and offshore wind farms and utility-scale photovoltaic (PV) were considered to generate renewable electricity. Each option was found to be feasible under certain conditions. The heating system composed of a biomass gasifier a combined heat and power system with a gas boiler as backup unit was also analyzed. Parameters were identified in which the combination of all three thermal units represented the best system option. In addition the possibility of green hydrogen production based on the excess electricity from each scenario was evaluated.