The decarbonisation of the Dutch power system cannot be accomplished by electrification alone. Although offshore wind power is to play a leading part in the future Dutch power system, long-term energy storage and hard-to-electrify energy consumers are in need of other energy carriers as well. Hydrogen gas is able to provide this system essential. For the production of green hydrogen gas, offshore wind is a promising option because it has a high capacity factor, relative to other sustainable energy technologies. Vice versa, hydrogen production can strengthen the business case of offshore wind as the average power price will decreases as a result of increasing power grid penetration from renewable energy power generators. Furthermore, the expansion of offshore wind in the Netherlands may lead to high cable costs with increasing distances to shore and onshore grid congestion. Hydrogen production can circumvent these problems while continuing the decarbonisation of the Dutch energy system. This study aims to determine the most profitable offshore hydrogen wind hub configuration for 2030 and 2040. To determine the optimal configuration, this thesis evaluates two main considerations. First, whether onshore or offshore electrolysis is more profitable. Second, whether a bidirectional or unidirectional grid connection may increase the profitability of respectively the onshore or offshore electrolysis configuration. For this evaluation, six configurations are examined that aim to represent the spectrum of possibilities on how a 12 GW hydrogen wind hub could be integrated in the energy system. These configurations vary in their positioning of the electrolyser (onshore/offshore), electrolyser capacity (11.5/9.5/5.6 GW) and grid connection capacities (0/2/6 GW). To compare the profitability of each configuration, this thesis evaluates their cost and revenues. The cost analysis is conducted through a literature study. The revenue analysis is performed by modeling the hydrogen production of each configuration for a given weather year in order to establish the hydrogen production cost. Additionally, for the grid-connect configurations, the power revenues are estimated using the Plexos power market model. This evaluation reveals whether the grid connection configurations can profit from both volatile power prices (sell \& buy) and a stable hydrogen price. All analyses use a screenshot approach on the year 2030 and 2040. Thus, annual cost and annual revenues are expressed for these years. In the cost analysis, cost variations are taken into account for the HVDC-components, offshore installation factor and WACC. Also, different distances to shore of the wind hub are taken into account (i.e. 88, 209 \& 330 km). For the power revenue analysis, the power system state data on 2030 and 2040 are used from the 'Ten-year network development plan' of ENTSOG/ENTSO-E, which span over more than ten years. From this data, the 'Global ambition' scenario and the weather year 1982 are used. This 'Global ambition' scenario represents a pathway of centralised innovation. In order to establish future power prices, the Plexos power market modelling tool is used to solve an hourly Unit Commitment Economic Dispatch problem by Mixed Integer Linear Programming. This nodal model consist of 59 EU- and surrounding non-EU countries. Additionally, a hydrogen market price is established in which the feedstock sector is assumed to be price-setter as an international hydrogen market is non-existent for now. In 2030, onshore electrolysis is more economical than offshore electrolysis as the electrolyser investment cost and accompanying offshore installation cost are high. The dedicated hydrogen configurations and the grid connection configurations have equal hydrogen production cost; 3.10 €/kg. In 2040, onshore and offshore electrolysis are equally economical up to about 200 km from shore. At larger distances, offshore electrolysis is more economical. Uncertainty in the system cost and differences in system cost between onshore and offshore electrolysis and per distance to shore are found to mainly result from uncertainty in the offshore installation factor, the cost of HVDC component and the WACC. The bidirectional 2 GW grid connection of onshore electrolysis and the unidirectional 2 GW grid connection of offshore electrolysis both result in the same hydrogen production cost as the dedicated hydrogen configuration; 2.50 €/kg. Overall, considering the operation of a hydrogen wind hub through 2030 and 2040 within one life cycle, there is no significant advantage of grid connection as the break-even prices of the 2 GW grid connected configurations and the dedicated hydrogen configurations are similar. Nevertheless, a 2 GW grid connection might provide risk spreading for the investor and a lower total hydrogen subsidy amount to achieve a profitable configuration. The larger grid connection of 6 GW is definitely less profitable operating through 2030 and 2040. When assuming the future technological maturity of turbines with DC output, efficient electronic power converters (DC-DC) and electrochemical compression combined with optimistic cost reduction of the electrolyser, the hydrogen production cost decrease to 2.65 €/kg in 2030 and 2.30 €/kg in 2040. Given these production cost, the 2 GW grid connected configuration and dedicated hydrogen configuration become competitive with grey hydrogen production in 2040 based on natural gas price of 7.31 €/GJ and 80 €/tCO\textsubscript{2}. An important note is that the current CO\textsubscript{2} price already surpassed the price trajectory for 2030 as used in this study. Variations in turbine cost will affect the production cost as well. However, in this thesis the emphasis is more on the comparison of the configurations than on the absolute level of the production cost. For different turbine cost, the comparison remains similar as the turbine capacity is equal for all configurations. Therefore, a fixed cost reduction is used for the wind turbines. Future techno-economic development of in-turbine electrolysis will determine whether decentralised electrolysis becomes beneficial over centralised electrolysis. It is recommended that the North Sea offshore wind infrastructural planning must take into account the broader potential of 60 GW Dutch North sea wind in 2050 (+ 450 GW onshore in Europe) and the forthcoming power grid challenges in all North sea countries. For specifically offshore wind-based hydrogen production, electrolyser capacity planning towards and beyond 2050 should be considered as the economies of scale of hydrogen pipelines might favour offshore electrolysis as the overall cost might be lower. Future onshore electrolysis provides possible symbiosis with solar PV, nuclear \& natural gas power generation and industry thereby limiting grid congestion and increasing the electrolyser load factor. Future modelling efforts that aim to value the benefits of combined hydrogen and power production should focus on different demand-side-response and power-to-gas capacities as both affect the volatility of the power prices. Also, alternative trajectories of the CO\textsubscript{2} price and energy system scenarios should be incorporated in the power price modelling. Furthermore, the power market model can be improved by including the recovery of long run marginal cost, strategic bidding behaviour and sector coupling of power and heat.

On the island of Goeree-Overflakkee, local and regional municipalities, businesses and education and knowledge institutions are pursuing a pioneering project called H2GO. The H2GO project is a project that researches the role green hydrogen can fulfill in our society through eight different scalable sub-projects. One of these projects is making the local fishing fleet of Goeree-Overflakkee CO2 neutral. Due to technical limitations, adaptations to make the fishing vessels CO2 neutral will not be possible for the coming years. For the shorter term, the project is therefore also looking for different ways to make the fleet more sustainable. A substantial polluting factor for this type of fishing vessels is the refrigeration unit, used to cool the freshly caught fish. A technology, called thermally driven metal hydride cooling, shows potential to provide an alternative for the current refrigeration system. In this thesis, the technical feasibility is explored of replacing the conventional ice slurry machines that fishing vessels currently employ with this technology. In order to do this, a literature review on different types of metal hydrides and the state-of-the-art on metal hydride cooling systems has been conducted. After this, a numerical model is presented and validated with an equivalent model and experiments. The model shows good similarity regarding overall system performance compared to the experiments. Finally, a metal hydride cooling system, containing another low temperature metal hydride is proposed that is capable of achieving a cooling capacity of 16 kW at a cooling temperature of -10 to -20 ◦C. This leads to the conclusion that the system has some efficiency drawbacks, but that the metal hydride system is technically feasible for use in the fishing vessels at Goeree-Overflakkee. This, in return, reveals a significant opportunity for employing this new technology to lower the environmental impact of the Goeree-Overflakkee fishing fleet.

Hydrogen, as a fuel, will soon play a key role in helping economies transition to more sustainable practices. Having always garnered attention due to its non-polluting nature, the costs associated with its production have stood in the way of it being more widely used in society. Since the cost of clean energy to produce hydrogen is one of the main reasons the current price is so high, locations with a high renewable potential are being looked at as a means to drive production prices down, benefiting from higher capacity factors at these locations. With near ideal offshore wind resources, the North Sea is one such location. This thesis aims to explore the potential of this resource to deliver future hydrogen and to a larger extent, EU TFEC demand in 2050. The main research question therefore asks: “What is the future potential of P2H in the North Sea , from a spatially explicit, techno-economic perspective” The analysis first explored the cost of different production configurations, mainly comparing the production of hydrogen onshore (via electricity transmitted over HVDC- high voltage direct current cables), offshore (after transmitting to shore via a pipeline) and in offshore wind turbines (again, after transmission to shore in a network of pipelines). The analysis then used GIS data to analyze the production potential in the North Sea by taking exclusion zones into account. A mapping model was therefore developed to estimate theoretical and practical yield potentials in steps of 5 years, until 2050. Supply curves and maps were then generated to paint a picture of P2H supply pathways in the North Sea. One of the designated research goals in the thesis was to offer a comparative analysis between the three P2H configuration types, mentioned above. The results show a clear preference in favor of the In Turbine configuration which is followed by the offshore configuration and finally the onshore type. The hierarchy was mainly influenced by the conversion chain losses in the three configurations, with the In Turbine configuration having the lowest losses, followed by the offshore and then the onshore types. Model results show a higher sensitivity to sea depth than transmission distance to shore for all three configuration types up till the fixed to floating transition point, after which the sensitivity to depth is reduced. The In Turbine and offshore configurations were however, predictably less sensitive to transmission distance than the onshore configuration since H2 pipeline investment costs for large delivery capacities are almost negligible in comparison to HVDC electricity transportation. Fishing zones, shipping zones, nature conservation zones and current wind farms were considered as exclusionary constraints in the model. This was done to test the influence of maritime spatial planning on both yield and costs in the North Sea. The total restricted and unrestricted yield potentials from the in-turbine configuration with the least losses were 15.8 and 24.18 EJ respectively. This represents 47% and 72% of EU total final energy consumption (TFEC) in 2050. The (Power to Hydrogen) P2H supply pathways were finally compared to a conventional HVDC (Power to Electricity) P2E supply routes for the North Sea and interestingly, a few offshore and all in-turbine P2H locations become cheaper than P2E in the North Sea area between 2040-2050. This begs the question: ‘What is the best/most cost effective supply pathway that leads us to a decarbonized energy system by 2050’. The results in this study indicate that careful consideration needs to be given to the best possible production pathways, particularly, in the North Sea.