The transition to a decarbonised energy system requires a cost-effective, reliable and sustainable supply of renewable hydrogen, particularly for industrial hubs like the Port of Rotterdam. Multiple supply pathways could potentially contribute to such an energy system, with each pathway characterised by different advantages and disadvantages. Therefore, it is crucial to consider the system-wide implications of various supply pathways in order to make balanced trade-offs. This study functions as an exploratory investigation into the relations between various system designs and their characteristics. It examines techno-economic trade-offs between local hydrogen production using offshore wind-powered electrolysis and cracking of imported ammonia. Key performance indicators for system affordability, security of supply and sustainability are defined in order to facilitate a comparison of the two supply pathways. Employing a quantitative system model, these indicators are evaluated across different system configurations and demand scenarios for the Port of Rotterdam.
This research highlights the complexity of the energy transition and the absence of a universally optimal hydrogen supply pathway. Local electrolysis offers lower operational costs and import independence but requires high capital investment. In contrast, ammonia imports ensure a stable supply with lower local capital expenditure but depend on a resilient supply chain and are highly sensitive to ammonia costs. Local production demands more space but has a lower carbon footprint, while imports require less space at the import site but result in higher emissions. Additionally, electrolysis competes with power demand in Rotterdam’s harbour-industrial complex and hinterland, adding strain to their decarbonisation efforts. Local production also requires multiple salt caverns for storage due to constrained extraction rates, along with significant overcapacity in wind power and electrolysis to ensure supply continuity. Conversely, import-dependent systems rely on large ammonia shipments, and as hydrogen demand increases, local production reaches clear supply limits, leading to greater import reliance.
Future research should expand model applicability to different locations and supply chains, enhance key performance indicator scope, and incorporate stakeholder-driven decision-making frameworks. Ultimately, an effective hydrogen strategy must balance affordability, security of supply and sustainability, navigating the trade-offs between supply pathways and their broader implications for the energy transition.

The recent growth of the size of wind farms highlights the need for a deeper understanding of the mesoscale phenomena in a stably stratified atmosphere, such as atmospheric gravity waves, as the effect on the power generation can be significant. This thesis is a numerical study of the effect of wind farm layout on atmospheric gravity wave excitation and the resulting feedback on wind farm performance. Wind farms in this study have varying power density, streamwise or spanwise turbine spacing, aspect ratio, hub height, rotor diameter, shape, or orientation with respect to the freestream, and are situated in a conventionally neutral boundary layer in offshore conditions. Moreover, the wind farms can be horizontally or vertically staggered. To investigate the atmospheric gravity wave excitation, the effect of wind farm layout on the Froude number and inversion Froude number governing the internal and interfacial waves respectively is studied using several high-fidelity Large Eddy Simulations. Then, AGW wavelength and wind farm efficiency are parametrically studied using a fast reduced-order model. Specifically, the non-local efficiency is considered, which is a measure of the global blockage effect induced by the atmospheric gravity waves. It is found that the length scale used in the Froude number must be adjusted to the wind farm, and is dependent on the turbine spacing and farm shape. The inversion Froude number is based on the phase speed of the interfacial waves. It is suggested that the phase speed must be based on shallow-water theory and deep-water theory for small and large turbine spacings respectively. In other words, for small turbine spacings the wind farm acts as an entity, while for large turbine spacings, the farm acts as a collection of individual turbines. Finally, the streamwise and spanwise turbine spacing (and consequently the power density), and the aspect ratio primarily govern the non-local efficiency.

Although the percentage share of renewable energy in the global energy landscape is increasing rapidly and consistently breaking records for annual installation, there is still a need for tripling up of renewable energy capacity by 2030.The costs and prices of renewable energy are declining year by year, this is one of the key reasons for the shrinking of profits for renewable power developers(RPDs). Different strategies can be adopted by the renewable developers to increase revenues like improving financing costs, making multiple revenue streams for individual renewable assets etc. This creates an opportunity for P2X technologies, which are becoming popular due to their ability to facilitate the integration of different energy sectors like electricity and hard-to-abate sectors.

The design of a Hybrid power plant(HPP) is a complex problem that combines different assets to maximize the value of the power plant. Researchers at the Technical University of Denmark(DTU) are in the process of developing an open-source tool called HyDesign. According to desktop research, it was understood before HyDesign that no other open-source HPP sizing tool in the market could size and optimize the P2X designs. The purpose of this thesis study is to analyze how can RPDs improve their economic value by coupling with green ammonia(GNH3) production using HyDesign. The quantitative data is collected through the literature research and qualitative data is collected through attending various conferences and industrial events.This study models the most prominent and proven technology, which existed for more than a century now called the Haber Bosch process. Around 30+ industrial professionals were interviewed to entrepreneurially validate TUDelft's patented methodology of the Green Haber Bosch process. These interviews also provided reliable qualitative data for this study.

Since there is no reference, open-source green ammonia model, modelling checks were developed in this study to verify the functioning of the model and increase confidence in the reliability of the results. Site selection hypothesis was also made for hybrid renewable power plants. Evaluation results depict that the revenue of HPP+GNH3 is more than the HPP. However, various financial metrics were more for the HPP than HPP+GNH3, this is due to the huge technology costs of the GNH3 plants and the lack of economies of scale of such new plants.

Sensitivity analysis is performed in this study to analyse value addition and its source for improving various financial metrics of HPP+GNH3.Increasing RE resource capacity will improve financial metrics. Increasing electrolyser capacity or battery capacity will also improve a few of the financial metrics but not to the extent of increasing solar and wind capacities .

The study finds that building a large-scale HPP+GNH3 system is beneficial for RPDs and to society, which yields better financial benefits and more green ammonia production, which can be used in many hard-to-abate sectors.

Transitioning to renewable energy is essential for mitigating climate change and ensuring long-term energy security. Offshore wind farms offer a promising solution by harnessing strong and consistent wind resources at sea while minimizing land use conflicts. However, developing cost-effective offshore wind farm networks in the Baltic Sea—due to its unique geographical and environmental conditions—presents significant challenges.

This study addresses these challenges by developing a techno-economic optimization model to identify the most cost-effective offshore wind farm network configurations in the Baltic Sea Region. The model evaluates various configurations, including national (limited to domestic connections) and international networks (allowing cross-border connections), as well as single-stage (planning the entire network at once) and multi-stage (developing the network in phases) development plans. It optimizes the placement and capacities of wind farms, energy hubs, and export cables to minimize total system costs while adhering to technical and capacity constraints. Key geographical factors—such as water depth, ice cover, and proximity to ports—are integrated into the spatial data processing method to accurately assess infrastructure costs. The model also explores different network designs, including hub-and-spoke configurations that utilize energy hubs to consolidate and distribute power from multiple wind farms. The incorporation of single-stage and multi-stage optimization approaches allows for holistic and phased network developments, providing flexibility in planning and implementation.

The findings reveal that international networks are more cost-effective, totaling €28.5 billion, compared to national-only networks. This cost advantage is primarily due to enhanced flexibility in wind farm placement and power distribution. Specifically, national networks are 1.51% more expensive due to less optimized wind farm locations and localized grid overloading. Additionally, single-stage optimization outperforms multi-stage approaches by reducing costs by 1.71%, highlighting the benefits of a holistic planning strategy. While energy hubs can lower export cable costs by consolidating power transmission, they introduce higher overall expenses due to the additional costs associated with the hubs themselves. Specifically, the hub-and-spoke network is 1.15% more expensive than connecting wind farms directly to the onshore grid, suggesting a need for improved network optimization strategies. The study further identifies potential cost savings by positioning wind farms closer to shore in ice-covered areas when additional costs resulting from sea ice adaptation are minimized. This adjustment results in savings on export cables, as wind farms positioned closer to shore within these regions prove more economical due to their proximity and positioning in relatively shallow waters.

Ultimately, this research enhances the efficiency and economic viability of offshore wind infrastructure by optimizing design and cost estimation processes. The study provides actionable strategies for effective planning and investment in renewable energy infrastructure, offering valuable insights for policymakers and investors. By addressing the spatial, technical, and economic challenges associated with large-scale renewable energy deployment, the findings contribute significantly to academic knowledge and practical applications. The research emphasizes the importance of strategic long-term planning and international collaboration in developing sustainable and cost-efficient offshore wind energy infrastructures.

The ever-increasing need for improving the energy yield in wind farms while minimising fatigue loads has created the need for exploring new concepts in the wind sector. One is the notion of wind farms with turbines of varying hub heights, often called vertically- staggered (VS) configurations. Multiple studies have demonstrated the potential benefits of such arrangements, yet the effect of erecting larger-scale wind turbines into an already existing control wind farm has not been explored. This concept has gained remarkable industrial attention, particularly in the German onshore market, as it simplifies the grid connection and land acquisition, among other benefits. Understanding the implications of vertical staggering on turbine performance is therefore essential. In addition, fast and accurate modelling of the inflow conditions modulated by the atmospheric boundary layer (ABL), is crucial in predicting the flow properties and energy yield in wind farms. A novel steady-state, RANS-based inflow model has recently been proposed, yet it lacks detailed validation. The present research aims to assess the reliability of that model in large wind farm flow simulations and subsequently apply it to identify flow patterns and power production characteristics in VS configurations representative of the German onshore wind standards through numerical simulations. RANS modelling combined with the actuator disk method in the PyWakeEllipSys software was employed to demonstrate that despite the inability of that inflow model to yield accurate prediction of the turbulence intensity, the computed velocity field is in fair agreement with LES results in conventionally neutral boundary layer conditions. This is evident, especially for deeper ABL cases. This study argues for the complexity of the flow caused by the collocation of different turbine scales in the investigated VS configurations. It is also highlighted that rotor overlap negatively impacts the power production of both turbine types in VS wind farms. Hence, it is suggested that optimal performance in VS setups can be achieved by minimising the rotor vertical overlap through appropriate adjustments of the hub height.

The global energy consumption relies heavily on fossil fuels, which are projected to be depleted by 2050. This makes it necessary to optimize renewable sources such as wind energy. However, wind energy faces challenges due to the unpredictability and turbulence of wind patterns. Traditional wind turbines are limited by their reactive approach to turbulence. To address this issue, the integration of lidar technology in wind turbines provides a predictive advantage, enhancing the control of wind parks by offering insights into incoming wind
disturbances and improving feedback mechanisms. A new method for adjusting ground-based lidar turbulence intensity measurements is investigated in this master’s thesis, aiming to reduce measurement uncertainties. A novel turbulence intensity equation, developed using perturbation theory, serves as the foundation for an adjustment model that has been validated against existing standards. This adjustment method was tested in both virtual environments and on an actual wind site in the Netherlands, demonstrating its effectiveness in reducing uncertainties associated with lidar data. The study also utilizes the findings of a joint-industry project to refine data precision and compares various adjustment methods, ultimately showing that the perturbation-based adjustment improves the alignment of lidar measurements with traditional met mast data. Furthermore, the thesis explores the acceptance of lidar technology through a model based on the technology acceptance
framework, revealing that reducing measurement uncertainties positively impacts the perceived usefulness and adoption of lidar systems. This research aims to enhance the accuracy and reliability of wind energy assessments using ground-based lidar, paving the way for broader adoption in the industry. Future work should focus on expanding the dataset, incorporating advanced machine learning techniques, and extending the turbulence
intensity equation to accommodate complex terrains, further reducing uncertainties in lidar measurements.

This thesis presents a thorough exploration of mid-term storage strategies aimed at enhancing flexibility in hybrid offshore power systems that integrate wind and solar energy. A multi-criteria analysis was employed to identify the most suitable storage technologies for medium-term applications, resulting in the selection of Compressed Air Energy Storage (CAES), Lithium-ion batteries, and Lead-acid batteries as the top three candidates.
A specific study area, already equipped with offshore wind turbines, was selected for this research. Weather data were obtained and analyzed to reduce power mismatches and their associated costs. A multi-objective optimization approach was applied, focusing on minimizing the hourly loss of load and total capital costs associated with the hybrid renewable energy system.
In the base case scenario examined, which comprised 100% wind power, CAES emerged as the storage technology with the lowest total capital cost. However, by varying the proportions of offshore wind and solar energy, it was found that adjusting the mix to 80% offshore wind and 20% solar led to a significant reduction in the annual loss of load, thus reducing the total capital cost of the renewable hybrid system.

The demand for hydrogen is expected to increase significantly in the coming years due to its critical role in decarbonizing industrial processes. Offshore wind presents a viable energy source for powering electrolyzers, though it leads to intermittent production. While underground salt caverns are acknowledged as a promising solution for large-scale hydrogen storage, the technology still faces challenges regarding integration with fluctuating renewable energy sources.

This research, conducted in collaboration with Vattenfall, introduces a framework for modeling hydrogen storage in salt caverns, linked to hydrogen production from offshore wind farms. The framework features a technical model that addresses the thermodynamic changes within the cavern during hydrogen injection and withdrawal.

This new framework was expanded with an economic model and used to evaluate the optimal configuration for a standalone green hydrogen production and storage system. The analysis demonstrates that, up to a high security of supply threshold, increasing the storage capacity is the most effective strategy. Beyond this threshold, optimizing the configuration by increasing the number of stack changes or slightly enhancing the overall production capacity proves more beneficial than merely expanding storage. Additionally, the study explores two case study variations to assess the impacts of integrating flexible demand and line packing into the system.

The study concludes that the thermodynamic modeling of caverns significantly improves the accuracy of storage capacity estimations. It also highlights that optimal system design extends beyond adjusting storage capacity, necessitating comprehensive component optimization to strike a cost-effective balance for required supply securities. Furthermore, integrating demand flexibility enhances security of supply, enabling systems with high flexibility to achieve 100% security of supply with smaller storage capacities. However, the inclusion of line-packing does not improve economic performance. The insights underscore the need for strategic system design in hydrogen production and storage systems.

The decommissioning of offshore wind farms (OWFs) presents a significant challenge due to the environmental impact associated with the process, particularly in terms of greenhouse gas (GHG) emissions. This research aims to develop a model for quantifying and analysing the GHG emissions associated with large-scale OWF decommissioning. It examines key variables, including vessel types, decommissioning activities, transport strategies, and weather conditions, to assess their impact on total emissions.

Using a GHG inventory-based approach, the research applies both deterministic and probabilistic methods to assess emissions across various decommissioning scenarios. The model integrates operational logistics with emission factors, providing a flexible framework that adapts to different OWF projects. The research specifically examines the decommissioning of OWF Lincs Limited.

The results of this study highlight the potential for emissions reduction through optimised vessel strategies, transport methods, and campaign scheduling. While operational activities dominate emissions, the research underscores the importance of addressing external factors, such as weather and campaign timing, to minimise environmental impact. The developed model offers valuable insights to stakeholders aiming to implement effective GHG emission reduction strategies in future OWF decommissioning projects.

The field of floating offshore wind energy is rapidly advancing, offering a promising solution to
harness stronger and more consistent wind resources in deep-water regions, where conventional bottom-fixed turbines are not viable. Floating Offshore Wind Turbines (FOWTs), mounted on floating substructures, enable the deployment of wind turbines in deep offshore locations without the need for extensive foundations. This approach can significantly lower project costs, primarily by reducing substructure procurement expenses for comparable water depths. As a result, the installed capacity of FOWTs is projected to reach approximately 18.9 GW by 2030.

However, the design of cost-efficient FOWTs presents significant challenges due to the complex interactions between aerodynamic and hydrodynamic loads, as well as the coupling of various subsystems. One of the key hurdles is reducing the Levelized Cost of Energy (LCoE) to ensure the economic viability of Floating Offshore Wind Farms (FOWFs). Additionally, the flexibility of the floating substructure, which moves in six degrees of freedom (DOF), introduces complexities in the wake profile, such as enhanced wake meandering, which may affect the wake losses and the overall farm energy production.

Despite the potential impact of floater movements on energy yield, the specific effects on optimal wind farm layout design remain under-explored. Furthermore, the impact of these displacements on the LCoE needs to be examined to determine whether incorporating floater displacements into optimization frameworks leads to more accurate results or merely adds unnecessary complexity and computational cost.

This thesis evaluates the role of static floater displacements, specifically tilt and surge, in the optimization of FOWFs. Two distinct scenarios have been compared to assess how these displacements affect energy yield, the LCoE, and the optimal wind farm layout. The first scenario (Case A) disregards the static equilibrium displacements of the floating turbines, while the second scenario (Case B) incorporates these displacements into the analysis. To conduct the analysis, this thesis develops a wake modeling strategy focusing on wind-induced floater displacements, wherein the tilt and surge displacements of the floater are computed for each turbine using the PyWake framework, based on the effective wind speed experienced by its rotor. This wake modeling approach is then integrated into an OpenMDAO-based optimization framework to minimize the LCoE of the wind farm, which is used for the comparison between the two cases, to achieve the objectives of this study.

A case study of a 42-turbine sample wind farm in the North Sea, arranged in a rectangular gridded layout, was analyzed using the optimization framework. The results showed minimal differences in AEP, LCoE, and layout design between the scenarios that account for floater displacements (Case B) and those that neglect them (Case A). However, the computational time required for the optimization process increased by approximately fourfold for Case B. Case B resulted in a 0.25% reduction in AEP and a 0.162 €/MWh increase in LCoE, primarily due to changes in wake behavior caused by tilt and surge displacements. The optimal layout also shifted in orientation and spacing, with Case B yielding slightly lower power in the final configuration. Despite these effects, the overall impact on the LCoE was modest, suggesting that while incorporating floater displacements could potentially improve the accuracy of results for FOWFs, it might not justify the added computational costs for larger wind farms.

This research evaluates the economic feasibility of adding offshore solar farms (OSFs) to planned offshore wind farms (OWFs) in Europe, identifying feasible ranges of OSF and subsidy levels to reach economic feasible projects. Ultimately, this leads to conditions to reach economically feasible projects for adding OSFs to OWFs. Using shared infrastructure, such as the power export infrastructure (PEI), it reduces the need for offshore grid expansion and lowers initial OSF investment costs. This study addresses a gap by examining the economic feasibility of this integration, specifically through an economic added value (EAV) analysis, combined with various OSF cost scenarios through a net present value (NPV) assessment.

First, a literature review explores the economic and technical benefits, focusing on shared OWF infrastructure and identifying relevant stakeholders, when adding an OSF. A techno-economic model is developed to calculate the economic added value based on increased OSF revenues and the added value subsidy (AVS), which reflects cost savings from using shared infrastructure. Subsequently, the model is applied to two OWF case studies, a wind farm site in the Netherlands and wind farm site in Italy, where economic feasibility is evaluated.

This study concludes that the addition of an OSF to an OWF at the Italian site is economically feasible, when an optimistic OSF cost scenario is used. With less optimistic OSF cost scenarios, the the addition of an OSF to an OWF would require higher AVS from increasing shared infrastructure costs to become feasible. The integration of OSFs shows greater economic potential in southern Europe, particularly in regions such as Italy, where abundant solar resources and a lower wind potential contribute to a higher EAV per unit of OSF capacity because of substantial growth of the PEI capacity factor. Locations with lower initial OWF capacity factors, greater increases in additional OSF capacity factors, and high shared infrastructure costs lead to faster NPV improvement and reduced dependence on subsidies, representing economically favourable conditions for adding OSFs to OWFs.

The escalating demand for green hydrogen as a sustainable energy carrier has sparked significant interest in offshore wind-to-hydrogen systems, which hold the promise of expediting the transition towards renewable energy sources. The objective of this research is to provide insight in the techno-economic feasibility of semi-centralised electrolysis in an offshore wind farm. The semi-centralised offshore wind-to-hydrogen configuration will be compared with centralised and decentralised offshore wind-to-hydrogen to potentially reduce the levelised cost of hydrogen (LCOH) in future wind-to-hydrogen production designs.

This research was conducted in collaboration with Vattenfall, a leading player in offshore wind energy within Europe, who recognizes the potential of green hydrogen as a key driver in the ongoing energy transition. Vattenfall provided access to an in-house wind farm layout optimisation model to create optimised wind farm layouts as well as site specific data for the case study. This model and data allowed a narrowed focus on the hydrogen aspects of the wind-to-hydrogen configurations.

The technical examination explores crucial elements such as the conversion of wind energy into hydrogen through electrolysis, hydrogen transmission and variances in offshore substations and hydrogen wind turbines, to understand the technical differences between the different offshore wind-to-hydrogen configurations. Additionally, by analysing the hydrogen production process and comparing the scale of hydrogen production in offshore substations or hydrogen wind turbines, the study exhibits the technical feasibility of a wind-to-hydrogen farm with numerous semi-centralised monopile hydrogen substations in comparison with wind-to-hydrogen farms consisting of a single centralised jacket hydrogen substation or decentralised hydrogen wind turbines.

To enable a quantitative comparison of the different offshore wind-to-hydrogen setups in the economic analysis, the LCOH for each configuration was modelled. This process involved creating wind farm layouts and calculating the associated cost for a variety of offshore substations using Vattenfall's optimisation model. Moreover, aspects such as hydrogen production, the dimensions and cost of hydrogen pipelines, and the weight and expense of offshore hydrogen facilities were modelled to estimate the costs associated with hydrogen production and transmission for each configuration.

In the economic analysis, a detailed case study is conducted. The research investigates cost drivers, including wind farm expenses, hydrogen substation investments, and energy transmission infrastructure costs. The results reveal the economic viability of the semi-centralised configuration. The findings highlight the importance of considering monopile load capacity and substructure costs in determining the optimal number of hydrogen substations for semi-centralised configurations. However, the decentralised configuration exhibits a 5\% lower LCOH compared to the centralised and semi-centralised configurations due to the lack of additional substructures and high voltage electrical equipment.

In conclusion, this research contributes comprehensive insights into the techno-economic feasibility of semi-centralised offshore wind-to-hydrogen configurations. The findings highlight the potential of semi-centralised configurations and call for further research and optimisations. Unlocking the potential of semi-centralised offshore wind-to-hydrogen configurations can drive the transition toward sustainable and renewable energy sources.

The replacement of conventional generation units with variable renewable energy sources could have a negative impact on the balance of supply and demand of electricity. Moreover, since the variable renewable energy sources are inverter based and therefore decoupled from the grid, the overall grid inertia will decrease. To solve this problem, the traditional mechanical frequency response can be re- placed by synthetic inertial response and fast frequency response (FFR) alternatives from wind turbines. However, there is uncertainty about the order of magnitude of these ancillary services and how these ancillary services will affect the ultimate and fatigue loads on the wind turbine. The aim of the study is to gain an understanding of the extent to which an offshore wind turbine can provide synthetic inertia and fast frequency response and how this affects the fatigue and ultimate loads on the wind turbine.

Simulations were performed in FASTTool to study the response of the IEA 15MW offshore wind turbine using the baseline controller, synthetic inertia controller and FFR controller. The moments at the blade roots and tower base were used to perform a fatigue and ultimate load analysis. Three different grid frequency data sets were used for the grid frequency inputs of the synthetic inertia controller and FFR controller. In addition, the response of the wind turbine was studied at two different response sizes for both the synthetic inertia controller and the FFR controller.

This study showed a significant increase in fatigue damage equivalent load and maximum stresses due to an increase in the response size of the synthetic inertia and FFR controller. The results therefore showed that the extent to which an offshore wind turbine can provide synthetic inertia and FFR depends mainly on the magnitude of the controller response and not on the size of the wind turbine.

Green hydrogen is expected to play a crucial role in the energy transition as it can be utilised for both storage purposes and as fuel for hard-to-abate sectors. One of the possible configurations for producing green hydrogen is by means of a central offshore hydrogen production platform powered by offshore wind energy. Producing hydrogen offshore facilitates the possibility to eliminate parts of the expensive electrical infrastructure present in conventional offshore wind farms and could result in lower losses.

In collaboration with Vattenfall, this study provides a thorough examination of centralised offshore hydrogen production. The study addresses both the techno-economic feasibility of the centralised configuration and the effects of aggregating the power supplied by individual offshore wind turbines.

In Part 2, the study presents a comprehensive techno-economic analysis of different electrolysis technologies, the optimal hydrogen production unit capacity, and compressor output pressure. The outcomes reveal that an optimal levelised cost of hydrogen can be achieved by reducing the hydrogen production unit capacity compared to the offshore wind farm capacity. Moreover, increasing the hydrogen pressure above the minimum pressure required to overcome the pipeline pressure drop, reduces the levelised cost of hydrogen further. The study reveals a small preference for hydrogen production based on proton exchange membrane electrolysis, in comparison to hydrogen production based on alkaline electrolysis.

In Part 2, the focus is shifted towards hydrogen production solely, influenced by power fluctuations. By using historical offshore wind turbine power output data, it was found that aggregating the power output significantly reduces the normalised power output fluctuations, compared to a decentralised offshore configuration. However, the reduced power fluctuations did not result in a higher hydrogen yield, attributed to the inter-array cable losses of the centralised configuration. Nevertheless, a significant reduction in the number of switches of operational mode and the number of turn-offs of the stacks was observed. Reducing the number of switches and turn-offs will reduce the process of stack degradation.

The study concludes that centralised offshore hydrogen production facilitates the possibility to produce hydrogen at a competitive levelised cost of hydrogen. Furthermore, the reduction of the power fluctuations will benefit this configuration due to the deceleration of the stack's degradation process.

Solar and wind will displace fossil fuels as the main source of energy in a net-zero world. However, renewable energy sources provide intermittent power, hence an energy carrier that enables the balancing of demand and supply is needed. Here green hydrogen comes in place.
In addition, the demand for green hydrogen is expected to rise in the coming decades.
Given the geographical wind resource availability combined with supportive policy, the supply of green hydrogen can be delivered through offshore electrolysis. Moreover, in addition to higher yield, going further offshore creates a stronger case for hydrogen export as power export would become impracticable.
The energy industry is investigating what kind of typology and system configuration is most suitable for offshore green hydrogen production. This report provides insight into the performance of a single wind turbine integrated electrolysis system. For which the effect of different control strategies, electrolyser dimensioning and electrolyser capacities are analysed.

The study comprehends the requirements for transforming a single wind turbine into decentralised hydrogen producing wind turbine. This configuration is designed for an offshore application, but is not restricted to an offshore location. This novel system is equipped with a power conversion system, to power the electrolyser and auxiliaries. Seawater lift with water treatment for desalination and demineralisation. And ultimately, the electrolyser with accompanying balance of system.
This study selects a PEM electrolyser with three parallel modules of 5 MW capacity each. The individual components are separately modelled and combined to complete the system into a mathematical model. Furthermore, a power management strategy is included. The power management strategy determines which, how much and how many modules are powered. The enhanced results are measured by key performance indicators, which are total annual yield, number of start-stop events and power fluctuation within a module. These KPI's are inspired by the drivers of Shell to get the lowest levelised cost of hydrogen. More hydrogen production drives down the costs and the two other KPI's ensures less degradation on the modules, therefore extending the longevity.

This report shows that the use of a power management strategy improves the annual yield, but is also capable of minimising the effect of degradation caused by start-stop events and power fluctuation. The equal power division strategy increases the annual yield by at least 2%. The total number of power fluctuations can be significantly reduced by using the segmented start strategy. Finally, a strategy is developed to enhance the longevity of the system and diminish the degradation of the modules.
Moreover, independent of the strategy, a higher annual yield is achieved by decreasing the size of the modules with the same total electrolyser capacity. However, only when it is operated on the right setpoint.
Furthermore, over-sizing of the electrolyser capacity results in under-utilisation of the electrolyser. While under-sizing the electrolysis capacity leads to an increase in performance as the system is utilised more efficiently. The results are tested and strengthened in a sensitivity study, where other wind conditions and design parameters are applied to the system.

Floating offshore wind turbines (FOWTs) unlock the potential to harness energy from wind in deeper waters. Despite their potential, the major obstacle to large-scale commercial deployment remains the floating substructure's high cost. Multidisciplinary design, analysis and optimisation techniques are commonly employed to improve their cost-competitiveness, but existing models often use simplified engineering models. This approach risks neglecting design considerations typical of structures subjected to complex aero-hydro-servo-elastic loads.

To address the need for incorporating higher-fidelity analysis methods, an optimisation framework is developed, integrating OpenFAST to simulate the response of the FOWT system under various environmental and operational conditions. Leveraging the flexibility of the Python framework and the wealth of output data contained within the OpenFAST simulation results, this holistic approach offers opportunities to explore novel and cost-effective platform designs with high reliability.

To demonstrate its effectiveness, the optimisation framework is utilised to achieve a significant reduction of the DeepCWind platform's structural mass. Among the considered constraints, the platform pitch motion was critical, reaching maxima for design load cases characterised by the most extreme wind and waves. Although the inclusion of a structural model for the platform comes at considerable computational expense, it enhances the framework's value, as structural integrity can be verified.

The recommended use of the optimisation framework is for in-depth studies, following preliminary design explorations conducted with cheaper models. Future efforts should focus on extending the structural and hydrodynamic model to improve the framework's versatility, and make it applicable to a wider range of platform concepts and turbine sizes.

The global emission of harmful greenhouse gasses has to be reduced. Commercial shipping contributes to these emissions by using fossil fuel as the only energy source to provide propulsion and power auxiliary systems. In order to reduce fuel consumption, much research is focused on increasing the efficiency of the propulsion system and reducing the required power consumption. In recent years an increasing amount of research focuses on utilizing wind energy as an alternative energy source. This is a renewable source of energy which is plentiful at sea. This thesis focuses on the novel concept of using a Vertical Axis Wind Turbine (VAWT) as a means of ship propulsion and power generation. Existing Wind Assisted Ship Propulsion (WASP) systems can only be utilized in conditions when the ship is in transit and when the apparent wind conditions are favorable. The VAWT concept has the ability to generate power in wind conditions where conventional sailing systems are not functional, including when the ship is in port. This system can also be used as a thrusting device when the wind conditions are favorable for sailing systems. Therefore this system can be used more frequently which is beneficial for the overall power savings. The use of a VAWT for WASP in combined operation as a thruster and a power generator does currently not exist. Therefore the design of the rotor has to be investigated and optimized in order to evaluate effective designs for different conditions and to compare this device to existing sailing concepts. The aerodynamic performance of the VAWT will be evaluated using numeric simulation models. This model will be coupled to an optimization algorithm in order to find the optimal design parameters for different wind conditions and modes of operation. This project will result in a better understanding of the working principles of VAWT used for WASP and the potential energy saving of optimized designs for the operational modes as a generator, thruster and combined-operation. There is a large opportunity for capturing wind energy at sea. This project has the potential to add a new method of ship propulsion to reduce shipping emissions and reducing the cost of ship operation. When one or multiple of these systems can be applied on a large share of the worldwide shipping fleet, this research can contribute to the reduction of commercial shipping emissions.

Offshore wind farms designed solely for hydrogen production are promising solutions for maximizing wind energy conversion, decarbonizing industries that cannot directly utilize electricity, and reducing the need for additional grid reinforcements. Furthermore, floating offshore wind turbines enable the capture of wind resources in deeper waters. This has created the possibility of locating wind farms far offshore. This study looks into the technological and economic feasibility of in-turbine hydrogen production, storage, and transport via vessels from far offshore floating wind farms. Transport of hydrogen via pipelines and transport of hydrogen via a large vessel connected to the entire wind farm are also studied for comparison and bench marking purposes. To investigate the performance of various transport methods, a wind farm model is built that includes the components required for hydrogen production at the wind turbine as well as the components required for hydrogen transport. The model simulates wind farm operation, vessel operations with regard to onsite storage, and vessel operations when connected to the entire wind farm. Based on the levelized cost of hydrogen(LCOH), the performance of the three different farms has been compared. The study was conducted over distances ranging from 100 to 700 km. Throughout the range of distances studied, on-site hydrogen storage and periodic removal via vessel proves to be the least cost effective solution. Weather conditions are seen to be a significant factor in the operation of the vessel fleet servicing the farm with on-site storage. When combined with a four-vessel fleet servicing the entire wind farm, the optimum storage size in the farm type with onsite storage is found to be equal to the wind turbine average weekly production. A key distinction is seen in the cost trends, a steady increase is seen in hydrogen transport via pipelines with increase in distance, while, the LCOH of hydrogen remains nearly identical for the transport of hydrogen via vessels over the range of distances studied. The farm produces the most hydrogen with pipeline transport of hydrogen followed by transport of hydrogen via a large vessel, and the least hydrogen with in platform hydrogen storage and periodic emptying of the storage by vessels. The study indicates that the pipeline transport of hydrogen is the most cost effective transport option.

The most effective way to decrease the cost of energy of wind turbines is to increase the rotor diameter. Therefore, this calls for the need of aerodynamic research on large wind turbines. This thesis project will tackle the topics addressed by the IEA Wind Task 47 which is focused on the aerodynamic analysis and comparison of the newly proposed IEA 15-MW reference wind turbine using varying fidelity tools. Therefore, the main goal of this work is to analyze whether a low-fidelity approach is still feasible for aerodynamic analysis in comparison with a high-fidelity approach. It was found that there are quantitative differences between the different fidelity methods but also qualitative similarities. It can be concluded that the low-fidelity methods are relatively less suitable for a large turbine design, especially for high TSR values, which should be confirmed by further research including different fidelity tools and turbines.

In order to decarbonize the electricity grid, renewable energy sources must be utilised in con- junction with energy storage to provide ancillary services, which maintain electricity supply quality, reliability and restorability, whilst remaining aordable. Due to a lack of knowledge about the potential of stacking UK ancillary services and electricity markets to improve service aordability, this study of a wind farm with a co-located battery system compares the UK Black Start service, Firm Frequency Response static low frequency secondary and dynamic high frequency services, alongside the day-ahead market as sources of revenue, both provided individually and stacked, with all mismatches handled in the balancing market, to identify the most protable method of operation. A model of the wind farm - battery system power and energy ows is used to assess availability of Black Start and two Firm Frequency Response services, as well as operation in the day-ahead and balancing market, for a one-year period. Internal rate of return and levelized cost of electricity are used to measure nancial perfor- mance, with a weighted average cost of capital (WACC) of 7.75%. Is is found that no service or market provision is protable compared to the WACC, and the most protable method of operating the system is to sell all wind energy forecast on the day-ahead market, not using storage and not stacking services. The most protable method of providing the BS service is when stacked with the FFR static low frequency secondary service. The most protable method of providing either the FFR static low frequency secondary service or FFR dynamic high frequency service is alone, not stacked. The protability of stacks are most sensitive to the changing of BS requirements, although the protability rank order of stacks doesn't change. A single bad wind year has a very small eect on BS availability, and the eect of increased frequency deviations doesn't aect the stacks of FFR services due to limited income from FFR service energy provision compared to the balancing market or from FFR service availability.