Hydrogen is emerging as plausible energy carrier to decrease the global dependency on fossil fuels. Hydrogen production based on renewable energy and electrolysis is a technically mature and well-researched production process. Production processes based on large electrolyzers result in varying and relatively high (between €4/kg and up to ± €14/kg) levelized costs of hydrogen - attributable to high electrolyzer and electricity costs. This research evaluates the potential of an off-energy-grid PV and small- capacity electrolyzer based hydrogen production process. The assessed smaller-capacity electrolyzers result in less than a quarter of most electrolyzer costs (€/kW). The cost reduction combined with the avoided electricity costs due to grid connection, allow for market competitive LCOHs within the range of ± €2,15-5/kg hydrogen depending on the hydrogen outflow system chosen for the farm. This research shows that the low electrolyzer and electricity costs of an off-energy-grid PV and small-capacity electrolyzer based hydrogen farm - with running hours limited to the average sun equivalent hours while including a water supply system (source, treatment, distribution across farms, etc.) and a hydrogen outflow system (collection across farm, possible compression) - has technical feasibility and market potential.

This study investigates the technical feasibility and economic viability of utilizing depleted offshore gas reservoirs in the Dutch North Sea for underground hydrogen storage (UHS) to buffer intermittent hydrogen production from offshore wind farms in the Dutch North Sea. The research aims to address the existing knowledge gap in integrating an offshore hydrogen storage platform while considering the maximum re-useability of existing natural gas infrastructure.

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 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.

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.

This study researched the optimal network of hydrogen refueling stations. The network is designed on a European scale and with a focus on heavy duty trucks. The design is created by means of a two-step optimization. The first step clusters truck representing datapoints into a predetermined number of stations by means of k-means clustering. The second step optimally connects these to a source of supply, which is assumed to be a European hydrogen backbone. Cost values of supply and demand are finally optimized by balancing a cost function.

Research was performed by order of Shell.

Hydrogen is expected to be a significant force in this transition. Hydrogen can be produced using technologies that do not emit CO2 or other greenhouse gasses (“green H2”). Hydrogen can be transported in big quantities and long distances unlike electricity and can play the role of a clean fuel. The emerging hydrogen economy, which will be accompanied by the gradual phase-out of fossil fuels, will significantly impact ports around the world. Ports can and should play a pivotal role in this “energy revolution”. Apart from import and export services, ports often include industrial clusters, they provide servicing and refuelling to visiting vessels and connect major trade routes.

This study aims at understanding and providing insights on challenges that the above-explained transition will create in a port environment focusing on hydrogen. Firstly, a favourable policy environment for hydrogen projects in the ports and maritime sector is a key topic that this study will address. This is included as a conclusion in many reports and port conferences. Secondly, the questions related to terminal planning and area requirements of hydrogen terminals remain unanswered as large scale hydrogen projects do not exist yet -with many being under development-, and thus this research will try to shed light on area calculations of hydrogen terminals. Thirdly, and lastly, terminals operators, investors and policy makers will need to make decisions on the preferred hydrogen carrier and location for various hydrogen projects that will be developed in the near future. Therefore, a method of comparison of different alternatives is required, especially when terminals are planned next to existing liquid bulk terminals.

In this thesis, we explore a proposal from Stedin that advocates heating the city of Stad aan `t Haringvliet with hydrogen rather than natural gas. Switching from natural gas to hydrogen presents plenty of unknown factors which must be properly evaluated for an accurate and realistic risk picture, including the danger of running out of hydrogen. The objective of this study is to examine the security of a 100% hydrogen supply in city buildings. For this MSc thesis, the security of supply is defined as a reliable and uninterrupted supply of hydrogen for heating purposes. We explore the security of supply by evaluating the risk to it.

To achieve this goal, we construct a hydrogen supply system using Stedin's criteria. The Classical Model for Structured Expert Judgement and the Bayesian Network are the two mathematical techniques we use to evaluate the risks. The lack of acceptable data makes the task of quantifying the risk to supply much more difficult in this regard. Expert opinion remains the sole trustworthy source of information in these conditions for quantifying uncertainty. However, expert opinion should be validated using objective performance measures. As a result, we adopt the Classical Model for Structured Expert Judgement. The resulting uncertainty distributions of the Structured Expert Judgement research are then integrated into a Bayesian Network that models the uncertainty within the hydrogen supply system. Bayesian Networks are an effective tool for visualizing a domain's probabilistic model, examining all random variable interactions, and inferring probability for scenarios based on available data.\\

The findings of Structured Expert Judgment reveal that there will be a forecast of 114 minutes of not enough hydrogen in the buildings of Stad aan 't Haringvliet in the first year of realizing Stedin's pilot, given the event that there will be a lack of hydrogen in Stad aan `t Haringvliet. Moreover, the security of supply is expected to not be achieved with an estimated probability of 0.06839 for the first year of realizing this pilot. Furthermore, failure rates for each component of the hydrogen supply system have also been quantified using the Classical Model, and one or more mitigations have been proposed for each component. Quantifying the Bayesian Network with the distributions for each component of the hydrogen supply system that resulted from the expert judgment study, yields distinct results than experts' aggregated distributions on the estimated probability and the duration of not meeting the energy demand. The results show that the best-estimated probability for not having enough hydrogen in the buildings equals 0.2067 and when we consider the event of having a lack of hydrogen in the buildings, the best estimated time for how long this will last equals 3.135 minutes in the first year of realizing Stedin's pilot.

Hydrogen produced by electrolysis of water, powered by renewable energy, is seen as the key to enabling the energy transition and creating a new green economy. The result will be a trade market for low-carbon hydrogen where the trade routes will be determined by natural, technical, cost and geopolitical factors. However, to transport or store hydrogen, it must be compressed, liquefied or attached to a carrier due to its low energy density per unit volume. The challenge of this is that the transport of hydrogen is expensive and still at an exploratory stage. More research is needed into the most cost-effective opportunities for the emerging hydrogen transport supply chains. The main objective of this research is to develop a method that provides insight into the effects of hydrogen supply chain configurations on the cost price of hydrogen at the end-use location. The method should provide a better understanding of the influence of different distances and required volumes on the supply chain structure and on the type of hydrogen transport. In addition, by connecting supply chains, it should become clear how the interaction of supply chains affects the cost and throughput. Eventually, it is concluded that if the overseas distance is made variable, DBT will be the most economical option for shorter oversea distances and that for longer oversea distances MCH and ammonia will be the most cost-effective options. This tipping point is around 3500 - 4500 nm (6500 - 8400 km), depending on the volume of the supply chain, the distance to the end user and whether the supply chain configuration is centralized or decentralized. The centralized option will be more cost effective than the decentralized option for all the carriers. It can also be concluded that the cost price of each carrier will approach a some what constant value at large supply chain volumes. From the sensitivity analysis, it can be concluded that the eventual cost price is very sensitive to the WACC and to the price at which the hydrogen is purchased in the export country. In addition, the cost price of LH2 is highly sensitive to the number of storage tanks. All hydrogen carrier options are also relatively sensitive to the energy price.

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.

Residential space heating demand in the Netherlands is met by natural gas boilers in 93% of Dutch households. In order to combat global climate change and limit the increase in global average temperatures to below 1.5°C by the year 2050, the Netherlands will have to cut down its emissions across all sectors of human activity to nearly zero. The residential space heating sector accounts for majority of the emissions of the built environment, decarbonising this sector is key to eliminating greenhouse gas emissions and combating global climate change. Decarbonisation of the residential heating sector can be achieved through multiple pathways. The aim of this thesis is to investigate which pathway would have the least cost to the end user in the year 2050. Three pathways have been selected, the all-electric pathway based on using heat pumps to meet space heating demand, the core hydrogen pathway based on meeting heating demand with end-use hydrogen boilers, and the hybrid pathway based on meeting heat demand with hybrid heat pumps. Electricity supply in all three pathways will come mainly from solar photovoltaic energy and wind turbines and hydrogen will be produced by electrolysis of water, from renewable electricity. Hydrogen is assumed to be transported directly to end-user households using the existing natural gas transport infrastructure of the Netherlands, with adequate safety modifications, after being produced by dedicated offshore wind turbine capacity. Hydrogen is not produced at all in the electric pathway. First, the heat demand per household (space heat + domestic hot water) is determined for each of the five types of dwellings in the Netherlands. Annual energy cost per household is then determined from projected future electricity and hydrogen retail prices. The installation of heat pumps will also involve renovations to the home to improve insulation levels in order to maximise the coefficient of performance, at additional cost to the end-user. The total annual cost per household of each pathway is then determined as the sum of the annual energy cost per household, the investment and installation cost of each device per household, and the annual maintenance cost. Total annual cost per decarbonisation pathway is the sum of the total annual cost per household for all houses in the Netherlands in 2050. The annual cost per household varies widely depending on the values of electricity and hydrogen tariffs in 2050, the capital investment cost of each device, the level of household renovations required to improve household insulation levels, and the cost of investment in devices such as low temperature radiators. Annual costs vary among different types of dwellings, the smaller the dwelling, the smaller the required area to be heated. The annual cost per pathway was found to mainly have uncertainties regarding the device capital investment cost and electricity and hydrogen tariffs in 2050. To reduce uncertainties in results, a scenario study was performed. The scenarios were constructed to account for the variations in device capital investment cost found in literature for electric and hybrid heat pumps, and the variations in energy tariff (electricity and hydrogen tariff) estimates for 2050. In five out of six analysed scenarios, the hydrogen boiler pathway was found to have the least annual costs in 2050, with electric heat pumps being the most expensive pathway in these scenarios.

Hydrogen enables renewable energy storage, and hydrogen carriers can allow easier transportation. This research was initiated to get more insight into transporting renewable hydrogen carriers (RHCs) by ship, which is one of the transportation options. The research was conducted in three steps. First, a system description with a literature study was made to select suitable RHCs, based on the production, and the performance as a hydrogen carrier. Secondly, a basic model for three transportation cases was made. Thirdly, a more detailed model was created to evaluate different transportation options. The four most attractive RHCs to be shipped are the synthetically produced: methanol, liquefied natural gas, liquid hydrogen, and liquid ammonia. In the model, short and long term options are evaluated for the same, mild and strict regulations compared to today. The following statements can be made, based on the results of the second model: • Ammonia is best suited in a scenario with strict regulation compared to today. Ammonia has a noncarbon nature; therefore, it is the most promising option in the long term. • Methanol is best suited for small scale transportation in the short and long term, in which the same regulations are active. The storage of methanol on board of the ship is relatively simple and it has a relatively high hydrogen density. • LSNG is best suited for large scale transportation in which the same regulations are active. LSNG has the highest hydrogen density of the discussed RHCs. The advantage of SNG is that during the reconversion to hydrogen, extra hydrogen will be produced because of the added steam, during steam methane reforming (SMR). • Liquid hydrogen is from a shipping point of view not the most suited for the transport of hydrogen, due to its low volumetric density and complex storage. Shipping liquid hydrogen has the advantage that it reduces extra conversion steps in other parts of the supply chain. Shipping RHCs and using the carriers as a fuel is an option which involves higher cost compared to current fossil fuel options. This relatively high share of fuel expenses using RHCs will make efficient powertrains relatively more attractive because it enables higher fuel cost savings. The most attractive engine configurations are a two-stroke internal combustion engine with a mechanical powertrain and a SOFC with a battery in an electric powertrain. The last option is especially promising for the long term, because of the technologic developments and increasing regulations in shipping. Overall the results indicate that shipping NH3 and using the carrier as a fuel is the most promising option for the transport of RHCs by ship. This research and constructed models can be used as a tool to evaluate different transportation options. However, used values are based on various sources and their corresponding assumptions, which can change significantly in the future.

Due to the abundance of solar energy resources in Oman and the participation in the joint venture of the Port of Rotterdam in the Port of Sohar, importing green hydrogen in the Port of Rotterdam has been suggested. In part one of this two-part research (Shipping Sunshine) two green hydrogen import prices were calculated based on a 100 [GW] solar pv system. The first price of 1.97 [e·kg−1] hydrogen received at the Port of Rotterdam considers cur- rent costs. The second price of 1.47 [e·kg−1] considers a 50% decline in solar pv module and electrolyzer capital expenditure costs. However, supply and demand of green hydrogen have to be created simultaneously. This second part will identify which hydrogen markets in the hinterland of the Port of Rot- terdam are feasible from a techno-economic perspective given both import prices and an ETS price of 25 and 80 [e·t−1] respectively. Besides, it will evaluate the carbon emission abatement cost in these markets. A new methodology is proposed, using hydrogen parity prices to create a level playing field in comparing these markets as well as synthetic fuel costs. Furthermore, the existing supportive policies will be included. Lastly, the required prices in these markets are compared to current market prices. At a green hydrogen import price of 1.47 [e·kg−1] and an ETS price of 80 [e·t−1], the following hydrogen markets are feasible: mobility, steel industry, natural gas blending, low temperature heat, natural gas power plants, SMR substitution and harbor tugs. The mar- ginal abatement cost ranges from minus 350 [e·tCO2−1] to 460 [e·tCO2−1]. Future research could focus on the sensitivity of these hydrogen markets when other techno-economic para- meters change, thereby affecting the parity price of these specific hydrogen markets. Besides, future research could identify the future volume of the studied hydrogen markets.

Energy storage systems are an emerging field of interest for the future of electrical grids. With the rapid growth of renewable but intermittent sources of electricity, energy storage systems can help smooth the variations, making the grid more stable and reducing the need for maintaining an overcapacity of power production infrastructure. Among energy storage solutions, power-to-chemical storage is of particular interest due to the high energy density of chemicals and seasonal storage capabilities. Developments made in power-to-chemical technologies can also go a long way towards making the transportation and chemical industries sustainable. The chemical considered in this work is ammonia (NH3), which has advantages of being an easily liquefiable fuel, and has also been in industrial use for over a century. This thesis project aims towards the development of an efficient power-to-ammonia energy storage system using reversible solid oxide cells. The system designed in this thesis is based on direct ammonia utilisation in fuel cell mode, and steam electrolysis coupled with Haber-Bosch ammonia synthesis in the electrolysis mode. A steady state process model is designed in Aspen Plus. This is followed by extensive thermodynamic exergy analysis, used as the basis for the further design and optimisation of the system, with a goal to maximise the round trip efficiency. Exergy analysis is used to identify the sources with most scope for improvement.
The final system can attain a maximum round trip efficiency of 61.20 %, improved from a basic system efficiency of 19.79 %. The maximum round trip efficiency is comparable to values reported in recent times for thermodynamically studied models from literature using other fuels, such as 56.72 % for methanol. The optimised system attains high efficiencies without the need for thermal energy storage or an afterburner. Further, it is demonstrated that the designed system is efficient enough that heat integration across modes with high temperature energy storage does not provide any significant benefit.

The objective of this research is to understand what smart charging can bring business and society at large. In close collaboration with the largest fleet operator in the world and a commercial aggregator, the impact of smart charging on both cost reduction and carbon reduction was simulated for an electric vehicle (EV) fleet in 2018. The simulation is designed to quantify the cost reduction of EV smart charging in The Netherlands as realistic as possible. Besides cost reduction quantification, the objective is to create a better understanding of what variables influence smart charging cost reduction. This is done via a statistical analysis of the smart charging simulations output. Furthermore, this research also has the objective find the direct impact of smart charging on carbon intensity of the electricity used for personal transport.
In this research, an EV aggregators perspective is leading. The EV aggregators could utilizing available flexibility in an EV fleet to deliver flexibility services. The strategy chosen to simulate is based on day ahead market optimization and passive balancing on the imbalance market. The EV fleet is assumed to be an isolated portfolio handled by the balance responsible party (BRP). The average synthetic load profile over 2018 was €41,56 per MWh and this is used as benchmark to quantify the smart charging savings in the simulations.
Different smart charging simulation set-up scenarios are designed and executed. In all simulations a real-world charging data set with 300.000 historic charging sessions was used. For each session, a new smart charging profile is determined by the optimization algorithms. The session price and session carbon intensity is calculated for both the smart charging scenarios as the business-as-usual scenarios. To compare the results of the different smart charging set-up scenarios, the average session price of all session in that simulations is used. At the same time, the smart charging savings is calculated based on the defined benchmark. The findings within this thesis support the conclusion that the used smart charging algorithms work properly and could decrease the electricity purchase price in The Netherlands. Additionally we found that the carbon intensity of the charged electricity during the smart charging schedule decreases compared to a business as usual scenario. This is a direct result of a correlation between the carbon intensity in the grid and day ahead prices in The Netherlands. EV aggregators are able to add flexibility to the demand side of the electricity system by means of smart charging, if a strong price incentive is provided. If stakeholders across the mobility and the energy sector work together, a real-world commercial implementation based on the price incentives on day ahead market and imbalance market in The Netherlands is possible. In the statistical analysis, multiple regression models show a linear relation between three independent variables (the session duration, session volume and maximum power of the charge point) and two dependent variables (the average session purchase price and savings per session). The key insights from the models empowered three main recommendations to EV aggregators to optimize the smart charging savings in the future: 1) Encourage longer session length. 2) Encourage regular overnight charging sessions behaviour, independent from the charging needs. 3) Stimulate access to high charging power. The data showed compelling differences between the 20% BEVs and the 80% PHEVs and their results were separated accordingly in this research. In all simulation set-up scenarios are the PHEVs outperforming the BEVs in terms of a lower average session price and higher cost reduction. If the smart charging strategy is executed as proposed in this thesis, the EV aggregator is exposed to the day ahead market and imbalance settlements for its portfolio. The EV aggregator is able to decrease the electricity purchase price, while acting as BRP. The exposure to the markets brings significant risk. Collaboration with an electricity supplier or BRP could potentially increase the smart charging savings for the EV aggregator. Furthermore, other revenue streams to utilize flexibility could be investigated. If stacking different flexibility strategies is possible, it could increase the smart charging value in the future.

The world population is growing and therewith facing a lot of problems, such as a growing energy demand and climate change. These problems force society to make a transition, from a system driven by fossil raw materials to a sustainability-based system. Hydrogen can play a part in shifting from fossil fuels to more sustainable energy flows, as a renewable energy carrier, to decrease the CO2 emissions. However, the major obstacle of hydrogen use is the low volumetric energy density at room temperature and atmospheric pressure. Therefore, hydrogen must be compressed, liquefied or attached to a carrier to use it for storage or transportation purposes. The most cost-effective method to import hydrogen is yet unknown, and therefore a better understanding of the costs of the hydrogen supply chains are essential. The objective of this research is to: (1) understand the different costs for each individual element of the supply chain, (2) design a hydrogen supply chain that integrates the individual elements into a single framework to be able to compare the different carriers to each other and (3) create a more profound perspective on the investment decisions for a hydrogen import terminal. A case study for the port of Rotterdam is performed to validate the operation of the general supply chain for a specific case, resulting in a more in-depth understanding of the import terminal. This research covers four hydrogen carriers: ammonia, MCH, liquid- and gaseous hydrogen. The answer for objective one, is that for ammonia and MCH the import terminal costs are the highest, for liquid hydrogen the conversion plant costs and for gaseous hydrogen the transport costs. The hydrogen costs for ammonia, MCH and liquid hydrogen decreases as long as the demand increases, up until an amount of 500,000 t/y, whereby for gaseous hydrogen this decline holds for values beyond this amount as well. In general, for distances up to 3,500 nm gaseous hydrogen is preferred and for intermediate to long distance ammonia. The discrepancy in costs between ammonia, MCH and liquid hydrogen is almost negligible. Regarding the second objective, it can be stated that it makes no difference when choosing one carrier, or the other at ammonia, MCH and liquid hydrogen for intermediate to long distances. To conclude, the optimal hydrogen import supply chain for the estimated demand of Rotterdam is obtained from gaseous hydrogen exported from Tunisia with a cost price of 2.3 €/kg.

Current energy concerns like growing energy demand, the desire for a clean environment and energy conservation started thrusting the society towards distributed renewable electricity generation (DG) technologies. These technologies such as PV solar, Fuel Cells (FC) and urban wind produce Direct Current (DC). The electronic equipment such as laptops, PCs, communication systems, LED lighting, batteries, Electric Vehicles (EV) and Fuel Cell Electric Vehicles (FCEV) also operate in DC. But the present-day electricity distribution system is based on Alternating Current (AC). From this conventional system, the conversion losses can be substantial when DC generation and DC loads are operated. For which, several (DC/AC – AC/DC) conversion steps are required. These conversion losses can be mitigated by removing the intermediate conversion steps and distributing DC power to the DC loads directly. For which, the main aim of the thesis focuses on the technical and commercial potential of Low Voltage DC (LVDC) grids for buildings in the Netherlands. DC office is a small office building at The Green Village (TGV) in TU Delft where a 350 Vdc LVDC system is installed for experimental purposes. The experiments are carried out using both LVDC and LVAC grids in DC Office project. The obtained experimental data are randomized using Matlab to create a year-long load profile. The results are used for discussing the LVDC technical potential in terms of overall efficiency and energy savings. From these results cost-savings are calculated. Along with this, usage of copper and aluminum as electrical conductor in buildings and its investment cost-savings are discussed. For the commercial potential of LVDC grids for buildings in the Netherlands, the Function of Innovation Systems (FIS) approach is used to identify the corresponding LVDC stakeholders, research, pilot projects, rules and regulations and policies for development. For the technical potential, there are three different cases formulated for analysis. They are ACTube case, DCLED case and ACLED case. In the experiments, tubelights are used in the ACTube case and LEDs are used in the DCLED case, in-order to neglect the energy savings obtained from LED technology, ACLED case is assumed. The overall efficiency of the LVDC grid (DCLED case) is 94.82% and the LVAC grid (ACTube case) is 88.16% and the LVAC grid (ACLED case) is 88.67%. From all these cases, the LVDC grid is around 6.5% more efficient than LVAC grid in small buildings similar to the DC Office. The energy savings obtained by LVDC grid replacing LVAC grid (ACTube) is 2013 kWh/year, and if tubelights in AC are replaced with LEDs in AC, then 1854 kWh/year is estimated to be saved. The cost-savings are calculated from the energy savings obtained by replacing LVAC grid (ACTube case) with LVDC grid (DCLED case). Considering the total lifetime of the LVDC system as 12 years, the cost savings obtained are € 221.43/year achieving payback in 6 years. For the commercial potential, using seven functions of FIS it is identified that there are several stakeholders interested in LVDC projects and are responsible for pilot projects. The government also is implementing the new NPR 9090 as the rules and guidelines for LVDC grid installations in buildings. It is also identified that people have positive acceptance of the LVDC grid in their houses. But the knowledge sharing about LVDC among the society is currently lacking. Moreover, the AC electricity distributors are interested in shifting towards the DC micro grid distribution.

A hydrogen fuel cell scooter was tested for the first time to alternatively drive, power electric appliances (Vehicle-to-Load, V2L) and power the grid (Vehicle-to-Grid, V2G). Performance of the scooter is known to rely mainly on the fuel cell stack, and fuel cell degradation depends on the operating conditions. This study aimed to provide insights on how each mode of operation (driving, V2L and V2G) impacts the fuel cell stack performance, as well as the overall system.
Operation in each mode was mimicked by applying typical duty cycles to the hydrogen scooter via an electronic programmable load.
Analysis of the experimental data yielded clear differences between each mode of operation. Principal Component Analysis (PCA) revealed that the voltage of the fuel cell and the battery were most determining in segregating the three modes.
The highest system efficiency was found for V2G usage of the scooter (39.4\% based on higher heating value). The power demand throughout this mode was high, making the fuel cell operate at almost full capacity.
Linear regression analysis was used to determine the fuel cell degradation rate. Severe degradation was measured throughout the experiments, with an overall voltage cell drop of 402 µV/h. Distinguishing the degradation rate per mode revealed V2L operation to cause the largest fuel cell degradation (648 μV/h) and driving the least degradation (205 μV/h). This result was confirmed by comparing the IV curve of the fuel cell stack before and after the experiments: the largest voltage drop occurred at low currents.
Further research on scooter usage in combined modes should include new energy management strategies for V2G and V2L operation, which focus on minimizing fuel cell degradation.