Green hydrogen is anticipated to be pivotal in the decarbonisation of global energy systems. For the Netherlands, both domestic production and imports of green hydrogen are believed to be needed for effective decarbonisation. Yet, significant uncertainty surrounds the cost discrepancy between domestic productions and initial imports, largely attributed to insufficient comparability of different reports. This study conducted a techno-economic assessment (TEA) to better understand these cost dynamics.

To ensure that viable exporting countries are assessed a multicriteria analysis (MCA) was employed. Within this MCA, contributing factors underwent expert weighting. It was found that the earliest developing value chains might not necessarily be the most economical. Among potential initial exporters to the Netherlands, Chile, Spain, and the United States emerged as frontrunners, which led to their assessment in the TEA.

The study highlighted the importance of wind availability for cost-effective hydrogen production. Even with favourable wind conditions in the Dutch North Sea, the Netherlands faces higher hydrogen costs due to the added expenses of connecting the wind with an onshore electrolyser through the grid.

The costs of hydrogen transport were evaluated based on four possible hydrogen import development scenarios for transport as ammonia, liquified hydrogen and the liquid organic hydrogen carrier (LOHC) DBT. Results indicated that the costs of delivered hydrogen will likely range from similar to thrice that of domestic production across the different countries and carriers for the two scenarios where gigawatt supply chains are realised. Consequently, the study suggests that overseas imported green hydrogen will be more costly than domestically produced hydrogen in 2030.

Dutch offshore wind farms are primarily located near the coast and connected to the grid, but as offshore wind farms continue to expand and occupy more space, developers are turning to deeper waters. However, installing traditional monopile or jacket structures in these deeper waters can be expensive. One potential solution is the Dogger Bank, a shallow sand bank located 275 km from the Dutch coast, which allows for inexpensive wind turbine installation and high capacity factors. For far offshore locations like the Dogger Bank, electricity transport can be costly, making hydrogen transport via the existing gas infrastructure a more efficient solution. This could enable hydrogen production far offshore and its use in the decarbonisation of hard-to-abate sectors.

This study focuses on the development of a stand-alone offshore hydrogen production system, incorporating battolyser technology, on the Dogger Bank. The battolyser, which combines a Ni-Fe battery and an alkaline electrolyser, is able to store energy and produce hydrogen efficiently and flexibly. However, as the battolyser is not yet commercially available, the proposed systems are analysed for the years 2030 and 2050. The study examines three system configurations: an electrolyser-battolyser, battolyser-only, and electrolyser-battery configuration. For the electrolysers, alkaline and PEM electrolysis is considered. For the battery a vanadium redox flow battery (VRFB).

To ensure autonomous operation, the battolyser serves as a backup power source for supplying
the system’s auxiliary energy demand. This demand is used to determine the system’s sizing, and a MATLAB/Simulink model is developed to calculate the hydrogen production based on future estimates of technical parameters. The hourly wind data from offshore platforms near the Dogger Bank is used as input for the model. To project future capital expenditures (CAPEX) for the model components, a learning curve method is employed, which assumes a specific cost reduction rate with every doubling of cumulative installed capacity.

This study demonstrates the feasibility of an offshore wind-hydrogen system with battolyser
technology, both technically and economically. Battolyser CAPEX are used as an input variable to estimate a range of possible levelized cost of hydrogen (LCOH) values for different systems. The study findings indicate that LCOH values of less than 1.55 C/kg could be achieved by 2030, and by 2050, these values could drop to less than 1.18 C/kg.

As part of the Dutch government’s ambitions to realise significant offshore wind energy capacity (70 gigawatts (GW) by 2050), the Port of Rotterdam is to become a hydrogen hub for North-Western Europe. To achieve this, it is expected that around 20 megatonnes (Mt) of hydrogen could be throughput in the Port of Rotterdam, out of which 2 Mt will be produced locally from offshore wind farms. Current offshore wind farms use high voltage electricity cables to transport energy to shore, but could, in the future, also transport energy in the form of hydrogen to shore via a transport infrastructure.
The objective of this thesis is to investigate the techno-economical feasibility of an offshore hydrogen production value chain connected to the Port of Rotterdam. The technical analysis gives insights into the possible technologies that can be used for the offshore value chain. It will also look at the technical feasibility of system integration in the Noth Sea's energy system. The economic analysis gives insights into the economic feasibility of the offshore hydrogen production value chain. The total costs are of importance, as well as the levelised cost of hydrogen.
In this thesis, a qualitative literature study maps the different possibilities per component of the value chain. A decision framework is then used to discuss the best possibility per component and to build three promising designs. These designs are then modelled in MATLAB to size their components. With the model’s output, a cost analysis can be done to determine whether such a value chain would be feasible compared to other ongoing projects. A special focus will be put on the Port of Rotterdam, to which the value chain will be connected.
The offshore decentral configuration is found to be the best-performing design based on assessments through a multi-criteria decision analysis, a technical model and a financial model. It is, therefore, the most promising design.

Methane pyrolysis is a technology that has the potential to greatly reduce the CO2 emissions of hydrogen production on a large scale. The process generates solid carbon instead of gaseous, thereby inhibiting emissions and has a relatively low process energy demand.

A three-step approach was taken to investigate the feasibility of offshore methane pyrolysis for sustainable hydrogen production. Firstly, a model was developed to evaluate the potential for converting methane into hydrogen under various design scenarios. Secondly, the model was utilized as a tool to create an offshore design for the methane pyrolysis reactor, including necessary auxiliary equipment. Finally, a calculation of the levelized cost of hydrogen (LCOH) was conducted to compare it with conventional methane reforming technologies for hydrogen production.

The ultimate results showed a higher LCOH of offshore methane pyrolysis compared to the reforming technologies, however, two main components were identified that have the potential to close this gap. First, the sales of the solid carbon by-product would reduce the LCOH of offshore hydrogen and second the introduction of a CO2 tax would increase the LCOH of reforming technologies where methane pyrolysis is not affected. Thus, it can be inferred that offshore methane pyrolysis can be cost-competitive under the appropriate conditions.

A radical change of the energy system is required in light of the dramatic effects of human-induced climate change. In this perspective, a future renewable hydrogen energy system was proposed, where biogenic resources are ascribed relevant potential as source of biogenic hydrogen and biogenic carbon dioxide. In this light, the research brings forward the concept of third-generation upgrading as the highest valorisation potential of biogas. This alters the perspective on biogas as source of renewable electricity, heat or fuel to biogas as platform molecule able to couple the renewable hydrogen and bio-economy domain. The research shows that concept of third-generation upgrading relies on a technologically feasible, environmentally benign and economically sound production process. In this respect, the adoption of the concept of third-generation upgrading is supported via the valuation of the bio-carbon dioxide as scarce renewable carbon-containing molecule and valuable carbon sink. Therefore, the concept of third- generation upgrading should be supported via regulatory commitment, market creation, policy mechanisms and infrastructural changes. In this way, biogas can act as an invaluable source of bio-hydrogen and bio-carbon dioxide, spark system integration and stimulate energy security. Ultimately, this research proposes to change the way biogas is seen.

The European Green Deal states that it wants to develop 40 GW of electrolyzer capacity by 2030 in North Africa to combat climate change. Using PV power as the primary energy source, a system is designed that can produce green hydrogen and ammonia to investigate how the location and the capacity of the components can be optimized to produce at the lowest possible levelized costs. This way the competitiveness of green hydrogen and ammonia can be examined against hydrogen and ammonia produced using fossil fuels. Incorporating batteries for electricity storage, a salt cavern for hydrogen storage and cryogenic tanks for nitrogen storage, the system is designed to work as flexible as possible to cope with the variations in PV output.

Scaled to an industrial scale output of 200.000 ton-NH3 per year, the resulting LCOH in 2030 will be 1.63 €/kg-H2, and the LCOA will be 0.394 €/kg-NH3. The competitiveness with fossil fuel-based production is dependent on the price of natural gas, which in this case will need to be higher than 3.16 $/MBTu or 12.25 €/MWh (converted using a USD/EUR rate of 0.88 and a conversion factor of 0.29308 MWh/MBTU, and taking into account a carbon price of 100 €/ton-CO2-eq) for green hydrogen to be competitive. For green ammonia to be cheaper, the gas price must be greater than 4.49 $/MBTu or 17.41 €/MWh.

A sensitivity analysis shows that if the CAPEX and OPEX cost of the five most contributing components to the levelized cost would be 50% higher, the LCOH (2.4770 €/kg-H2) and LCOA (0.5817 €/kg-NH3) would still compare favourably to blue hydrogen and ammonia with a natural gas price of 7.71 $/MBTu (29.89 €/MWh) and 9.04 $/MBTu (35.05 €/MWh). By analyzing the operations of the salt cavern, it is discovered that 6.4% of the salt cavern is used from the available capacity of 3300 ton-H2. Even when the necessary yearly output of ammonia is raised 2 or 4 times, the salt cavern uses only 12.7% and 16.8% of the available capacity. Overall this research shows that green hydrogen and ammonia can compete with hydrogen and ammonia produced from fossil fuels in 2030 and that the possibilities of salt cavern storage for hydrogen are greater than expected because a capacity of 250 ton-H2 is enough for a yearly production of 200.000 ton NH3.

Implementing green alternatives in the heavy­-duty mobility market is required to reach the set climate goals of 2050 and decrease greenhouse gas emissions. Refuelling infrastructures based on alternative fuels such as hydrogen are not sufficiently available. This poses a barrier to large scale implementation and investment in new emission­ free heavy-­duty fuel cell vehicles.

Early market value chain configurations and low refuelling station demand levels are researched and evaluated to determine the optimal future strategy decision based on operational decision-making results. A Mixed Integer Linear Programming (MILP) optimisation model is adopted to simulate a small scale hydrogen value chain dominated by hydrogen production directly from wind energy at the wind turbine location. Additionally, a method is proposed to define future demand for two separate end-­user categories at a hydrogen refuelling station. The spatial configuration of the researched infrastructure is based on a ”Hub” and ”Satellite” concept with distributed production locations and demand locations.

With the current market pricing of all value chain components, cost parity with diesel fuel is reached if the total production capacity of the value chain is utilised. Future cost development will result in a lower total cost for hydrogen per kg than the diesel fuel equivalent. The hydrogen refuelling infrastructure based on wind energy is resilient against increased energy price fluctuations by an expected increase in the installed capacity of renewable energy sources. The operational decision ­making process regarding the hydrogen production process is generally independent of the distribution system size, spatial configuration, and type of non­-stationary storage container, taking into account similar demand within a specified time frame. The hydrogen infrastructure project of DUWAAL by HYGRO is used as a basis for the research.

The Hydrogen Heating Studies project in the Green Village at the TU Delft researches the safe application of hydrogen to heat buildings. This study aims to evaluate hydrogen sensor technologies for residential safety, including the determination of the sensor location inside a standard (Dutch) metering cabinet that achieves the fastest response to potentially dangerous leakages of hydrogen gas.
A range of commercially available sensor technologies was assessed to determine their suitability in residential applications. From this analysis on multiple criteria, the thermal conductivity sensors outperformed the other sensor technologies, albeit only by a small margin versus catalytic hydrogen sensors. Furthermore, an experimental study has been carried out by locating seven sensors at different locations inside the metering cabinet. The hydrogen concentrations have been measured in seven different conditions (case studies). It was found that sensors located at the top of the metering cabinet showed the highest concentrations, more specifically, the top-center.
The results of this research also confirmed that the condition of closed ventilation leads to a constant increase of hydrogen concentration in the metering cabinet. This has implications for managing the risks associated with high hydrogen concentration levels because of hydrogen leakage. Air ventilation inside the metering cabinet causes changes in the distribution mechanism, resulting in mixing and distribution of the hydrogen, reducing hydrogen concentrations. With open ventilation, the hydrogen concentration levels to trigger the alarm inside the metering cabinet should be lowered. Based on the results, it is advised to set the alarm to trigger when hydrogen concentration levels reach 5 %LEL. It was also found that, compared to methane, the release of hydrogen gas leads to a more buoyant gas mixture which mixes more easily with the air and rises three times quicker toward the ceiling. Finally, further research on worst-case scenarios is relevant to make specific recommendations for safe and economically feasible residential heating appliances.

In order to reach the climate goals the use of fossil fuels needs to decrease and green solution need to provide the energy of the future. Wind and solar will probably supply a large fraction of our electrical power need in the future. Because of the nature of these sources the demand for electrical power will not always be balanced with the supply. Industrial companies are responsible for a large portion of the total greenhouse emissions. Some of the emissions are process related, but most are due to the demand for high temperatures in the process. Today fossil fuels like coal and gas are used to achieve these high temperatures. Hydrogen provides a solution for the problems as it can be used as a storage medium and as an energy source to achieve high temperatures. In order to provide the world with sufficient hydrogen needed for the transformation to greener solu­ tions the production of hydrogen needs to increase. Hydrogen can be made from fossil fuels, but to achieve our goals the production of green hydrogen is needed. Green hydrogen is made using green electricity and the electrolysis process. In this thesis the alkaline electrolysis process is reviewed. During the production of hydrogen using the alkaline electrolysis process, a large fraction of the electri­ cal energy is converted to thermal energy. The aim of this research is to gain insight into the possibility of extracting the thermal energy form the process so it can be used in a district heating network. Based on the thermal demand form the heating district and the power supply to the hydrogen plant four case studies are evaluated. Using a pinch analysis, a process flow diagram is designed for each case study after which every design is modelled. Using a heat pump and thermal storage the supply of thermal energy and the demand from the district heating network are balanced in order to reach a high overall efficiency.

The North Sea has significant potential in becoming a green energy hub, due to its remarkable offshore wind potential, and could therefore facilitate the energy transition to a net-zero energy system in Europe in the coming decades. In this transition, hydrogen is also predicted to play a key role, due to its ability to transport and store substantial amounts of energy. Previous studies have shown that for large offshore wind capacities and substantial distances from the shore, transporting the produced energy in the form of molecules (converting the electricity to hydrogen) via dedicated pipelines would be a more cost-effective option than using electricity cables and converting electricity to hydrogen. This transport could be achieved by developing new hydrogen-dedicated infrastructure or reusing existing natural gas pipelines, which is a cost-effective alternative.

This research study aims to determine the potential for repurposing existing gas infrastructure in the North Sea for hydrogen transport, taking into consideration that this infrastructure will still have to transport natural gas to the shore over the coming years. Redirecting an amount of this natural gas to other, neighboring pipelines creates the possibility for existing pipelines to be freed up for hydrogen transportation, and therefore achieve parallel transmission of green hydrogen and natural gas from the Dutch North Sea to the shore. Consequently, the purpose of this thesis project is to examine the geographical, technical, and economic feasibility of large-scale green hydrogen transportation (produced offshore with green energy from wind turbines), with parallel natural gas transport, via new and already existing gas infrastructure in the North Sea, by 2030.

The first aspect to be analyzed was the geographical configuration of such a system. For that purpose, different possible configurations for parallel transport of hydrogen and natural gas via existing North Sea infrastructure were examined. This analysis indicated that the most suitable scenario, considering the projected timeline and current circumstances, would be repurposing the NGT pipeline for 100% hydrogen transportation (produced from offshore wind search areas 7 and 3), and rerouting the natural gas to the NOGAT pipeline. Both NGT and NOGAT pipelines are parts of the North Sea offshore pipeline system, currently transporting natural gas to the Dutch shore. The next part of the study concerned the physical configuration of the hydrogen transportation system. A component analysis was done, highlighting the most suitable components across the entire system configuration, including the offshore hydrogen production by water electrolysis, its compression, and its transportation via the NGT pipeline among others.

Furthermore, a more elaborate analysis was done to determine the project’s technical feasibility, with emphasis being placed on the key aspects of hydrogen compression and transportation, evaluating its flow characteristics and compression requirements. The analysis results showed that transporting hydrogen via the NGT pipeline to the Dutch shore is technically feasible. Based on the analyzed scenario, the maximum hydrogen transport capacity was found to be 7.9 GW, and the total compression capacity 103 MW. During its transportation along the length of the pipeline (253 km), hydrogen experiences a pressure drop of 10.4 bar (65 bar to 55 bar). An economic evaluation of the system was also performed, indicating that the project is feasible from a financial standpoint as well. The LCOH transport for the proposed system, including hydrogen compression and NGT pipeline repurposing costs, was found to be 0.17 €/kg/1000km. The overall conclusion of this study is that reusing existing infrastructure in the North Sea for hydrogen transportation is a physically and technically feasible option, which can be achieved at a competitive cost.

The vast amounts of greenhouse gas (GHG) emissions, surging gas prices, and increasing proportion of intermittent energy sources force the energy sector to structurally modify the energy system. The reversible Solid Oxide Cell (rSOC) is considered to be part of the solution due to its high efficiency, good scalability, and ability to balance the energy grid. The rSOC is a high-temperature, electrochemical device that can convert both power-to-gas and gas-to-power during its Solid Oxide Fuel Cell (SOFC) and Solid Oxide Electrolysis Cell (SOEC) modes. The integration of the SOFC with a combined cycle gas turbine (CCGT) features exceptional synergies. Although the synergies of the SOFC and CCGT have already been widely reviewed, the combination of an rSOC and a CCGT has remained unexplored.

The research objective of this study is to assess the benefits of retrofitting an rSOC to an existing CCGT by simulating its exegetic performance, relative GHG emissions and gross profit, and comparing these results to those of an existing CCGT. During the integration of the rSOC (operating in SOFC mode) with the CCGT, the performance of the reversed SOEC mode must be taken into account because it will have to operate with the same operating conditions and the same system components. In order to decrease the system investment cost, this work examines to what extent the rSOC can be retrofitted into the currently deployed CCGTs.

This research optimizes the process plant design and scrutinizes the effect of various operating conditions on the system performance. The optimization is performed through exergy analyses of a zero-dimensional Aspen Plus model. A case study, in which the proposed system is inserted into an energy resource allocation model of the Amsterdam metropolitan area, is used to examine the gross profit of the proposed multi-energy system.

The optimization of the SOFC-CCGT system results in an exergy efficiency of 61.5%, generating 518 MWe, which enhances the performance of the existing CCGT by 3.8% and decreases the GHG emissions [CO2e t/MWh] by 21.3%. When the combined heat and power (CHP) mode of the CCGT is considered, the resulting SOFC-CCGT CHP system achieves an exergy efficiency of 61.2%, while generating 474 MWe and 103 MWth. The SOFC-CCGT CHP outperforms the exergy efficiency of the original CCGT CHP with 4.2%, while emitting 13.2% less GHG emissions. The same operating conditions of the SOFC were applied to the SOEC, which manages to operate with an exergy efficiency of 84.3%.

Implementing the rSOC-CCGT CHP system into the energy resource allocation model results in a 118% increased net present value (NPV) of the gross profit compared to the original CCGT. The proposed multi-energy system is able to adjust its operating mode to anticipate the price variations in the energy grid and thereby increases the gross profit. Adding a thermal energy storage system decouples the consumption and production of heat, which enhances the NPV of the gross profit by an additional 1.4%.

Vopak has the vision to become climate neutral by 2050 (Scope 1 and 2 emissions). Currently, over 99% of its CO2 emissions originate from storage terminal activities. Action must be taken to reduce these emissions by converting the current (fossil fuel-based) generation of electricity to sustainable energy.

This study aims to research how we can develop a methodology to evaluate the cost-effectiveness of an autonomous solar and storage system to electrify Vopak’s storage terminals? The objective of the method is to develop a system that is clean, reliable, autonomous, and payable (cheap). The selected autonomous system comprises a photovoltaic (PV) system, a battery energy storage system (BESS) and a hybrid inverter to satisfy the energy load of the storage terminal.

The developed method is a techno-economic model using three interlinked components. First, a PV model uses meteorological data and specific technical characteristics to simulate different PV systems. Second, based on the cost of different components of the PV system and BESS, a grid-search system selection method is used to determine the lowest-cost sizing of an autonomous PV and battery
system. Third, the sizing of the system is used to calculate the levelized cost of solar plus storage (LCOSS).

The method is evaluated for three selected storage terminals located in different climates. The lowest cost developed system for Vopak Fujairah Horizon terminal (desert climate), which has a LCOSS of 0.33 [$/kWh]. For Vopak Terminal Laurenshaven (maritime climate), a LCOSS of 0.96 [$/kWh] is calculated. Vopak Panama (tropical climate) has a designed system with a LCOSS of 0.53 [$/kWh]. The calculated LCOSS shows that these autonomous systems are not cost-effective, as they are 3 to 14 times more expensive than average energy prices from the grid for the storage terminal locations. A sensitivity analysis of the system costs and the weighted average cost of capital shows that a 50% decrease in battery costs results in a 38% decrease in the LCOSS. Furthermore, a decrease of 2% of the WACC has the same effect as a total system cost reduction of 10%–15%. Ultimately, enabling the system to
use its dumped energy by selling it to the grid shows the most significant reduction in the LCOSS.

This study clarifies that the cost-effectiveness of an autonomous PV and battery system strongly depends on the climate and seasonal variation of the location as it affects the energy yield of the PV-generating technology and the sizing of the system. Furthermore, the battery system costs are currently two to three times more expensive than a PV system; therefore, to size the lowest-cost system, the sizing strategy rather increases the (cheaper) PV system size to satisfy the load than install an additional battery. This results in oversized PV systems generating a large amount of unused energy. A solution is to enable the system to sell its unused electricity to the grid. An alternative solution would be to add a secondary “clean” energy source, such as a hydrogen generator, to combat these oversized systems and thus reduce the lifetime system costs.

The maritime sector plays an important role in energy transition because offshore vessels are used for building offshore renewables but also have high emissions. The European Union (EU) has determined that from 2025 the maritime sector must pay per ton of CO2 emission. Heerema Marine Contractors (HMC) is an essential player in the maritime sector and plans to have reduced its emissions by 50% by 2025. This thesis aims to build a model in which different emission-abating options can be compared on financial and technical aspects to determine the best roadmap to achieve sustainability.
To do this properly, literature research is done on emissions-abating fuels and technologies/processes applicable to offshore crane vessels. Five sub-questions are answered to find an answer to the main research question:
What will be the future energy configuration of the Heerema fleet and the most technical and financial feasible roadmap to meet the sustainability goals look like?

• What are an offshore crane vessel's main operational energy-consuming modes?

• Which fuel switches and blends are technically and financially feasible, and what are the key characteristics of these fuels?

• What are the key characteristics of the ship-based emission-abating technologies like batteries and carbon capture and storage?

• What are the current vessel-specific levelized cost of Energy (LCOE) and levelized cost of carbon abatement (LCoCA) of the fuel switches and technologies, and how are they expected to develop over time?

• Which emission-abating future scenarios are technically and financially feasible, and how will these sustainable roadmaps look?

With the evaluation of the answers to these sub-questions, the importance of using hydrotreated vegetable oil (HVO) is shown until e-fuels are available. From 2026 e-fuels are assumed to be wide available for usage on board the three vessels, the Sleipnir, Aegir and Thialf the vessels within the scope. The financial evaluation of the e-fuels is in favour of ammonia. The technical evaluation is based on the limited available storage volume favour for methanol.
These findings result in a roadmap using batteries on board the vessels together with HVO as fuel and when available installing designated ammonia or methanol tanks, and using ammonia or methanol as a 100% fuel blend in the internal combustion engines of the three vessels.

Since the European Commission concluded that green hydrogen is a key priority in the achievement of Europe’s energy transition, hydrogen is included in transition strategies of many parties. The Netherlands has the ambition to become the European leader of hydrogen deployment within their strategy. The oversea import of hydrogen is highly needed in the future, as it is expected that NW-Europe does not have sufficient renewable energy sources to locally produce the entire hydrogen demand. Due to the extensive gas network and distribution infrastructure, the strategic location of Rotterdam has the potential to become the new hydrogen energy import hub of Europe. As Vopak, world’s leading independent tank storage company, sees opportunities in the large scale import and storage of hydrogen, an evaluation of the entire green liquid hydrogen supply chain is done. In this paper, an evaluation of the green liquid hydrogen supply chain is presented. The literature review of the individual elements led to the construction of the supply chain existing of the consecutive elements: renewable energy generation, electrolyser technology, liquefaction plant, onshore storage, oversea shipping, onshore storage, distribution of hydrogen and consumption by end-users. Within this supply chain, liquid
hydrogen is taken into account due to its favorable volumetric density of 70.8kg/m3. This results in the handling and storage of hydrogen at cryogenic conditions: 20K at a pressure of 1.1 bar. The scope of the project is determined to be from the liquefaction plant to the distribution of the hydrogen into the different transportation modes on the importing terminal. A technical and economic model is created in order to analyse different throughput scenarios. These scenarios transport the hydrogen from a country X in which abundant renewable feedstocks are expected to be produced to the importing location of Rotterdam. By creating and merging a technical and economic model, an in-depth research is conducted. The model determines optimized configurations and their sensitivity for certain throughput scenarios. The technical research led to the following findings: 1. The storage tank has an expected maximal spherical capacity of 40 000m3 with an according BOR of 0.043%/day. If higher capacities are required, the shape
of the tank shifts towards cylindrical structures, due to the vacuum insulation technique. Whenever this capacity is increased, the currently used technology of vacuum MLI is expected to shift towards membrane technology. This is due to that vacuum insulation is not applicable to flat surfaces unless a very thick inner wall is constructed. The exact technology and according BOR of membrane technology is highly proprietary. 2. The liquefaction plant is a mature technology of which the capacity can be easily increased. The current largest plant capacities can be increased from 50tpd to 500tpd, due to easily transportable cold boxes. The current energy consumption of 8kWh/kg can presumably decreased to around 6kWh/kg. Although the minimum capacity of a plant is 20%, the energy consumption is heavily affected. 3. The first oversea LH2 vessel, with a capacity of 1250m3, is currently in its sea trials. Concept designs and interviews led to the perspective that a LH2 vessel of 100 000m3 can be expected in the year 2030. 4. The BOP systems do not exist on industrial scale. Although the handling systems do not exist, the transfer loss during a transfer of a parcel is estimated to be 1.5%. 5. The energy consumption throughout the supply chain shows that the liquefaction plant plays a dominant role. The second most energy intensive process is the oversea shipping. The economic simulations led to the following findings: 1. The LCOH in Rotterdam can decrease to 2.78USD/ kg when a throughput scenario of 3.5Mt/year from the location of Saudi Arabia is realised. 2. The competitiveness tipping point (3.15USD/kg) from the location of Morocco and Saudi Arabia is around 0.35Mt/year. 3. Australia does not reach an economically attractive liquid hydrogen oversea supply chain to Europe, unless the demand highly increases. 4. In small throughput scenarios the storage tank has the most dominant impact on the LCOH. This is due to that the liquefaction plant and ship are scalable to a single unit, while the storage tank has a minimum of three tanks per terminal. The combination of the technical and economic results led to an overall conclusion that a green liquid hydrogen supply chain is economically competitive at a throughput scenario of 0.31Mt/year from Morocco. Although the technical elements within this scenario are currently still in concept phase, expectations look very promising and can be deployed by 2030. Further BOP and handling systems are not yet commercially available, similar expectations are set for the year 2030. Whenever the hydrogen demand in NW-Europe increases, an acceleration of the oversea hydrogen deployment is established. Therefore further research needs to keep a close eye on the technical development of the supply chain.

This thesis aims to analyze the techno-economic feasibility of integrating a salt cavern storage system into a green hydrogen production system in the Dutch North Sea, with the objective to provide a constant green hydrogen supply to the industry sector. To this end, the potential for creating salt caverns in the North Sea was examined and the prospected theoretical storage capacity was evaluated and compared to the required storage capacity and the costs of the system were assessed.

The simulations reveal that a 19.8 GW wind park in combination with an 8.65 TWh salt cavern storage system would be sufficient to provide a constant hydrogen supply to a 10 GW pipeline. Four locations in the Dutch North Sea were identified where a group of adjacent salt caverns could be created with a collective storage capacity of at least the required 8.65 TWh. Although further research is required, from this analysis it is concluded that creating a salt cavern storage system of sufficient magnitude may indeed be technically feasible.

The incremental cost of adding to offshore hydrogen production an 8.65 TWh salt cavern storage system is estimated at €5.4 billion, which translates to an addition of 0.17 €/kg to the LCOH for offshore green hydrogen production. Optimization of system design and the financial state of affairs may reduce costs for the storage system and thereby the total LCOH for offshore hydrogen production and storage.

Hydrogen offers opportunities to develop a sustainable energy system and is essential to support the EU’s commitment to reaching carbon neutrality by 2050. Hydrogen is a solution for heavy transport sectors that struggle to reduce emissions by direct electrification, such as the Dutch inland waterway transport (IWT) sector. However, the lack of economic viability is one of the most dominant challenges for hydrogen, which calls for a tailored and sectoral policy approach that considers the dynamics involved in the IWT sector. This study simulates the decision-making process of active ships in the Netherlands based on the economic trade-off between diesel- and hydrogenpowered drivetrains to identify policy measures that would catalyze the sector’s hydrogen transition.

In the simulated base scenario, NOx, PM, and CO2 emission targets are not met. Economic policies must contribute to the realization of these emission targets. Here, quantity-based economic instruments are preferred over price-based economic. Quantity-based economic instruments ensure that emission targets are realized virtually, while the effect of price-based economic instruments is subject to uncertainties related to cost developments, for instance. The introduction of a Renewable Energy (HBE) obligation and the inclusion of the IWT sector in the Emission Trading Scheme (ETS) are effective quantity-based economic instruments. When implementing both these instruments, policymakers must prevent double burdening of the IWT sector.

When introducing an HBE obligation, obligation levels must be set in accordance with the emission goals and a multiplier for hydrogen is recommended to create a level playing field with other renewable fuels. To include the IWT sector in the ETS, the minimum tonnage condition for ships must be removed. In addition to these policies, subsidies must be provided on the large capital investments for hydrogen to compensate for the higher marginal abatement cost in the IWT sector and create a level playing field with other transport modes, countries and fuels. Besides economic policies, the development of relevant regulation and bunkering infrastructure is a prerequisite for the hydrogen transition in the IWT sector.

This research mainly focused on a techno-economic trade-off between hydrogen- and diesel-powered drivetrains. Future research could focus on additional (qualitative) criteria in the decision-making process, such as upcoming legislation, safety, and (bunkering) infrastructure availability.

The electricity grid in the Netherlands is currently unable to provide sufficient capacity for both the integration of new renewable electricity powerplants as well as for the integration of new electricity demands like electric vehicle charging. Symptoms of this scarcity of capacity, also seen in other countries undergoing an energy transition, are observed in various forms.

On the generation side, newly planned solar photovoltaic projects at both commercial and residential scales are increasingly being denied permission to connect to the grid or face long delays for grid reinforcement before they are connected. Since 2020, new utility-scale solar Photovoltaic (PV) installations were provided a maximum of 70% grid connection capacity relative to the solar installed capacity. In 2022, this permitted grid connection capacity has been further lowered to 50% for new projects larger than 1 MWp.

On the demand side, recent mapping studies by the Dutch grid operators show that a majority of the country faces structural congestion in the distribution and transmission grids. The Dutch ambition, as stated in the Regional Energy Strategy (RES), is to integrate 12 GWp of additional solar installed capacity to the existing 14 GWp by 2030. Also by 2030, the total number of Electric Vehicles (EVs) in the Netherlands is expected to increase from about 390,000 (4.4% of the total Dutch passenger vehicle fleet) today to about 1 million (10%), increasing the peak electricity demand.

The scarcity of capacity in the electricity grid to integrate both low carbon solar generation and electric vehicle charging presents an obstacle to the realisation of both short and long term emissions targets. Even though significant grid expansion is already planned and commissioned, this scarcity of capacity is expected to be a characteristic feature of the electricity grid over the coming decades. This thesis aims to investigate how the coupling of solar carparks and EV charging can enable their integration in a grid with scarce capacity while lowering operational carbon emissions.

Two configurations of solar carparks for EV charging are analysed, with the aim of reducing the grid capacity needed:

Chapter 3 analyses the first configuration: a solar carpark for charging EVs at a workplace in the Netherlands where demand peaks are caused by the simultaneous charging of EVs. The inclusion of EV demand forecasting within the scheduled charging reduces annual peak EV charging power by 36-39% relative to immediate charging. These reductions in peak demand enable a more effective use of the available power capacity (now mandated to 50% of solar installed capacity) as well as increase the utilisation of generated solar energy by reducing the need for solar curtailment.

Chapter 4 investigates the second configuration: an off-grid solar carpark for EV charging at a long term (>24 hours) parking lot in a Dutch airport. Offgrid solar charging would enable rapid planning of charging facilities for EVs, removing the uncertainty, delays and costs associated with a grid connection. However, these benefits come with a trade-off: not all vehicles are fully charged at the time of departure. With immediate charging, 20% of EVs over the year leave with a state-of-charge lower than 60% and 3% of EVs leave with a state-of-charge lower than 40%. The adequacy of fleet-level charging is lowest during the low irradiance month of December, during which 63% of vehicles leave with a state-of-charge lower than 60% and 11% of vehicles leave with a state-of-charge lower than 40%. Prioritising the charging of plugged-in vehicles with the lowest state-of-charge ensures that no vehicles leave with a state-of-charge lower than 40% over the entire year, even in the low irradiance winter months. Increasing the minimum duration of parking reduces the fraction of vehicles leaving with state-of-charge below 60% by about 2% per day.

The consequences of scheduled charging on greenhouse gas emissions are investigated in Chapters 5 and 6: Chapter 5 analyses a recently constructed solar carpark located in Dronten, the Netherlands, which includes a solar array, a nickel metal hydride battery and charge points for electric vehicle charging. The aim of the study is to quantify the magnitude of offset carbon emissions per year by the solar carport, and the contribution of battery storage to this offset. The prevalent practice of using the annual average carbon intensity is found to be unsuitable for estimating the annual offset carbon emissions since it does not account for the intra-day patterns of solar production, EV charging and battery cycling. To overcome this, we propose a novel method to calculate the annual offset carbon emissions, making use of the hourly average and hourly marginal carbon intensity. The choice of approach is found to make a difference to the calculated values of the annual offset emissions of the solar carpark. The use of hourly average carbon intensity, which takes into account variation in production, generation and storage, leads to a higher calculated value of annual offset carbon emissions by about 7% relative to a method using the annual average carbon intensity. The use of the hourly marginal carbon intensity to calculate the annual offset carbon emissions suggests that solar carparks have about a 55% higher incremental effect on the carbon intensity associated with the new load of EV charging than what is conventionally calculated. When comparing the annual offset carbon emissions from the solar carpark with and without a battery, we find that the use of the battery has a negligible effect on the annual carbon offset by the system. This result is found to be robust across all the methods of calculation. We therefore conclude that the use of batteries in solar carparks have a low contribution to the total carbon offset by the solar carport.

Chapter 6 investigates the effect of price-based scheduling of EV charging on the carbon intensity of the electricity used by a scheduled fleet of EVs. Real data of over 55,000 home charging sessions collected from 1031 charge points in the Netherlands is analysed. A simulation is made with a commercial smart charging algorithm to create a scheduled charging profile ex post from the EV charging data set. The profile results in an average price reduction of 25% for the overall fleet relative to the costs for unscheduled charging of the fleet over the same period. The time dependent hourly carbon intensity of electricity consumed in the Dutch low voltage grid in 2018 is used to find the impact of price-based scheduling on the mean carbon intensity of electricity used by the fleet. A small decrease of 1.2% in carbon intensity used by the entire EV fleet is observed over the year. Although price optimisation has large effects on the carbon intensity in individual sessions, the effect is found to balance out over the large number of sessions in the year.

Chapter 7 investigates the factors affecting the consumer acceptance of Vehicle-to-Grid (V2G) charging, which remains an insufficiently investigated barrier for the use of the full potential of EVs in demand response and storage. The research work comprises two stages of semi-structured interviews: the first with EV drivers who have never experienced V2G charging, and the second with EV drivers who experienced V2G charging. The participants in the second stage are given access to a V2G-compatible Nissan LEAF and the V2G charging facilities set up in a living lab on the University campus for at least a week each, after which they are interviewed. Clear communication of the battery impacts, financial compensation and operational control are all found to foster acceptance and were, in many cases, necessary conditions for acceptance. The main barriers for acceptance found are range anxiety in various forms, concerns about the effects of V2G charging on the EV battery and the perceived loss of freedom associated with private vehicles. A majority of participants interviewed from both groups are found to accept or conditionally accept V2G charging. This suggests that the use of EVs for demand side storage in addition to demand response is already acceptable to a subset of current EV drivers. The study also clarifies the conditions under which V2G charging would be more acceptable to a broader group of EV users.

The results obtained in this thesis show that the coupling of solar photovoltaics and EV charging enables the integration of both in a grid with scarce capacity. We therefore recommend that solar carparks for EV charging be more widely implemented at workplaces and at longterm (>24 hour) parking lots, though without stationary batteries.

Most nations have agreed to limit the emission of greenhouse gases within the Paris Agreement. The agreement relies on the assumption that all participating nations have accurate means of estimating carbon emissions and offsets accurately. However, global carbon emission accounting methodologies lack accuracy in approach and required carbon intensity data of utility grid electricity. From this, a need for developing a standardized accurate carbon emissions assessment methodology arises. The aim of this research is to develop an accurate carbon offset assessment methodology and determine the effect of using marginal, hourly average and annual average emission factors. The methodology is applied to a solar carport system in the Netherlands, consisting of a 465 kWp solar PV system, a 345 kWh nickel metal hydride battery and 16 DC charge points for EVs, in order to quantify the emission offset potential of the respective system components. This research presents a comprehensive literature review of existing carbon accounting methodologies based on which a new accurate methodology to calculate carbon offsets is developed. This methodology uses marginal emission factors from observed power dispatch and computes offsets on an hourly timestep. Application of marginal emission factor results in a 30 % and 23 % increase in carbon offset compared to hourly average emission factors and annual average emission factors, respectively. The carbon offset attributed to the battery system is roughly 100 kg CO2eq annually in 2019 and 1.5 -1.7 tons CO2eq in 2030. Relative to the lifecycle emissions caused by the battery system of about 200 tons CO2eq, including the battery system is not beneficial in terms of mitigating carbon emissions in solar carport applications. 99.96 % of the total offset is attributed to the solar PV system and lifecycle emissions of the solar carport can be mitigated after operation of 1.5 years when excluding the battery. Including the battery, lifecycle emissions are mitigated after 2 years and 3 months. To conclude, the results show that using marginal emission factors results in significant impact on the assessment results and are conceptually more accurate. Hence, they should be applied for carbon offset studies. Additionally, the carbon offset potential of the PV system is high while the contribution of the battery is low and installation of battery systems at solar carports is, therefore, not recommended.

The energy transition, is one of the most important topics nowadays. Renewable energy sources contribution in the energy mix is growing rapidly. However, due to their intermittent power output, they cannot ensure system security and stability, and therefore, energy storage technologies are needed. In this direction, hydrogen is an energy carrier with great potential. When produced from water electrolysis based on electricity from renewable energy sources (green hydrogen), it represents a sustainable fuel. Due to that, industry’s interest is turn on green hydrogen production, with several large scale projects announced on a daily basis. In many countries, especially in Europe, there is not enough empty land for large scale renewable energy projects, turning the interest to offshore areas. This research aims to design and analyse the economic feasibility of an offshore hydrogen production system, intending for 2030, based on offshore solar energy,
located in Greece, for the production of a million tons of hydrogen per year. The
produced hydrogen will be injected into the European hydrogen network. Considering the main components of an offshore solar to hydrogen system, four possible system configurations are proposed based on two parameters for comparison. The first parameter for examination is the electrolyzer type, which can be either alkaline or PEM. The second parameter is the involvement of batteries into the system. The sizing and cost details about the different systems were selected and all the configurations were modelled using Matlab and Simulink software. From the model results, the levelized cost of hydrogen
for all the systems was calculated to evaluate the project. The most cost-effective
configuration was the one based on alkaline electrolyzer and without the involvement of batteries. The levelized cost of hydrogen for the selected
onfiguration was calculated to be 1.5 €/kg of hydrogen, making it comparable with blue hydrogen costs and with green hydrogen costs of relevant announced projects. A sensitivity analysis showed that the most influencing factor in the cost calculation is the capital expenditure of the floating photovoltaic system. More specifically, by decreasing the floating photovoltaic costs by 30%, the levelized cost of hydrogen can be reduced by 19%. Finally, in an optimistic scenario,
where all influencing factors are improved by 20%, hydrogen can be produced at
a cost slightly higher than 1 €/kg. Overall, it is concluded that an offshore hydrogen production system based on offshore floating solar energy, located in Greece, northern to Crete, can produce hydrogen at a competitive cost.